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EPA's Responses to Public Comments on EPA's National Emission

Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric 

Utility Steam Generating Units

Volume 2 of 2

Comments, letters, and transcripts of the public hearings are also available electronically through

http://www.regulations.gov by searching Docket ID EPA-HQ-OAR-2009-0234.
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FOREWORD

This document provides the EPA’s responses to public comments on the EPA’s Proposed National 

Emission Standards for Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility Steam 

Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units. The 

EPA published a Notice of Proposed Rulemaking in the Federal Register on May 3, 2011, at 76 FR 

24976. The EPA received comments on this proposed rule via mail, e-mail, facsimile, and at three public 

hearings held in Chicago, Illinois; Atlanta, Georgia; and Philadelphia, Pennsylvania, in May 2011. 

Copies of all comments submitted and transcripts for the public hearings are available at the EPA 

Docket Center Public Reading Room. Comments, letters, and transcripts of the public hearings are also 

available electronically through http://www.regulations.gov by searching Docket IDs EPA-HQ-OAR2009-0234 (NESHAP action) and EPA-HQ-OAR-2011-0044 (NSPS action). 

This document contains responses to comments on the NESHAP only; responses to comments on the

NSPS action are in a separate Response to Comments document. Due to the size and scope of this 

rulemaking, the EPA summarized a limited amount of major comments in the preamble of the final rule. 

This document contains a summary of all significant comments provided by each commenter extracted 

from the original letter or public hearing transcript.

Appendix A of this document provides a list of public hearing speakers and their affiliation. Appendix B

of this document provides a list of commenters and their affiliation along with the associated document 

control number (DCN). For each comment, the DCN is provided along with the comment summary. For 

purposes of this document, the text within the comment summaries was provided by the commenter(s) 

and represents their opinion(s), regardless of whether the summary specifically indicates that the 

statement is from a commenter(s) (e.g., “The commenter states” or “The commenters assert”). The 

comment summaries do not represent the EPA’s opinion unless the response to the comment specifically

agrees with all or a portion of the comment. In some cases the same comment was submitted by two or 

more commenters through submittal of a form letter prepared by an organization, by the commenter 

incorporating by reference the comments in another comment letter, or by the commenter providing 

identical or similar language independently. Rather than repeat these comment excerpts for each 

commenter, the EPA has listed the comment excerpt only once and provided a list of all the commenters 

who submitted the same form letter or otherwise incorporated the comments by reference in Tables 9A1 through 9A-21 and 9B-1 through 9B-5 of section 9 of this document and Table 10-1 of section 10 of 

this document, respectively.

Several of the EPA’s responses to comments are provided immediately following each comment 

summary. However, in instances where several commenters raised similar or related issues, the EPA has 

grouped these comments together and provided a single response after the last comment summary in the 

group. In some cases, the EPA provided responses to specific comments or groups of similar comments 

in the preamble to the final rulemaking. Rather than repeating those responses in this document, the EPA 

has referenced the preamble or the appropriate technical support document for a description of the 

analysis included in the final rule.

As both the NESHAP and NSPS actions were included in the same proposal package, many commenters 

submitted comments to this rulemaking docket that were specific to the NSPS action. Some commenters 

submitted a single DCN with comments on both rules, while others submitted a separate DCN specific 

to each action. Many commenters submitted identical comments to both dockets. In order to reduce 

duplicative comments, we have removed from this document comments associated with the NSPS 
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action. For this reason, the EPA encourages the public to read the Response to Comment document 

prepared for the NSPS action.
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TABLE OF CONTENTS

CHAPTER CHAPTER 5: COMPLIANCE WITH TESTING /MONITORING/ 

RECORDKEEPING AND REPORTING

5A - Testing/Monitoring

5B - Recordkeeping/Reporting

5C – Compliance

CHAPTER 6: IMPACTS AND COST ANALYSIS

6A – Impacts/Costs: Emission Impacts

6B – Impacts/Costs: Emission Reductions

6C – Impacts/Costs: Energy Impacts

6D – Secondary Impacts

6E - Impacts/Costs: Compliance Costs

6F – Control Technology Cost Assumptions

6G - Impacts/Costs: Testing and Monitoring Cost Assumptions

6H - Impacts/Costs: Projection of New Units

6I - Impacts/Costs: Economic Impacts/Employment Impacts

6J - Impacts/Costs: Social Costs

6K - Impacts/Costs: Health Co-Benefits

6L - Impacts/Costs: Mercury Benefits

6M - Impacts and Costs: Air quality co-benefits modeling

6N - Impacts/Costs: Other/Miscellaneous

CHAPTER 7: STATUTORY AND EXECUTIVE ORDERS

7A - Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, 

Improving Regulation and Regulatory Review

7B - Paperwork Reduction Act

7C - Regulatory Flexibility Act (RFA), as Amended by the Small Business Regulatory 

Enforcement Fairness Act of 1996 (SBREFA)

7D - Unfunded Mandates Reform Act of 1995

7E - Executive Order 13132, Federalism

7F - Executive Order 13175, Consultation and Coordination with Indian Tribal Governments

7G - Executive Order 13045, Protection of Children From Environmental Health Risks and Safety 

Risks

7H – Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy 

Supply, Distribution or Use

7I - National Technology Transfer and Advancement Act

7J - Executive Order 12898, Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations

7K - Statutory and Executive Orders: Other

CHAPTER 8: RULE LANGUAGE CORRECTIONS

8A - Rule: Definitions (existing)

8B - Rule: Definitions (new)

8C - Rule: Corrections to tables

8D - Rule: Language

8E - Rule: Other Language Corrections
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CHAPTER 9: GENERAL SUPPORT AND GENERAL OPPOSITION

9A - General Support

9B - General Opposition

CHAPTER 10: INCORPORATION BY REFERENCE

APPENDIX A: PUBLIC HEARING PARTICIPANTS

APPENDIX B: LIST OF COMMENTERS
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CHAPTER 5: COMPLIANCE WITH TESTING/MONITORING/RECORDKEEPING

AND REPORTING

5A01 - Testing/Monitoring: Stack Test Methods

Commenters: 17174, 17191, 17402, 17621, 17623, 17675, 17681, 17696, 17716, 17725, 17729, 17730, 

17731, 17747, 17754, 17758, 17767, 17770, 17775, 17790, 17795, 17800, 17807, 17808, 17820, 17821, 

17868, 17877, 17878, 17880, 17881, 17975, 18014, 18015, 18021, 18025, 18034, 18428, 18498, 18539, 

18935, 18963, 19033, 19536, 19537, 19538, 18932, 18023

1. Comments related to alternative compliance test methods.

Comment 1: Commenter 17775 states that the EPA should allow use of Method 5B and 29 to 

demonstrate compliance with the PM limits under the stack testing option. Rather, the commenter 

asserts, the EPA proposes to allow use of Methods 5, 5D (required for positive pressure FFs), or 17 

(Proposal Table 5). The commenter states that sources performing calibrations of PM CEMS under 

Performance Specification (PS) 11, on the other hand, are also allowed the option of using Method 5B -

Determination of Nonsulfuric Acid Particulate Matter Emissions from Stationary Sources. The 

commenter states that Method 5B was specifically developed to determine primary filterable PM 

emissions from sources with wet scrubbers and is routinely allowed for stack testing under federal 

regulations. (40 CFR part 60, subparts D (section 60.46(b)), Da (section 60.50Da(e)(1)), Db (section 

60.46b(d)(2)), Dc (section 60.45c(a)(2)) and part 63, subparts QQQ (section 63.1450(b), UUU (section 

63.1579 and tables).) The commenter asserts that the EPA should allow use of Method 5B or explain 

why the method is not appropriate for demonstrating compliance with the proposed limits. The 

commenter asserts that although the agency’s specification of a filter temperature for Method 5 (320° F 

+ 25) achieves some of Method 5B’s objective, there is no basis for not allowing sources to use a 

promulgated test method specifically designed for that purpose. According to the commenter, 

prohibiting use of Method 5B could prevent some sources from using tests under subpart UUUUU to 

meet other testing requirements without obtaining approval for use of a higher Method 5 filter 

temperature in lieu of using Method 5B. Moreover, according to the commenter, evaluation of filterable 

PM data from the agency’s 2010 ICR database reveal an inconsistency between Method 5 and Method 

29 results. The commenter attaches a discussion of and findings on this issue. To the extent the EPA 

proposes or promulgates a PM limit that is based in any way on filterable PM results from Method 29, 

commenter asserts that the EPA must provide EGUs the option to use Method 29 for any PM testing.

Comment 2: Multiple commenters (17681, 17716, 17725, 17767, 17790, 17795, 17800, 18014) request 

that the final rule include the following reference methods in Table 5:

1. EPA Method 2H,

2. Conditional Test Method 41 (wall effects adjustment for flow),

3. EPA Method 26A (HCl - option for dry stacks),

4. EPA Method 320 (HCl – FTIR option),

5. EPA Method 5B,

6. EPA Method 17 (total, filterable PM), and

7. The table should indicate that Method 2 (or equivalent) need only be used if necessary to calculate 

output-based emissions.

Response to Comments 1 - 2: The final rule has been amended to allow the use of EPA Methods 2H, 

26A and 320 and clarify the requirement of Method 2 (or equivalent) only as necessitated by the 
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calculation of the emission limit. The EPA disagrees with the use of Method 5B or 17 as the filterable 

PM standard was based on Method 5 with a filterable temperature of 320 °F.

Comment 3: Several commenters (17767, 17790, 17795, 17800, 17821) state that proposed use of 

Method 5 rather than Method 5B in wet stacks is inconsistent with NSPS (e.g., section 60.46(b), section 

60.50Da(e)(1), section 60.46b(d)(2), and section 60.45c(a)(2)) and inconsistent with part 63(e.g., section 

63.1450(b) and section 63.1579), and the commenters request that the final rule specify the option to use 

Method 5B in wet stacks for compliance tests and PM CEM certifications consistent with PS-11. 

Commenter17795 acknowledges that the filter temperatures listed in Table 5 are consistent with Method 

5B but points out that filter desiccation temperatures per the proposal would occur at M5 temperatures

(220 °F). Commenter 17795 states that absence of Method 5B from the proposal creates a problem 

complying with section 3.20 of PS-11, which defines “reference method” as the method defined in the 

applicable regulation, but the method listed in proposed Table 5 is a hybrid method. Commenter 17795

states that inclusion of Method 5B is critical to certification of PM CEMS because all wet particulate 

monitors use some type of heated cyclone to vaporize water droplets before analyzing the gas sample, 

and the temperature of these cyclones is set to be consistent with the reference method filter 

temperature. However, according to this commenter, in order to obtain a final filter weight the reference 

method filters must be desiccated, to a constant weight, and proposed Table 5 specifies Method 5, which 

by default would require filter desiccation at 220 °F. According to this commenter, since the PM CEMS 

sampling process occurs at temperatures above the acid dew point, Method 5B should be followed to 

allow filters to be desiccated at the same temperatures as sample collection to minimize inaccuracies for 

wet PM CEMS correlations. Commenters (17795, 17800) also believe that making the MACT standard

consistent with the NSPS program and SIP programs will allow the use of a single stack test to satisfy

multiple regulatory requirements and save time, resources, and costs. Commenter 17725 recommends 

that the EPA also allow 40 CFR Part 60 Method 2H-Determination of Stack Gas Velocity Taking into 

Account Velocity Decay Near the Stack Wall as a valid method for all pollutant types listed in Table 5 

to subpart UUUUU of part 63 performance stack testing requirements. The commenter notes that they

utilize Methods 2, 2F, 2G, and 2H for annual volumetric flow monitoring as required across the fleet.

Response to Comment 3: The final rule does not require the certification of the PM CEMS by PS-11.

However, in the event a source wants to be able to use a PM CEMS as a direct method of determining 

compliance with the filterable PM emission limits in the final rule, the final rule allows for this option. 

Please see the final rule preamble for further discussion.

Comment 4: Commenter 17775 requests that the agency clarify that use of certain methods (Methods 2, 

2F, 2G, and 4) are optional because proposed Table 5 lists Methods 2, 2F or 2G as the required methods 

to determine the velocity and volumetric flow rate of the stack gas when testing for PM, HCl, and Hg, 

and lists Method 4 to determine moisture content for all pollutants, but in some cases, use of these 

methods may not be necessary, or reasonable, because all of the methods specified in Table 5 for 

concentrations of those emissions also provide measurements of velocity and flow. Likewise, according 

to the commenter, the methods used to determine pollutant concentrations (e.g., Methods 5, 23, and 

26A) also determine stack moisture. The commenter states that the agency should make use of those 

methods optional and allow the EGU to determine which method is more appropriate for the specific 

test. 

Response to Comment 4: The final rule has been amended to clarify that only methodology or 

equations required for the specific emission limit will be required.
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Comment 5: Commenter 17808 recommends measures be incorporated in the final rule to avoid 

running a unit simply to conduct a stack test similar to the approach used in part 75 for defining an 

operating quarter and a unit operating hour. Specifically, the commenter recommends incorporation of 

the provisions of 40 CFR 72.2 defining a “QA operating quarter” as “a calendar quarter in which there 

are at least 168 unit operating hours (as defined in this section) or, for a common stack or bypass stack, a 

calendar quarter in which there are at least 168 stack operating hours (as defined in this section).”

According to this commenter, a unit operating hour would be defined as a clock hour during which a 

unit combusts any regulated fuel, either for part of the hour or for the entire hour. The commenter

recommends that these definitions apply specifically to the regulated fuels under the EGU MACT rule 

(e.g., coal and liquid oil), because by requiring a minimum level of operation to trigger stack testing 

requirements, no unit will be operated simply for the sake of testing.

Commenter 17808 recommends an additional, alternative method for demonstrating continuous 

compliance for Hg when a unit qualifies for LEE status. As an alternative to conducting monthly fuel 

tests, the commenter proposes that owners/operators of a LEE unit have the option to conduct an annual 

Method 30B performance test to demonstrate that its emissions are less than 10 percent of its applicable 

Hg emissions limit or less than 22.0 pounds per year. If a LEE unit exceeds LEE limits, the commenter

proposes that the unit revert back to more frequent performance tests (e.g., quarterly, as recommended 

above). Under this commenter’s proposal, in the subsequent year, if the unit can, again, demonstrate 

LEE status through reduced utilization or a lower emission rate, it would return to annual stack tests 

under the LEE provisions. The commenter recommends this alternative, annual stack testing instead of 

monthly fuel testing, to balance the need for accurate emissions data with reduced compliance costs for 

those units emitting at a fraction of the proposed standards. Also, in order to avoid having companies 

run units simply to conduct stack testing, the commenter proposes that LEE units have the flexibility to 

schedule their annual performance tests at any time during a 12-month cycle because some of these 

LEEs may be smaller units with low capacity factors and may go several months without operating. The 

commenter believes that allowing flexibility in scheduling stack tests will avoid unnecessary HAP

emissions and reduce costs for these units operating well below the proposed standard and believes this 

compliance option would allow companies to align testing under this rule with existing state testing 

requirements. 

Response to Comment 5: The EPA agrees with the comments. The final rule has been amended to 

waive testing requirements in a quarter when the unit operates for less than 168 hours, but the source 

must under any circumstances test at least once per year.

Comment 6: Commenter 17747 states that they would also like to see the Method 29 monitoring 

options (Method 29 testing every 2 months or every month depending on PM control) retained. The 

commenter believes that this gives plant operators additional control options and flexibility in achieving 

emissions limits.

Response to Comment 6: The final rule has been amended to allow compliance with the non-Hg metals 

limit with quarterly Method 29 testing.

2. Comments related to testing period (clarification etc.).

Comment 7: Commenter 17868 states that the final rule should clarify the required testing period in 

proposed section 63.10005(k) which specifies 28 to 30 days, but proposed Table 5 specifies 30 days.
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Response to Comment 7: The EPA has clarified this issue in the final rule. The required testing period 

is 30 days.

Comment 8: Commenter 18539 states that it is not clear in the proposal whether the EPA intends to 

require one performance test every 5 years for all surrogates. For example, asserts the commenter, 

proposed section 63.10005(d)(4) states that initial compliance for coal-fired units with FGD technology

and SO2 CEMs is determined using the average hourly SO2 concentrations during the first 30-day

operating period, and section 63.10005(d)(5) states the same for PM CEMs. However, according to the 

commenter, pages 25051 and 25051 of the preamble and section 63.10005(a) indicate that PM, metals, 

SO2, and HCl compliance tests are required initially and every 5 years. According to the commenter, 

section 63.10005(a) states that “[I]f you use a continuous monitoring system that measures a surrogate 

for a pollutant (e.g., an SO2 monitor), you must perform initial emission testing during the same 

compliance test period and under the same process (e.g., fuel) and control device operating condition of 

the pollutant and surrogate, in addition to conducting the initial 30-day performance test.” Additionally, 

the commenter states, section 63.10006(a) and (b) state that PM and non-Hg metal HAP, and SO2 and 

HCl emissions testing, respectively, is required at least every 5 years. The commenter requests that the 

EPA clarify the intent of the stack testing requirements and give appropriate time to comment on this 

requirement. 

Response to Comment 8: The final rule has been amended to only require testing and/or monitoring for 

the specific emission standard with which the source complies (either the direct emission limit, such as 

HCl, or the alternate equivalent standard, such as SO2).

Comment 9: Commenter 17775 requests that the agency clarify the required testing period because 

proposed section 63.10005(k) refers to a 28-30 operating day performance test and proposed Table 2 

similarly requires “LEE testing for 28-30 days.” However, according to the commenter, proposed Table 

5 requires conversion of emission concentrations to “30 boiler operating day rolling average lb per 

MMBtu emission rates or lb/MWh emission rates” (proposed Table 5 (4.f.)). According to the 

commenter, if the EPA intends to allow use of 28 days of sorbent trap data (i.e., two 14-day sorbent

traps) to determine the “average Hg concentration” for the performance test, the EPA should make clear 

in Table 5 that the values in Table 5 can be derived from 28 days of data. 

Response to Comment 9: The final rule has clarified this issue. The required testing period is 30 days. 

3. Comments related to operating parameters and fuel limits set during testing.

Comment 10: Commenter 17775 requests clarifications regarding the proposal’s stack testing options 

for HAP metals because it is not clear to the commenter whether the agency intended the operating 

parameters and fuel input limits in proposed section 63.10011(b) to apply, because on its face, the 

requirements of section 63.10011(b) appear to apply to all EGUs, regardless of the compliance option. 

However, according to the commenter, that result is not consistent with the agency’s expressed 

intention. For example, the commenter asserts, in the preamble the EPA says that such operating 

parameters do not apply and cites 76 FR 25,029/3 (“Except for liquid oil-fired units, . . . we are 

proposing that you monitor during initial performance testing specified operating parameters) (emphasis 

added). However, the commenter states, similar to LEEs, the EPA also suggests that liquid oil-fired 

units must meet maximum fuel input limits as an operating limit (citing 76 FR 25,030/2). According to 

the commenter, the EPA must make clear in section 63.10011(b) what operating limits apply and issue a 

proposal explaining why. The commenter states that if the maximum fuel input limits in section 

63.10011(b) apply to liquid oil-fired EGUs opting to demonstrate compliance using stack testing, the 
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EPA should make clear that EGUs combusting a single fuel type are not required to make any 

determination regarding that fuel under section 63.10011(b)(2)(i) and (3)(i) (requiring determination that 

the fuel type or mixture has the highest content of Hg and of non-Hg HAP metal) and that EGUs using 

supplemental fuels qualify as single fuel EGUs. The commenter states that although the EPA has 

attempted to address that issue for liquid oil-fired EGUs in section 63.10005(c)(4) and section 

63.10011(c)(1), those provisions apply only to liquid oil-fired EGUs complying through fuel analysis.

Comment 11: Commenter 18023 states that the agency must clarify that operating limits and fuel limits 

do not apply to sources using CEMS for compliance because the commenter assumes that the purpose of 

the operating limits is to demonstrate compliance between regularly scheduled performance tests at units 

that are not otherwise continuously monitoring compliance; however, the proposed rule is not clear on 

this point. The agency should therefore specify that the operating limits (including the operating load 

limit) and fuel limits apply only to units using stack tests to comply.

Comment 12: Commenter 17775 states that the final rule must clarify the operating limit requirements 

for control devices and the single fuel EGU requirements for establishing a maximum fuel input for 

chlorine under section 63.10011(b)(1)(i).

Comment 13: Commenter 17878 states that for units not equipped with CEMS it is appropriate to have 

an alternative approach to assure compliance for the periods between stack tests. The EPA proposes to 

set enforceable operating limits based on control device parameters measured during performance 

testing creates what is effectively a second and more stringent standard. According to the commenter

unit operators will utilize control equipment that is designed to provide a margin of compliance that 

provides flexibility for the source to account for small variations in control equipment performance and 

fuel characteristics. The result will be “over-compliance” during a periodic stack test, and this is normal. 

If operating conditions reflecting this stack test period are then used as a measure of ongoing 

compliance, then those expected variations, which do not exceed an emission limit, would become 

violations.

Comment 14: Commenter 17868 states that the EPA should re-evaluate the proposed operating 

parameter requirements.

Response to Comments 10 - 14: The final rule has removed the requirements for operating and fuel 

limits, except where a source: (1) opts to use a PM CPMS to monitor compliance; or (2) for a liquid oilfired unit, adopts a source-specific monitoring plan to collect, record, and report on appropriate 

operational parameters in addition to conducting quarterly performance tests. In addition, the EPA notes 

that the final rule allows a source to monitor fuel moisture data to demonstrate compliance with the HCl 

and HF standards for liquid oil-fired units (fuel moisture must be no greater than 1.0%). The details of 

these options are discussed in the preamble to the final rule and elsewhere in this response to comment 

document. There are no operating parameter requirements in situations where a source determines 

compliance with an emission limit using a CEMS.

4. Comment related to use of short term stack test and fuel samples to set 30-day standards.

Comment 15: Commenter 17402 states that the EPA should not penalize facilities with low emissions 

by setting both fuel content and operating limits based on average performance during stack tests 

because this methodology effectively sets lower standards. Instead, according to the commenter, the 

EPA should set fuel content limits based on the source’s contaminant removal effectiveness, so that a 

source can use a range of fuels as long as the standard is met. Commenter 17729 is an affected source 
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operator who discusses stack test results for non-Hg metals and total PM at a unit that will be subject to 

the proposed MACT standards. Commenter 17720 states that the stack test data collected in 2010 in 

response to the EGU MACT ICR reflected compliance with the proposed standards during the 4-hour 

steady state tests, but this source operator states that such steady state tests do not indicate if continuous 

compliance is achievable at this source. Commenter 17623 states that the proposed limits for PM do not 

allow for variability because they are based on the particular conditions during one stack test for CPM, 

and the commenter believes that when setting a MACT standard, variability must be taken into account. 

The commenter adds that since each stack test is time-consuming and costly, the EPA cannot expect 

facilities to feasibly perform numerous stack tests.

Response to Comment 15: The final rule has removed the requirements for operating and fuel limits 

with the exceptions noted in Response to Comments 10-14, above.

5. Comments related to concerns about use of Method 202.

Comment 16: Commenter 18014 states that despite Method 202 being revised to include a nitrogen 

purge and an initial dry impinger (which is quickly wetted with condensation from the flue gas) to 

reduce these artifacts, the remaining SO2-related artifacts can be significant at low levels. According to 

the commenter, because of the bias, extending the run time does not necessarily improve the accuracy or 

detection limit since it simply provides more time for the artifacts to form and, thus, tends to defeat the 

purpose of adding the purge/dry impinger. According to the commenter, recent studies have shown the 

SO2-related artifact formation to be particularly acute if there is any NH3 in the flue gas (e.g., slip from 

an SCR for NOX control), which again is not related to primary particulate and certainly not related to 

metal HAP in any way.

Comment 17: Commenter 17402 expresses concerns that condensable PM reference Method 202 is 

unproven and variable and should be improved, because the commenter has reviewed many reports on 

Method 202 and OTM 28 and has carried out Method 202 testing programs. The commenter asserts that 

even with the recent improvements to Method 202 there are concerns about condensable PM formation 

and creation of pseudo particulates. The commenter references recently completed Method 202 stacks 

tests on a number of units using the same coal, and observations that the condensable PM fraction 

ranged from 7% to 75%. This commenter relays plans to install Trona FGD controls to reduce HCl and 

to further reduce condensable PM but expresses concerns that Method 202 may not properly quantify 

actual reductions. Commenter 17402 also relays plans to commission nine SNCR systems and 

associated concerns about ammonia slip reactions with dissolved SO2. Commenter 17402 encourages 

the EPA to continue research & development (R&D) on refined test methods to measure condensable 

PM, with the goal of achieving a more reliable standard in time for the initial MACT compliance date; 

however, the commenter believes that given the benefits of reducing condensable PM, the EPA should 

not let testing uncertainty prevent the implementation of the total PM standard. Commenter 17402 refers 

to the EPRI CEMS Users Group in Chicago, IL on June 8, 2011 and a presentation given by Clean Air 

Engineering (“CAE”) entitled “Description of a Potential Pseudo CPM Formation Mechanism in New 

EPA Method 202” for a CFB boiler equipped with an SNCR. The paper concluded that due to its high 

affinity for water, free NH3 in the gas stream will be absorbed in the aqueous layer of the Method 202

impingers and will react with SO2 to form either ammonium sulfate or bisulfate. According to 

commenter 17402, CAE recommended that ammonium sulfate or bisulfate formed in the Method 202

dry impingers should be considered an artifact and the commenter quoted CAE’s suggestion that “the 

EPA should acknowledge that significant positive biases related to the interaction of SO2-NH3-H2O can 

occur in the new M202, and should also allow for quantification and correction” of this artifact using 

procedures prescribed by CAE or the EPA should modify Method 202 to reduce or eliminate the bias. 
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Commenter 17402 states that subtracting the inorganic condensable PM from Method 202 and adding 

the inorganic condensable PM from CTM-013 (controlled condensation) was one of the steps included 

in the proposed procedure.

Comment 18: Commenters 17725 and 18498 state that using only filterable particulate (in conjunction 

with SO2 or HCl for selenium) as a surrogate for non-Hg metals from coal combustion would avoid 

various problems associated with including condensable particulate as part of the standard. According to 

the commenters one of the fundamental problems with using Method 202 for condensable PM 

measurements is that the results are overwhelmingly driven by sulfate and nitrate compounds, which 

have nothing to do with metal HAP emissions. According to the commenters, Method 202 is also 

problematic because of its high bias tendencies; the method is intended to provide a measure of 

condensable “primary particulate,” which is not PM at stack conditions but which condenses upon 

cooling and dilution in the ambient air to form PM, as opposed to “secondary particulate,” which forms 

later as different compounds react and combine in the atmosphere over time. The commenters

acknowledge that one might argue over the merits of requiring sources to include condensable PM as 

part of a measure to control ambient particulate/haze but assert that Method 202 is prone to biases due to 

SO2 artifact formation (again, something that has nothing to do with metal HAP) that make the results 

especially unreliable in conjunction with the long run times proposed under this rule. According to the 

commenters, while Method 202 was revised to include a nitrogen purge and an initial dry impinger

(which is quickly wetted with condensation from the flue gas) to reduce these artifacts, the remaining 

SO2 related artifacts can be significant at low levels. Also, according to the commenters, because of the 

bias, extending the run time does not necessarily improve the accuracy or detection limit since it simply 

provides more time for the artifacts to form and, thus, tends to defeat the purpose of adding the 

purge/dry impinger. The commenters state that recent studies have shown the SO2-related artifact 

formation to be particularly acute if there is any NH3 in the flue gas (e.g., slip from an SCR for NOX

control), which again is not related to primary particulate and certainly not related to metal HAP in any

way and cite Bionda, J. and Evans, S., Description of a Potential Pseudo CPM Formation Mechanism in 

New EPA Method 202, 2011 EPRI CEM Users Group Conference, Chicago, Illinois (June 8-10, 2011).

Comment 19: Commenter 17821 states that although the revisions of Method 202 finalized in 2010 

have been demonstrated in the laboratory to reduce sulfate and other artifact formation, the EPA’s data 

show that it does not completely eliminate the high bias associated with the test method: “EPA reported 

experimental results that showed the dry impinger modification to Method 202 reduced sulfur dioxide 

artifact formation by more than 90%.” See Method 202 Assessment and Evaluation for Bias and Other 

Uses Evaluation of Stakeholder Recommendations August 4, 2006 through April 17, 2007.

Comment 20: Commenters 18935 and 18034 note that the new version of Method 202 published in 

December 2010 is substantially different from Method OTM 28, which was used to generate ICR data. 

The commenters express concern that the proposed rules have been developed from a dataset derived 

from slightly different methodology than that which will be used to demonstrate compliance with the 

proposed rules. Given the different train configurations and operating temperatures, the commenters

suspect that OTM 28 data are not directly comparable to Method 202 and therefore sources may have 

difficulty planning or demonstrating compliance without substantial comparative testing.

Comment 21: Commenter 17820 states that Method 202, recently finalized by the EPA to measure 

condensables, is still prone to biases due to SO2 artifact formation that has nothing to do with metal 

HAP and makes resulting PM measurements questionable.
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Response to Comments 16 - 21: The final rule does not require the measurement of condensable PM as 

a part of an alternate equivalent standard for non-Hg metals, so we need not address these comments. 

However, the EPA also notes that the newly revised Method 202 was developed to minimize the 

formation of particulate from the oxidation of SO2 to SO3. Laboratory and field evaluations of the 

method reveal that the revisions were successful and that the residual formation is not quantifiable by 

gravimetric methods. The use of OTM-28 (essentially identical to the promulgated Method 202) for the 

ICR for utility boilers show that both the emissions of inorganic condensable particulate and the organic 

condensable particulate emissions measured with Method 202 are as consistent as the filterable PM

measurements. While the percentage of condensable particulate matter ranges from a low of 5% of the 

total PM to a high over 95%, the highest percentages are typically associated with the lowest filterable 

PM emissions and the lowest percentages are typically associated with the highest filterable PM 

emissions. This is the case both when the data are not segregated by control technology and when 

controls are segregated by control technology (dry scrubbing with either no ammonia injection or when 

ammonia injection is used with either catalytic or non-catalytic reduction, ESP with either no ammonia 

injection or when ammonia injection is used with either catalytic or non-catalytic reduction). This 

variability in the percentage of particulate that is condensable does not support the conclusions reached 

by the commenters that Method 202 provides inconsistent results. The data measured for the ICR 

demonstrates that Method 202 is comparable in precision as was demonstrated for the filterable 

particulate matter measurements. With respect to the conclusion of the commenters that ammonia 

absorbed in the impingers leads to artifact formation of ammonium sulfate or bisulfate, there is more 

than adequate published information that formation of ammonium sulfate or bisulfate occurs in the 

gaseous phase at lower temperatures in the presence of very small amounts of water vapor.1, 2, 3, 4, 5

While these reactions are prevented at temperatures above about 350 oF, the reactions occur when 

temperatures are below this level. As a result, the formation of ammonium sulfate or bisulfate in Method 

202 is not an artifact of the sampling method but the collection of PM that would occur upon the release 

of the flue gas to the ambient air where it is cooled and chemical reactions between the acid and basic 

constituents occur.

1Determination of Method 6 Samples in the Presence of Ammonia; Foston Curtis; Source Evaluation 

Society Newsletter; Volume XIII; February 1988.

2Reactions of Sulfur Dioxide with Ammonia: Dependence on Oxygen and Nitric Oxide; Koichi 

Hirota, Jyrki Ma1kela, and Okihiro Tokunaga; Industrial Engineering and Chemical Research 1996, 

35, 3362-3368.

3Reaction Behavior of Sulfur Dioxide with Ammonia; Yanxia Guo, Zhenyu Liu, Zhanggen Huang, 

Qingya Liu, and Shijie Guo; Industrial Engineering and Chemical Research; 2005, 44, 9989-9995.

4

Sulfur Dioxide Reactions with Ammonia in Humid Air; Edwin M. Hartley, Jr., and Michael J. 

Matteson; Industrial Engineering and Chemical Fundarmentals, Vol. 14, No. 1, 1975.

5

Thermodynamics of the Reaction of Ammonia and Sulfur Dioxide in the Presence of Water Vapor; 

Ronald Landreth, Rosa G. de Pena, and Jullan Helcklen; The Journal of Physical Chemistry, Vol. 79, 

No. 77. 1975.

6. Comments related to frequency of stack testing.

Comment 22: Commenter 17775 states that the EPA must clarify the Hg testing requirements. The 

commenter states that in the preamble, the EPA states that additional performance tests for Hg are 

conducted “at least annually.” (Proposal Preamble, 76 FR 25,029/3). The commenter agrees that Hg 

testing should not be required any more frequently than annually. However, according to the 
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commenter, there is no reference to this annual testing in the proposed rule. Instead, according to the 

commenter, the rule requires testing either monthly, or every other month, for “individual or total HAP

metals” and cites Proposal section 63.0006(f) and (g). The commenter states that the agency should 

revise its proposal to reduce all stack testing to no more frequently than annual. According to the 

commenter, there is no reason to require Hg testing in addition to “individual or total HAP metals”

testing. 

Response to Comment 22: In the final rule, annual Hg testing is required as part of demonstrating the 

continued applicability of the LEE provisions for a unit that qualifies as an LEE for Hg. For units with 

Hg CEMS or sorbent trap monitoring systems, Hg performance tests are not required on an annual basis, 

although the monitoring systems will be subject to ongoing QA, including RATA tests.

Comment 23: Several commenters (17730, 17775, 17808) express concerns about the number of stack 

tests required under the proposal’s stack testing compliance options. Commenter 17808 expresses 

concerns about the monthly or bi-monthly stack testing requirements in the proposed rule for units not 

measuring emissions continuously. For example, the commenter notes, liquid oil-fired EGUs would be 

required to test for all HAP metals on a monthly basis if they do not have a PM control device installed, 

or once every two months if they do have a PM control device. Additionally, the commenter notes, they

would need to test for HCl and HF on a monthly basis because there are no controls currently installed 

for addressing these pollutants at oil-fired EGUs. According to the commenter, coal-fired EGUs would 

face similar obligations. Commenter 17808 believes that the proposed frequency of testing will place a 

significant cost burden on plant operators. According to the commenter, stack testing can also be unsafe 

for testing personnel during harsh weather conditions, particularly the cold winter months. Finally, 

according to the commenter, inflexible testing schedules may induce units to run solely for testing 

purposes, leading to increased emissions. In addition to company costs and staff time, the commenter

notes that state-level environmental regulators may need to be on site to witness the tests and expresses

concerns that the large number of units affected by the rule and the proposed testing frequency could 

make staff availability a significant issue. The commenter is also concerned that this could result in 

delayed compliance testing or not being able to dispatch a unit (that has not been able to schedule 

required compliance tests). In an effort to balance these concerns with the need for reliable compliance 

demonstrations, the commenter recommends that all stack testing requirements be no more frequent than

quarterly under standard operation (i.e., unless boiler operations or characteristics are substantially 

altered, in which case initial testing should be repeated). The commenter believes that quarterly stack 

testing in combination with parameter monitoring should be enough to ensure that a unit is operating 

within the required limits because quarterly testing would capture seasonal variations in operation while 

not unnecessarily repeating tests at the same conditions. Commenter 17730 characterizes the proposed 

monitoring option for sources not using CEMS as excessive and overly burdensome because the 

commenter believes the requirement to conduct stack testing either monthly or bi-monthly is a very

expensive and time consuming operation, especially when testing at the very low levels necessary to 

comply with the proposed MACT standards. The commenter states that the sampling times that will be 

necessary to collect enough sample volume to record values over the method detection limits will 

require extended hours of testing operations, and the extended hours of testing further increase 

compliance costs. Commenter 17730 believes that compliance with monthly stack testing requirements 

will put sources in a nearly continuous mode of stack testing. The commenter recommends that the 

agency consider requiring stack testing on an annual basis combined with an appropriate level of 

parametric monitoring and defined operating limits because such requirements are adequate to ensure 

compliance and to protect public health and the environment. Commenter 17775 also expresses concerns 

with the proposal’s stack testing options for HAP metals with respect to the frequency of repeated stack 

tests and states that the EPA has provided no rationale or data for the proposed frequency of stack 
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testing or accounted for the cost of such frequent testing in its proposed ICR. The commenter references 

the EPA’s supporting statement for the February 2011 proposed ICR describing the existing source 

requirement as testing with Method 29 initially and every 2 years thereafter. [EPA-HQ-OAR-2009-

0234-3031 at Tables 1a, 1b, 1c.] However, the commenter interprets the statement as assuming that no 

source will perform anything other than initial testing. The commenter states that the proposed 

frequency of testing is by definition arbitrary and capricious and contends that EGUs demonstrating 

initial compliance through stack testing and confirming compliance by monitoring and responding to 

appropriate operating parameters should not need to conduct additional stack tests more frequently than 

annually, unless the EGU’s fuel type or controls change. The commenter contends that such frequent 

testing adds nothing but cost and states that the agency points to no other variables to justify such 

frequent testing. The commenter acknowledges that the proposal allows some provisions for reduced 

testing, but counters that the 50 percent criteria for qualify for these provisions makes them too

restrictive to be useful.

Comment 24: Comment 18498 states that the frequency of the additional performance testing 

requirements is not consistent with the expected variability in stack emissions. Units without add-on 

control systems are required to complete stack tests less frequently than units with add-on control 

systems. According to the commenter, for units without add-on control systems, the emissions of HCl, 

HF, and non-Hg metals are most closely tied to fuel characteristics. In lieu of requiring more frequent 

performance tests if a source chooses to use the alternate standards for certain subcategories, the 

commenter recommends periodic fuel analysis to determine if a significant change has occurred since 

the previous performance test. According to the commenter, if there is a significant change of fuel HAP

concentrations then additional emissions testing might be warranted but the source’s expected removal 

efficiency should also be taken into consideration to minimize unnecessary testing. The commenter

believes that annual performance testing is sufficient to demonstrate proper operation of control devices 

and has historically been sufficient.

Comment 25: Commenter 18498 states that because many liquid oil-fired sources operate infrequently

and only during peak demand periods for liquid oil-fired sources, the proposed testing magnifies the 

burden of frequent testing. The commenter notes in the preamble the EPA found that for liquid oil-fired 

units, no correlation was found between non-Hg metallic HAP emissions and PM emissions or the 

operation of PM control devices. As such, according to the commenter, the emissions of HCl, HF, and 

non-Hg metals are most closely tied to fuel characteristics and thus it would be more meaningful to 

assess fuel characteristics and use that information to determine whether additional emission testing is 

needed.

Comment 26: Commenter 18025 states that they support the proposal to allow existing sources the 

option to comply with input- or output-based standards, and recommend that the EPA maintain this 

flexibility in the final rule. However, the commenter believes that the proposed compliance 

demonstrations are unnecessarily frequent, and recommend quarterly testing for all HAP. According to 

the commenter, quarterly testing provides the necessary performance guarantee, while balancing the 

substantial costs of stack testing. 

Response to Comments 23 - 26: In response to comments, the final rule has been amended to include 

quarterly periodic testing and retains the option to comply with input-or output based standards for 

existing units. For liquid oil-fired units that use the quarterly performance test option, the source will 

also need to develop a site-specific monitoring plan to ensure that operations between tests remain 

consistent with the operations during the performance test. Please see the final preamble for further 

discussion.
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Comment 27: Commenter 17880 supports the requiring of coal-fired, IGCC and solid oil-derived fuelfired units to conduct HAP metals and P) testing at least every 5 years, using the current process 

outlined by EPA Methods 29, 5, and 202. Additionally, the commenter states, units that have elected to 

comply with the HAP metals emission limits instead of total PM emissions limits would be required to 

conduct total or individual HAP emissions testing every 2 months to demonstrate continuous 

compliance.

Comment 28: Commenter 17191 states that for IGCC units, the proposed rule requires either use of PM 

CEMS or Method 29 stack testing and that Method 29 is required every 2 months if PM controls are 

installed or every month if no PM controls are installed. The commenter requests that this requirement 

be clarified to indicate that the “PM controls” can be pre-combustion controls such as the gasification 

process for IGCC units because traditional post-combustion PM controls are not used in IGCC systems. 

Commenter 17191 states that PM is captured “upstream” of the combustion turbine in the gasification 

phase and that such a design configuration should not be used to require monthly stack testing under the 

Method 29 compliance option.

Response to Comments 27 - 28: In the final rule, if a PM CPMS is used, the source must reestablish the 

operating limit by conducting a test every year, not on a 5-year basis. This approach recognizes that the 

operating limit associated with the PM CPMS is a surrogate operational requirement that does not 

provide the same degree of assurance as a direct measurement of the emissions limit, and needs to be reestablished over time. With respect to the frequency of tests where continuous monitoring is not used to 

demonstrate compliance, the final rule does not distinguish between units with or without controls, so 

the concerns on how to classify IGCC combustion controls are inapplicable.

7. Comments related to derating units.

a. Compliance Plans to temporarily derate units while air pollution control upgrades are 

completed.

Comment 29: Commenter 17402 states that the EPA should clarify that stack testing may be performed 

at loads where facilities can meet all emissions and operating parameters because some upgrades 

required to meet certain MACT standards may not be fully operational as of the compliance deadline, 

and the commenter believes that compliance prior to completion of air pollution control upgrade projects 

can only be achieved by operating such units at reduced load. Commenter 17402 requests that the EPA 

clarify that “maximum normal operating load” under the proposed performance test guidelines can 

include short-term, full-load operating restrictions if such generating load restrictions are necessary to 

ensure compliance in advance of completion of air pollution control upgrades. Commenter 17402 notes 

that in proposed section 63.10007(c), the EPA specifically allows for the conducting of tests at 

“differing operating limits,” implying that the EPA expects the operating load to be somewhat flexible, 

and the commenter states that the EPA should not require operations during a performance test which 

the operator knows will cause a violation. Instead, the commenter requests that the final rule allow 

operators to choose an interim compliance operating level for up to 3 years so that the operating limits 

set based on the most recent performance test well temporarily limit maximum capacity to 110% of the 

operating load achieved during the most recent performance test.

Commenter 17402 additionally requests provisions in the final rule that would allow facilities that 

choose to restrict load (while air pollution control upgrades are installed) to resume operations at the 

pre-MACT, full-load capacity upon demonstrating compliance at the true maximum capacity during a 
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periodic performance test. The commenter notes that the EPA has supported interim control strategies 

previously, including voluntary capacity reductions.

Response to Comment 29: The EPA believes the proposed rule already provides for this type of 

flexibility. If a source adopts a derate restriction as a condition of its federally enforceable operating 

permit for a source, then testing at full load for that source would be conducted in accordance with the 

terms of the permit as to what full load means. As part of modifying the permit to lift the restriction, the 

EPA would anticipate that testing to demonstrate compliance with this rule would be part of the action 

that a source would need to take in order to demonstrate compliance.

b. NSR implications of interim MACT compliance strategies involving derates.

Comment 30: Commenter 17402 requests, regarding temporary measures to administratively derate a 

unit to a generating capacity that can comply with MACT standards while air pollution control upgrades 

are installed, that the EPA provide clarification on the implications of such a compliance strategy under 

the NSR program. The commenter believes that once the emissions controls are installed and fully

operational and the facility ends the voluntary capacity reduction, prevention of significant deterioration 

(PSD) or NSR should not be triggered provided that there is no significant increase in emissions from 2 

consecutive calendar years of operations prior to the interim control strategy’s implementation. 

According to the commenter, since “baseline actual emissions” are defined as any consecutive 24-month 

period from the 5 years prior to the start of construction, an operator could reasonably choose 24 months 

from the period preceding the interim control strategy’s voluntary capacity reduction, provided that 

construction started within 3 years of the interim control strategy implementation. The commenter states 

that “increase” is defined as the difference between baseline and potential annual emissions, where 

potential is the maximum projected emissions in any of the next 5 years. As a result, according to the 

commenter, with a properly designed control upgrade, a facility’s operating capacity before and after the 

interim control period would be identical, and the emissions in question would decrease. Given the clear 

emissions reductions, and conformity with existing regulations, the commenter requests that the final 

rule confirm that the use of an interim control strategy of voluntary capacity reductions will not result in 

triggering NSR or PSD requirements.

Response to Comment 30: PSD permit implications of the derate strategy mentioned by the commenter

would be addressed in accordance with the implementing regulations and accompanying guidance for 

the NSR program as in effect at the time of such compliance approach taken by the source. Those 

implications are not part of this rulemaking, and the EPA will respond to specific questions and requests 

for guidance on a case-specific basis under the normal procedures established for issuing guidance and 

policy interpretations under the NSR program.

8. Comment related to bypass requirements – CEMS.

Comment 31: Commenter 17675 states that the requirement in section 63.10010(a)(4) for installing, 

operating, and maintaining a complete CEMS system on a bypass stack is not appropriate for EGUs that 

only use the bypass stack for a short time during startups and shutdowns because such a requirement is 

excessive, unnecessary, and difficult to maintain in a state of readiness for a few hours of usage on an 

occasional basis. The commenter believes that alternative monitoring methods such as data substitution 

techniques similar to those used in 40 CFR part 75 or fuel sampling for Hg during startups and 

shutdowns must be allowed rather than requiring installation of a duplicate and seldom utilized CEMS

system for a startup bypass stack.
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Response to Comment 31: The EPA has modified the bypass stack monitoring requirements. Under 40 

CFR Part 75, the EPA allows the use of a maximum potential concentration value on a bypass stack. 

That approach works within the broad context of an emissions trading program but does not work when 

evaluating compliance with a specific emission limit over a shorter period. Thus, the final rule provides 

two other options for a source. One is to monitor the bypass stack consistent with the proposed rule. The 

other is to treat any hours of bypass stack emissions as periods of monitor downtime. In general, this is 

consistent with the EPA’s approach to startup and shutdown periods, in that we treat those periods as 

subject to a work practice standard. That generally obviates the need to monitor the bypass stack as the 

emission limit does not apply during the periods when the source is most likely to operate a bypass 

stack. Use of a bypass stack at times when the source is operating and the emission limit applies (i.e., 

other than startup or shutdown periods), will mean a failure to monitor emissions at all times in 

accordance with the rule.

9. Comments related to duplicative testing.

Comment 32: Several commenters (17820, 17868, 18014) state that the EPA is requiring stack tests for 

both the pollutant and surrogate and that this requirement is superfluous. The commenters state that the 

EPA has established alternative limits for compliance for various HAP groups. For example, state the 

commenters, coal-fired units may choose to meet either the PM limit, the limits for individual metals, or 

a total non-Hg metals limit to establish compliance for metal HAP and may monitor SO2 or HCl for acid 

gas HAP, and these options provide the sources with a measure of flexibility. According to the 

commenter, since limits for each pollutant (or surrogate) have been independently established to assure 

effective reductions in accordance with section 112 of the CAA, there is no need to test for both the 

pollutant and surrogate. The commenters indicate that a performance test should only be required for the 

pollutants and surrogates with which the source is choosing to show compliance.

Comment 33: Commenter 17775 believes that the EPA’s proposed compliance demonstration, 

recordkeeping, and reporting requirements are flawed because the applicability of many provisions is 

unclear and the EPA fails to provide any rationale by which the provisions’ basis and purpose might be 

discovered. The commenter states that for the first time in any MACT, and without explanation, the 

EPA proposes to require that EGUs exercising the option to comply with a surrogate emission limit also 

stack test for the corresponding HAP, and conversely, that EGUs opting to comply with a HAP limit 

stack test for the corresponding surrogate. According to the commenter, these duplicative testing 

requirements are inconsistent with the agency’s legal and policy justifications for the use of surrogates 

and are otherwise unsupportable. The commenter states that for EGUs that opt to comply with a chosen 

emission limit using stack testing, the EPA (again without explanation) requires stack testing no less 

frequently than every other month, requires compliance with established “operating limits” on control 

devices, and requires compliance with fuel input limits. According to the commenter, the agency

provides no rationale for the selected frequency of stack testing and fails to include the associated cost in 

its proposed ICR. According to the commenter, the requirements are unnecessary and inconsistent with 

the EPA’s prior position on use of surrogates, numerous preamble statements claiming cost savings by

use of surrogates, and the proposal to allow EGUs to choose whether to comply with a HAP limit or, 

where surrogates are proposed, the surrogate limit. The commenter states that where the EPA has 

demonstrated the appropriateness of use of a surrogate and selected an emission limit for that surrogate 

that is consistent with what the best sources achieve, there is no basis for also requiring the source to test 

for the applicable HAP. According to the commenter, the EPA says as much in the preamble, and the 

commenter cites portions of the preamble (including the following portions and language: the agency

summarizes the D.C. Circuit decision in National Lime Ass’n, 233 F.3d 625: If these criteria are satisfied 

and the PM emission standards reflect what the best sources achieve -- complying with CAA section 
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7412(d)(3) --’’EPA is under no obligation to achieve a particular numerical reduction in HAP metal 

emissions.’’ We have considered this case in evaluating whether the surrogate standards we propose to 

establish in this proposed rule are reasonable. 76 FR 25,021/3. The EPA has satisfied the criteria for use 

of PM, HCl, and SO2 as surrogates. See 76 FR 25,039/3, 25,040/1, 25,041/1.). According to the 

commenter, the same is true with respect to testing for surrogates. The commenter states that where the 

EPA has established an emission limit for a HAP that is consistent with what the best sources achieve, 

there is no basis for also requiring testing of a surrogate. Commenter further notes that in National Lime 

Ass’n, the EPA’s position with respect to use of PM as a surrogate was that it “‘achieves exactly the 

same level of HAP metal emissions limitations’ as would be reached were the metals to be regulated 

directly,” and that the “use of a surrogate ‘eliminates the cost of performance testing to comply with 

numerous standards for individual metals” (citing F.3d at 637 (quoting 64 FR 31,916/3)). According to 

the commenter, the Court found the EPA’s use of the surrogate reasonable (citing id. at 639). If the HAP

limit and the surrogate limit provide equivalent control, the commenter asserts, there is no reason to test 

for both, at any frequency, and the EPA has not suggested any purpose. The EPA also has not required 

such duplicative testing in any other rule that relies on surrogates.

Commenter 1775 also asserts that requiring testing for both the HAP and surrogate is inconsistent with 

Tables 1 and 2, which, according to the commenter, establish surrogate emission limits as “alternatives”

to HAP emission limits and vice versa. According to the commenter, requiring EGUs to test for HAP, 

when they have opted not to meet the HAP limit, or requiring EGUs to test for a surrogate, when they

have not opted to meet a surrogate limit is completely unreasonable. The commenter states that the tests 

have no regulatory purpose under the proposed rule and the EPA’s preamble summary identifies none. 

The commenter states that the EPA discussed the cost savings associated with using surrogates and 

refers to 76 FR 25,038; at 25,039; at 25,059. 

Commenter 17758 also disagrees with the proposal’s requirement to test for surrogates at units using the 

stack testing compliance option for non-Hg HAP metals and HCl, because according to the commenter, 

if a utility has chosen to demonstrate ongoing compliance by directly measuring the regulated HAP, it is 

superfluous to require any further testing of surrogates, and under the stack testing compliance option 

the agency should specify that performance tests only for methods necessary to measure the regulated 

HAP are required.

Comment 34: Commenters 17881 and 18428 state that where a surrogate is used the requirement to test 

for the applicable HAP is duplicative and should be removed. For example, according to the 

commenters, sources using PM as a surrogate for non-Hg HAP metals must perform metals testing in 

addition to stack testing for total PM and establishing a filterable PM limit and demonstrating 

compliance with PM CEMS, and similarly, sources using SO2 as a surrogate for HCl must test for HCl

in addition to the SO2 CEMS performance test. Commenter 18428 notes that for EGUs that do not 

choose to use a surrogate, the EPA proposes to require testing for surrogates anyway. For example, 

notes the commenter, proposed section 63.10006(d) requires EGUs without PM CEMS, but with a PM 

control device, to perform annual tests for both PM and non-Hg HAP metals. Similarly, proposed 

section 63.10006(h) requires EGUs without SO2 CEMS to conduct “all applicable performance tests” for 

SO2 and HCl annually and, for units with SO2 controls, to conduct SO2 emissions testing “at least every

other month.” See also preamble, 76 FR 25,051. According to the commenter, where the EPA has 

demonstrated the appropriateness of use of a surrogate and selected an emission limit for that surrogate 

that is consistent with what the best sources achieve, there is no basis for also requiring the source to test 

for the applicable HAP. The commenter asserts that where a source chooses to comply with the HAP 

limit, testing for surrogates is unnecessary and unreasonable. The commenter also views both 

requirements as inconsistent with Tables 1 and 2, which, according to the commenter, establish 
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surrogate emission limits as “alternatives” to HAP emission limits and vice versa. The commenter states 

that although the EPA describes these duplicative testing requirements in the preamble, the EPA 

provides no rationale to support them.

Comment 35: Commenter 18015 states that section 63.10000(c)(1) of the proposed rule provides that 

for all coal-fired and solid oil-derived fuel-fired units the initial performance testing is required for all 

pollutants. According to the commenter, this implies that for HCl, owners and operators would be 

required to conduct performance tests for both HCl and SO2, and for HAP metals, owners and operators 

would be required to conduct performance tests for both PM and all individual HAP metals. According 

to the commenter, this is inconsistent with the intent established in the preamble that facilities must 

conduct performance tests to demonstrate compliance with all applicable emission limits. According to 

the commenter, if a facility chooses to use PM as a surrogate pollutant and meet the PM limit set forth in 

Table 1 or 2, then that becomes the applicable emission limit, and the HAP metals emission limits are no 

longer applicable. The commenter asserts that this is supported by the fact that continuous compliance is 

based on PM CEMS or other PM-related compliance mechanisms. Conducting the additional emission 

tests for individual HAP increases the cost and labor time for no added benefit, according to the 

commenter, because the facility will be complying with the PM emission limit, not the individual HAP

metals emission limits. Thus, states the commenter, initial compliance should only apply to the 

applicable emission limit and result in testing of only the surrogate pollutant, PM, not HAP metals.

Comment 36: Commenter 18034 states that proposed section 63.10006 requires coal-fired and solid-oil 

derived fuel-fired EGUs to perform testing for non-Hg metal HAP even if the source elects to use total 

PM as a surrogate for the non-Hg metal HAP limits. The commenter states that similarly, the same 

source categories are required to perform HCl testing even if the source elects to use SO2 as a surrogate 

for HCl. Furthermore, the commenter states, on-going compliance for units that are not equipped with 

CEMS is through monthly or bi-monthly stack testing for pollutants that are the primary HAP when the 

source is using a surrogate limit for the HAP. According to the commenter, the preamble (76 FR 25029) 

states that the purpose of the stack testing is demonstrate compliance with all applicable emission limits; 

however, if a coal-fired EGU is using the PM surrogate option, the unit is not subject to the non-Hg 

metal HAP limits and a demonstration of compliance is not necessary. The same issue applies to an 

EGU using SO2 as a surrogate for HCl, the commenter states. According to the commenter, the EPA 

provides no explanation for why the proposed rule requires sources to test for pollutants for which there 

are no applicable emissions limits. The commenter also asserts that section 63.10006 is inconsistent with 

the EPA statements in the preamble that use of the PM surrogate would eliminate costs associated with 

conducting performance testing for non-Hg metals (76 FR 25039). According to the commenter, these 

additional testing requirements provide no added compliance assurance for the rule and unnecessarily 

impose extensive burden on regulated sources as well as state agencies that are delegated enforcement 

authority for the NESHAP and responsible for overseeing required stack testing. The commenter asserts 

that if these overlapping testing provisions are inadvertent, then the EPA must revise the rule to clearly

indicate that sources are not required to test or monitor for HAP when a surrogate limit for those HAP

has been selected. However, states the commenter, if the EPA is intentionally requiring sources to test 

for HCl and non-Hg metal HAP even if the sources are using a surrogate limit and do not have to 

demonstrate compliance with the specific HAP, then the EPA must provide a reasoned justification for 

the additional testing and explain the intended purpose of the test results.

Comment 37: Commenter 17868 states that the EPA must remove the requirement for SO2 performance 

testing. According to the commenter, proposed section 63.10006(h) and (i) include testing provisions for 

SO2 for units without SO2 CEMS. According to the commenter, the EPA must make clear that these 

provisions do not apply to EGUs complying through HCl stack performance testing. The commenter 
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states that there is no basis for testing of the surrogate SO2 at a unit that is complying with the HCl

standard. In addition, according to the commenter, the proposed rule does not provide any procedure for 

SO2 performance testing or an SO2 emissions standard other than those applicable to units with SO2

CEMS. The commenter states the EPA has no basis to require EGUs that choose to comply through 

stack testing to also install an SO2 CEMS.

Response to Comments 32 - 37: In response to comments, the final rule has removed all requirements 

for testing of both the individual HAP and the surrogate. Facilities complying with a surrogate limit do 

not have to perform periodic testing for the corresponding HAP.

10. Comments related to non-Hg metal standards.

Comment 38: Commenter 17775 supports the proposed inclusion of an option for non-Hg HAP metals 

stack testing (i.e., Method 29) but contends that the proposed rule contains duplicative testing 

requirements under the non-Hg HAP metals stack testing option. The commenter believes that to make it 

a reasonable option, the final rule must reflect several adjustments:

1. First, the commenter believes the final rule must remove the requirement for annual PM testing 

under section 63.10006(d) because no justification is provided for this requirement. Furthermore, 

notes the commenter, proposed Tables 1 and 2 clearly provide sources the option of meeting either a 

PM or non-Hg metals limit. Testing for PM when that option has not been selected and no limit 

applies is nonsensical. The commenter concludes that requiring testing for a surrogate in addition to 

the regulated HAP is beyond the agency’s authority.

2. The commenter believes that the EPA should re-evaluate the proposed operating parameter 

requirements because the operating parameters specified for non-Hg metal controls are not 

sufficiently connected to metals removal or sufficiently flexible to be used as enforceable limits. The 

commenter contends that secondary power is not directly related to PM removal and that pressure 

drop and liquid flow will vary with load. Moreover, according to the commenter, at the level of the 

proposed standard, metals control may not be very sensitive to liquid flow. The commenter states 

that the final rule must allow for adjustment of load-dependent operating parameters to account for 

load changes, and the final rule should use the operating parameters as indicators, not enforceable 

limits.

3. The commenter states that the final rule should make clear that EGUs combusting a single fuel type 

are not required to make any determination regarding that fuel under section 63.10011(b)(3)(i) 

(requiring determination that the fuel type or mixture has the highest content of non-Hg HAP metals) 

and that EGUs using supplemental fuels qualify as single fuel EGUs. The commenter notes that 

although the proposal attempts to address that issue for liquid oil-fired EGUs in section 

63.10005(c)(4) and section 63.10011(c)(1), those provisions apply only to liquid oil-fired EGUs

complying through fuel analysis.

4. Commenters 17775 and 17868 state that the final rule should specify minimum detection limits for 

laboratory analyses and provide procedures for calculating combined concentrations of single metals 

and total non-Hg metals. According to Commenter 17775 the data collected in the 2010 ICR

indicated the reported detection limits for laboratory analyses were highly variable even for data for 

the same metal and from the same laboratory. To determine compliance on a consistent basis, the 

final rule must specify minimum detection limits and a procedure for combining front and back half 

fractions to report total concentrations.

Response to Comment 38: The final rule has removed all requirements for testing for both the non-Hg 

HAP metals and the PM. The operational limits tied to secondary power, pressure drop and liquid flow 
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have been removed. The EPA disagrees that a specific minimum detection limit should be given due to 

the variety of factors affecting detection limits such as matrix effects, sampling gas volume, analytical 

finish, and final analytical volumes. The EPA agrees about the need for a procedure to combine the front 

and back half fraction and has revised the final rule to address this concern. With the removal of the 

proposed fuel input operating requirements in the final rule, the concerns about identifying highest fuel 

mixture and supplemental fuels are no longer applicable.

11. Comments related to HCl standard testing.

Comment 39: Commenter 17775 expresses the following concerns with the HCl stack testing option:

1. The commenter supports the proposed inclusion of an option for HCl stack testing. However, the 

commenter contends that to make it a reasonable option, the final rule must include several 

adjustments. First, the commenter states, the EPA must remove the entire requirement for SO2 

performance testing under this option because there is no basis for testing of the surrogate SO2 at a 

unit that is complying with the HCl standard. In addition, the commenter states, the proposed rule 

does not provide any procedure for SO2 performance testing, or an SO2 emissions standard other than 

those applicable to units with SO2 CEMS. The commenter states that the EPA has no basis to require 

EGUs that choose to comply through stack testing to also install an SO2 CEMS.

2. Second, according to the commenter, the EPA should re-evaluate the proposed operating parameter 

requirements because the operating parameters specified for HCl are not sufficiently connected to 

HCl removal or sufficiently flexible for use as enforceable limits. The commenter states that the 

EPA also must allow for adjustment of load-dependent operating parameters to account for load 

changes and should use the operating parameters as indicators not enforceable limits.

3. Third, according to the commenter, the EPA should make clear that EGUs combusting a single fuel 

type are not required to make any determination regarding that fuel under section 63.10011(b)(1)(i) 

(requiring determination that the fuel type or mixture has the highest chlorine content) and that 

EGUs using supplemental fuels qualify as a single fuel EGUs. The commenter states that although 

the agency has attempted to address that issue for liquid oil-fired EGUs in section 63.10005(c)(4) 

and section 63.10011(c)(1), those provisions apply only to liquid oil-fired EGUs complying through 

fuel analysis.

4. Fourth, the commenter re-iterates previously stated concerns about the frequency of stack testing 

required under the stack testing compliance option but relates the concerns to the HCl standard 

rather than HAP metals standard.

Response to Comment 39: The final rule has been amended to remove the requirement for testing of 

both SO2 and HCl. Operational parameter requirements specified for HCl have been removed. The 

frequency of periodic testing has been reduced to quarterly testing. With the removal of the proposed 

fuel input operating requirements in the final rule, the concerns about identifying highest fuel mixture 

and supplemental fuels are no longer applicable.

Comment 40: Commenter 17807 states that preliminary HCI testing using Method 320 (FTIR) and 

Method 26 generally show a considerable disparity in the reported concentration of HCl. According to 

the commenter, Method 26A is reported to be approximately 5 to 10 times higher than Method 320. The 

discrepancy is considered significant despite sampling on different dates and taking into account 

variances in chemical composition of coal. According to the commenter, this data supports the high 

biases of chlorides from FGD systems running with high equilibrium chloride concentrations. 

Furthermore, asserts the commenter, the test results imply Method 26A may not be an appropriate test 
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method for testing HCI emissions in wet stacks. The commenter suggests the EPA evaluate these 

discrepancies in wet stacks using Method 320. (See 17807-A1_Table_2_&_3.doc.)

Response to Comment 40: The EPA has amended the final rule to include the option for periodic HCl

testing by Method 320.

Comment 41: Commenter 17696 states that coal-fired EGUs without an HCI CEMS should be allowed 

to reduce the frequency of HCI stack testing or fuel analysis if the EGU’s initial performance test is less 

than 50% of the standard. According to the commenter, for coal-fired EGUs that do not install an HCl

CEMS, proposed section 63.10006(k) and (l) require performance testing either monthly (for EGUs

without an FGD) or every other month (for EGUs with an FGD). Commenter 17696 contends that for 

EGUs whose initial emissions stack test is less than 50% of the applicable HCl emission limit, monthly

or bi-monthly performance testing for HCl is excessive, unnecessary and unduly burdensome. 

According to the commenter, EGUs that emit at such low HCl emission levels are able to do so as a 

result of the chlorine content inherent in their fuel. As long as there is no change in fuel, the commenter 

asserts, there is no expected change in the level of HCl emissions. The commenter suggests that an 

alternative approach for sources testing at less than 50% of the standard is to require subsequent 

performance tests less frequently, such as semiannually. Commenter 17696 also states that a 50%

threshold would be consistent with the threshold for reduced frequency of monitoring in proposed 

section 63.10006(o) and states that operating parameters and fuel analysis demonstrating no material 

changes in the fuel supply are sufficient to assure compliance with the applicable HCl emission limit 

between semi-annual performance tests.

Response to Comment 41: The final rule has been amended to require quarterly HCl testing for sources 

not using an HCl/HF or SO2 CEMS option. The EPA disagrees that one performance test at 50% of the 

emission standard would be adequate to ensure compliance. However, the final rule adopts a LEE 

provision for pollutants other than Hg that enables a source to move to annual testing if all tests for the 

applicable pollutant over a 3-year period are less than 50% of the emission limit.

Comment 42: Commenter 17754 requests that the EPA revise the compliance demonstration 

requirements applicable to EGUs achieving LEE status for Hg, and the commenter contends that the 

final rule should provide an additional compliance option for LEEs with Hg emissions below 50% of the 

applicable LEE threshold; according to the commenter, such very low emitting EGUs should be allowed 

to demonstrate continuous compliance through annual stack testing and should not be required to 

conduct monthly fuel analyses.

Response to Comment 42: The LEE threshold for Hg remains at the 10% threshold that the EPA 

proposed (or the total mass limit of <29 pounds per year, as requested by another commenter for 

consistency with existing state rules). However, there is no monthly fuel analysis requirement for units 

that qualify, but rather an annual test, consistent with the commenter’s recommendation.

12. Comments about concerns with combined stack.

Comment 43: Commenter 18932 states that the use of combined stacks will undermine monitoring and 

enforceability because the stringency and practicable enforceability of an emission standard depends 

largely on the precision of its associated monitoring regimen. The commenter asserts that monitoring 

requirements that do not reflect appropriate averaging times based on applicable emissions or air quality

standards do not assure continuous compliance with those standards. Similarly, the commenter states, to 

assure that each EGU meets all applicable MACT emission standards, the Utility Air Toxics Rule must 
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specify monitoring requirements that will accurately measure and record the HAP emissions from each 

individual source. The commenter does not believe that the proposed rule will accurately measure and 

record emissions from individual sources and believes that the agency must clarify monitoring 

requirements in cases where multiple individual units co-located at a single facility exhaust through a 

combined stack. According to the commenter, this problem arises in two ways: (1) when multiple 

emission sources vent gases through separate flues that are physically located within the same stack; and 

(2) when multiple emission sources vent commingled exhaust gases through a common stack.

The commenter asserts that, first, there are many cases where multiple individual units exhaust through 

individual flues that are co-located within a combined stack. According to the commenter, the rule 

should make it clear that, in such cases, individual flues should be monitored separately, since there is 

no impediment to doing so. According to the commenter, the combined stack, in these instances, is 

simply the structural unit that encloses the flues, which are the separate, functional, exhaust gas emission 

points.

The commenter also asserts that there are many other instances where the exhaust gases generated by 

individual EGUs enter, commingle, and exhaust through a common stack. According to the commenter, 

to assure that each EGU that vents through a combined stack complies with applicable MACT standards, 

the EPA should require separate monitoring and reporting of each unit’s HAP and surrogate emissions 

prior to the exhaust gases commingling in the stack, such as prior to the stack breeching. According to 

the commenter, a monitoring regime that does not require each source to separately monitor and report 

its HAP emissions will not assure that each covered EGU complies with all applicable MACT

requirements. The commenter provides an example of monitoring emissions at both types of combined 

stacks.

Response to Comment 43: A common stack with individual flues (and no commingling of emissions 

from the individual units) will require monitoring and testing on each separate gas stream. Each flue 

would be the monitored or tested location at any unit that operates in such a manner. For the more 

typical common stack situation in which emissions from multiple units may be released through a single 

combined stack, the rule allows for either separate monitoring at the unit level or monitoring of the 

combined emissions. In the latter case, any failure to meet the standard at the combined location would 

be deemed a separate compliance issue for each individual unit to which the standard applies.

13. Comments about using total PM.

Comment 44: Commenter 17621 states that the use of total PM as a surrogate parameter for HAP

metals is problematic due to shortcomings in the test methods for the two components of PM (filterable 

and condensable PM). According to the commenter, particulate monitors measure only the filterable 

portion of total PM, and the manual stack test methods for both filterable and condensable PM are of 

uncertain accuracy.

Commenter 17621 also states that the EPA’s rationale for including condensable PM in the MACT limit 

to represent selenium is not supported. 

Comment 45: Commenter 17877 states that the proposed total PM MACT is unworkable for several 

reasons. According to the commenter, while Method 5 is more accurate in the short run, it does not (and 

cannot) account for variations in filterable PM actual levels over a range of unit operating levels as 

would a less accurate PM CEMS. Optical, light scatter, and light extinction PM CEMS are not accurate 

enough to acquire meaningful values for developing a PM limit, but they could be used to determine 
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variability. According to the commenter, Laser Beta Gauge or Tapered Element Oscillating 

MicroBalance (TEOM) PM samplers are much more expensive, but could be used to develop a body of 

data that is both accurate and inclusive of operating variability over long periods. The commenter is not 

aware that any such data was used to inform the development of the PM standard, but contends that this 

analysis should be performed on the 12% of existing units identified in the development of the PM 

surrogate for HAP metals.

Response to Comments 44 - 45: As discussed in detail in other sections of this document (see 4F01

responses), the requirement for total PM testing has been removed from the final rule.

14. Miscellaneous comments regarding testing.

Comment 46: Commenters 17621 and 17758 state there is a need to establish test methods that can 

measure the HAP or surrogates accurately at the actual stack gas concentrations. Commenter 17621 

refers to an EPRI study that evaluated whether an accurate measurement could be obtained by most of 

the ICR laboratories at those emission levels using the standard methods required by the ICR (Appendix 

B; Method Sensitivity for ICR Data Usage and Compliance with Proposed MACT Limits). The 

commenter concludes that the method sensitivity is not adequate to quantify HAP or surrogates at many

of the new unit limits that EPA is proposing. According to the commenter, the reason for this is that the 

EPA’s floor procedure relied on outliers and did does not take into account method performance with 

actual stack gas samples.

Comment 47: Commenter 17725 states that in section 63.7520(d), the EPA minimum sampling time of 

4 hours for each test method seems excessive for certain pollutants. The commenter recommends that 

the EPA re-evaluate the required sampling times for each method and/or provide alternative minimum 

sample volumes for each method, taking into account representative analytical detection limits and 

emissions standards that are properly adjusted for non-detect values.

Response to Comments 46 - 47: The EPA reviewed the minimum sample volumes required for the 

emissions limits and, based upon the present analytical capabilities, concluded that the sample volumes 

specified are appropriate. In the future, facilities with the capabilities to meet the stack detection limits 

in less than required volumes may request alternative test methods per 63.8(f).

Comment 48: Commenter 17731 states that the proposal to require “total PM and HAP metals testing 

during the same compliance test period and under the same process (e.g., fuel) and control device 

operating conditions at least once every 5 years” (citing 76 FR 25029/2), has not been justified given 

that it is highly unlikely an EGU could demonstrate compliance with the total PM limit while exceeding 

the individual PM and HAP metals limits. 

Response to Comment 48: The final rule will not require testing of both the filterable PM emission 

limit and the corresponding HAP metals standard. The source will conduct the test that is applicable to 

the standard with which the source has elected to comply.

Comment 49: Commenter 19033 states that the Table 8 data recording requirements should match the 

sampling times specified in Table 7. The commenter states that for example, scrubber and ESP 

parametric data is mandated by Table 7 to be recorded at 15 minute intervals during each test run. Three 

test runs are then required. According to the commenter, since Table 8 requires that subsequent data is to 

be maintained in 12-hour block averages, it would seem the EPA want each test run to last 4 hours. 

However, the commenter states, as examples, Table 2 specifies that each PM test run needs to collect a 
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minimum of 2 dscm, and each HCI test run using Method 26A needs to collect a minimum of 0.75 

dscm. The commenter doubts that it will take 4 hours to meet the minimum test run sample volume for 

either pollutant and therefore they recommend that Table 8 be amended from 12 hours to the time period 

required to perform three test runs. 

Response to Comment 49: For the 12-hour block average limits discussed in this comment, the EPA 

notes that the final rule does not require data reporting of these parametric data. Generally, the only 

operating data reported under the final rule are PM CPMS data (see the final preamble and other 

responses pertaining to the potential for liquid oil-fired units to require operating parameter data in 

certain situations). The source will collect hourly data during the performance test, identify the highest 

hourly average during the test, and then record data during operations on an hourly basis and develop a 

rolling 30-day average of the PM CPMS data. There is no intent that the 30-day average represent the 

length of the Method 5 or 29 stack test.

Comment 50: Commenter 18963 states that if the EPA does not agree to revise the proposed rule to 

provide that if an owner/operator of an affected EGU elects to demonstrate compliance with total nonHg HAP metals by using the PM surrogate, then such owner/operator is not required to conduct 

performance tests for PM and total non-Hg HAP simultaneously, the proposed rule must nonetheless be 

revised to avoid additional ambiguities. Specifically, according to the commenter, the proposed rule 

lacks clarity related to the requirement to conduct periodic emissions testing for HAP metals and total 

PM during the same compliance period and under the same process and control device operating 

conditions (citing76 FR 25,106). According to the commenter, the proposed rule fails to clearly address 

a facility’s compliance status if it simultaneously conducts stack testing for HAP metals and PM during 

the same compliance period, and demonstrates compliance with the applicable standards for one of these 

two pollutants.

Response to Comment 50: The final rule has been amended to remove the requirement for testing total 

non-Hg HAP metals if the source elects to meet the filterable PM standard (and vice versa).

Comment 51: Commenter 18021 states that any performance testing of an EGU needs to be 

representative of the unit’s actual operation. According to the commenter, EGUs ramp up and ramp 

down based on demand, and the performance testing needs to be based on a test plan that will, in the 

end, reflect the unit’s actual operation. According to the commenter, that unit’s specific test plan needs 

to make it possible to “certify” and have the documentation demonstrating that the EGU configuration, 

control devices, and material/fuel have remained constant since the prior performance test was 

conducted (section 63.10005(d)(1)(iii)). According to the commenter, this protocol would be consistent 

with section 63.1 0007(c). The commenter asserts that the flexibility to address normal operating 

conditions should be clearer. The commenter provides that if an affected unit chooses to establish limits 

for PM as a surrogate for metals and if the limit on PM were established based on a one-time test of 

three runs at maximum potential operating load, the affected source would be penalized at those units 

where over-controls were provided to allow for a compliance buffer.

Comment 52: Commenter 18015 opposes the proposed requirement for periodic compliance testing for 

several individual HAP for which the proposed rule designated a single surrogate. The commenter

believes that demonstration of continuous compliance for that surrogate based on data collected with 

CEMS should assure compliance with the requirements for the individual HAP that surrogate represents. 
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Response to Comments 51 - 52: The final rule has been amended to remove the requirement for testing 

of both the HAP and a surrogate. You will test for compliance only with the limit with which you are 

demonstrating compliance.

Comment 53: Commenter 18015 states that a testing grace period, similar to the 40 CFR part 75 RATA 

grace period provisions, should be applied when a source is unable to complete the required testing by 

the deadline specified. Additionally, the commenter recommends that a grace period of 720 unit 

operating hours should apply to sources that are unable to complete performance tests within the allotted 

time period. 

Response to Comment 53: The EPA agrees with the commenter that a grace period similar to the 40 

CFR Part 75 RATA grace period provisions should be provided for RATA testing and these provisions 

have been added to Appendices A and B. The EPA disagrees that grace period provisions should be 

provided for the performance testing requirements in Subpart UUUUU. The Part 63 General Provisions 

section 63.7(a) provide for an extension of the performance testing deadlines only for situations beyond 

the source owner/operators control. These provisions are explained in greater detail in the “Clean Air 

Act National Stack Testing Guidance” released on April 27, 2009.

Comment 54: Commenter 17881 states that clarification is needed with respect to what it means to 

“conduct all applicable performance tests for PM (or SO2) and non-Hg HAP metals (or HCl) during the 

same compliance test period” (citing section 63.10006). According to the commenter, while this 

statement may make limited sense for those units demonstrating compliance via a CEMS, EGUs relying

upon manual sampling methods for the surrogate will not likely be able to conduct concurrent tests for 

the associated HAP(s) due to limitations on sampling port availability, possible interferences from 

multiple probes inserted at a given stack plane, etc.

Comment 55: Commenter 17881 questions how, when CEMS are being used to measure the surrogate 

(i.e., PM or SO2), one would reconcile a 30-day compliance test period for the surrogate with the 

relatively short duration run times associated with manual sampling methods for non-Hg metals and HCl 

(citing section 63.10006). 

Response to Comments 54 - 55: In response to comments, the final rule has removed all requirements 

for duplicative testing of a HAP and a surrogate. Facilities complying with surrogate standard do not 

have to perform periodic testing for the corresponding HAP.

Comment 56: Commenter 17881 states that as currently written, section 63.10006(e) requires that the 

fuel factor methodology and equations in sections 12.2 and 12.3 of Method 19 (40 CFR 60, Appendix 

A-7) be used to convert the results of the performance tests into units of lb/MMBtu of lb/TBtu, as 

applicable. According to the commenter, this section should recognize that such calculations need not be 

conducted if an EGU has chosen to demonstrate compliance with the mass per unit of electrical output 

emission limits. 

Response to Comment 56: The final rule has been amended to clarify that only the methodology or 

equations required for the specific emission limit will be required.

Comment 57: Commenter 17881 states under Table 1 - Emission Limits for New and Reconstructed 

EGUs, that the run times specified for each constituent should be the lesser of 4 dscm or the duration 

required to capture a specified amount of PM. According to the commenter, the current volume equates 

to a run time of about 4 hours at a typical sample rate of 30 dscf/hr. 
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Response to Comment 57: The EPA does not believe a change is warranted. The run time is that 

needed to get at least 4 dscm. The commenter’s suggestion would not change that because, using the 

commenter’s phrasing the current wording is the same as “the lesser of 4 dscm or the duration required 

to capture a specified amount of PM [4 dscm].”

Comment 58: Commenter 17881 questions why (under Table 2 - Emission Limits for Existing EGUs, 

for Coal < 8300 Btu/lb, Total PM) the run time is different than the run time for existing units firing 

coals > 8300 Btu/lb when the PM emission limit is identical. 

Response to Comment 58: The final rule has been amended to fix the clerical error.

Comment 59: Commenter 17881 states that (under Table 5- Performance Stack Testing Requirements 

for Non-Hg HAP Metals) the exhaust flow and moisture should only need to be determined if you are 

complying with the lb/MWh limit. According to the commenter, the O2/CO2 levels should only need to 

be determined if complying with the lb/MMBtu standard. 

Response to Comment 59: The final rule has been amended to clarify that only the methodology or 

equations required for the specific emission limit will be required.

Comment 60: Commenter 17881 questions whether (under Table 5, for HCL and HF) 40 CFR part 60, 

Appendix F, Procedure 1 is really applicable to HCl and HF CEMS. 

Response to Comment 60: Based on the comments received that support the use of part 75 reporting 

for CEMS, we have added an Appendix B to the rule to set the technical requirements for QA applicable 

to an HCl or HF CEMS if used under this rule. The procedures are largely similar to Appendix F as 

proposed but adapt those requirements to fit more closely with approaches taken under Part 75 so that 

the existing reporting infrastructure for Part 75 reporting can be easily adapted to support this rule.

Comment 61: Commenter 17881 states that (under Table 5) 40 CFR part 60, Appendix B, Performance 

Specification 6 conflicts with the QA requirements in part 63, subpart UUUUU, Appendix A for 

auxiliary measurements. 

Response to Comment 61: The final rule will be amended to provide consistency with Table 5 and 

Appendix A.

Comment 62: Commenter 17881 states under Table 5, for Hg, (bullet a.) Method 20B (sic) contains 

alternate provisions for determining the number of sampling points as compared to Method 1.

Response to Comment 62: The final rule has been amended to allow the alternative provisions for 

sample point selection contained in Method 30B.

Comment 63: Commenter 17881 states that under Table 5, bullet f., the rule should also contain 

provisions for lb/MWh or lb/GWh conversions. 

Response to Comment 63: This issue has been addressed in Table 5 and section 63.10007(e) of the 

final rule.
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Comment 64: Commenter 17881 states that under Table 5, for the LEE testing, moisture and flow 

should only be required if you elect to show compliance with the lb/GWh limit or calculate annual mass 

using a flow CEMS, in which case moisture would be needed. 

Response to Comment 64: The final rule has been amended to clarify that only the methodology or 

equations required for the specific emission limit will be required.

Comment 65: Commenter 17681 states that proposed section 63.10011(b)(3)(i) appears to require 

operators to determine the fuel mixture with the highest content of non-Hg HAP metals and asks if this 

determination requires distinction between types of coals (i.e., anthracite, bituminous, subbituminous, 

etc.) and between regions (i.e., Illinois Basin coal vs. Appalachian coal).

Response to Comment 65: The final rule no longer includes this provision.

Comment 66: Several commenters (19536, 19537, 19538) state that the EPA should strengthen 

monitoring requirements for acid gases because one plausible combination of monitoring and FGD

controls is omitted from the proposal. Commenters state that no periodic performance testing and 

operating parameter monitoring are specified for units that use CEMS but have no controls.

Response to Comment 66: The EPA disagrees that additional performance testing or operating 

parameter monitoring is needed for units operating CEMS.

Comment 67: Commenter 17174 states that the term “maximum normal operating load,” as used in 

section 63.10007, is not defined. According to the commenter, facilities use different fuels in different 

proportions, depending on many variables such as availability and cost. The commenter asserts that the 

EPA should provide a clear definition of maximum normal operating load or representative operating 

conditions in section 63.10042. According to the commenter, the EPA should also clearly define how a 

source that utilizes more than one fuel should comply with this requirement. The commenter states that 

there appears to be an inconsistency between the testing conditions specified in section 63.10007(c) and 

(f). According to the commenter, while section 63.10007(c) requires facilities to conduct performance

tests at the “maximum normal operating load,” section 63.10007(f) requires facilities to conduct 

performance tests under such conditions as the EPA Administrator specifies to the owner or operator 

based on “representative performance” of the affected source for the period being tested. (76 FR 25108)

Comment 68: Commenter 17770 states that there is a problem with setting an emission limit that must 

be achieved on a continuous basis using results from a periodic performance test. According to the 

commenter, a performance test is conducted according to prescribed conditions, i.e., steady state, full 

load conditions and provides a “snap-shot” of unit performance representative of those steady state 

conditions, and a performance test does not show how that the unit will operate under all conditions and 

at all levels of unit operation. The commenter states that typically, a unit will operate above or below the 

load conditions during which performance tests are conducted.

Comment 69: Commenter 18935 notes that the proposed minimum sample volumes for metals and HCl 

will probably not yield the required detection limits to establish compliance. According to the 

commenter, while a responsible emission testing firm will make source-specific calculations as part of 

test planning, the proposed sampling volumes may significantly skew the anticipated cost of and time 

associated with compliance testing. As a responsible emission testing service provider, the commenter

encourages the EPA to present realistic sample volume and duration information so that sources can 

properly budget and prepare for compliance testing.
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Response to Comments 67 - 69: The EPA reviewed, and adjusted as appropriate, the final emission 

limits and minimum detection levels so that the rule contains appropriate sample volumes and run 

durations. 

Comment 70: Commenter 18021 states that the small degree of alternative requirements with 

Administrator’s approval is built into the regulation but is concisely stated. The commenter requests 

elaboration in at least the preamble that recognizes the variability in design and operating characteristics 

of EGUs allowing consideration of alternatives supported with a demonstration during the performance 

tests is needed. The commenter requests that the EPA allow demonstration with CEMS and/or operating 

parameters in lieu of an emission test after the annual performance test during the first 2 to 3 years.

Response to Comment 70: While the agency appreciates the commenter’s support for rule brevity, the 

agency does not believe the preamble needs to elaborate on an EGU owner or operator’s ability via the 

general provisions in §63.8(f) to seek an alternate means of monitoring. The agency finds the last 

comment moot, as the rule no longer requires annual performance tests or operating parameter limits for 

those EGUs whose owners or operators choose to use CEMS.
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5A02 - Testing/Monitoring: Averaging times for monitored pollutants

Commenters: 17621, 17623, 17627, 17638, 17681, 17689, 17702, 17705, 17714, 17716, 17718, 17725, 

17730, 17736, 17740, 17757, 17758, 17767, 17774, 17775, 17796, 17798, 17800, 17807, 17820, 17873, 

17881, 17885, 17902, 17904, 17909, 17925, 17926, 17927, 17928, 17929, 17930, 18014, 18018, 18034, 

18037, 18421, 18443, 18498, 18539, 18644, 18831, 19032, 19041, 19114, 19121, 18023

1. Commenter supporting current or shorter averaging times.

Comment 1: Commenter 17926 supports and offers praise for the proposed averaging times in

conducting Hg-related testing. According to the commenter, currently Montana utilizes a 12-month 

average in calculating the emissions of generating units. The commenter states that while Montana has 

Hg emissions limitations, the averaging times may allow for emissions spikes of Hg. According to the 

commenter, the proposed averaging times by the EPA, which are averaged on a rolling basis of 30 boiler 

operating days, will assure that facilities are adequately complying with emissions limits. The 

commenter also contends that a 30-day averaging time will help to assure that facilities are avoiding 

time periods with periodic spikes in emissions.

Response to Comment 1: The agency appreciates the commenter’s support for the rule’s averaging 

time for Hg.

Comment 2: Commenter 17929 states that compliance with the EPA’s standards for PM and Hg are not 

to be based on a single triplicate “independent sample” at a single “randomly select[ed] future test 

condition” where the EPA has claimed it wishes to provide 99 percent confidence, but rather continuous, 

integrative sampling every minute of every day and then averaging for a long-term, 30-operational-day

period. According to the commenter, because the EPA is using a 30-day rolling average rather than a 

triplicate sample, the various measures that the EPA uses to account for variability in a triplicate sample 

are irrelevant and unnecessary. The commenter states that there is no rationale for an “n” of 3 test runs 

in the UPL equation, for an “s2” value, the variance in the single-point emissions data from the top 

units, or for a student’s t-statistic with a 99% confidence level. The commenter asserts that there is no 

rationale at all for the whole UPL calculation unless compliance is to be determined solely based on a 

single triplicate sample, which, the commenter asserts. it is not. 

Response to Comment 2: The agency uses a number of statistical tools so that poorly performing or 

problematic sources can be identified. Basing emissions limits on the average result of three test runs 

and adjusting that result to account for most, if not all, false positive results, then setting a 

commensurate averaging time that accounts for brief, transient emissions spikes, focuses the agency’s 

resources on those poorly performing or problematic sources, instead of penalizing inadvertent 

occurrences. 

Comment 3: Commenter 18421 states that the proposed procedures permit averaging of Hg levels on a 

rolling 30 boiler operating day basis, which could result in days when a given boiler is exceeding the 

NESHAP limit for Hg emissions. According to the commenter, the EPA should adjust the procedures 

for Hg CEMS to ensure continual compliance with the standards of the proposed rule.

Response to Comment 3: The agency disagrees with the commenter, for the procedures for Hg CEMS 

as well as Hg sorbent traps are designed to ensure continuous compliance with the rule. As mentioned in 

a previous response, establishing an averaging time that accounts for brief, transient emissions spikes 
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focuses the agency’s responses on those poorly performing or problematic sources, instead of penalizing 

inadvertent occurrences.

Comment 4: Commenter 17975 notes that emission limits for non-Hg metals are based on a 30-day 

rolling average that would include startups, shutdowns and maintenance events. Commenter 17975 goes 

on to state that the stack tests upon which the agency’s PM standard is based do not reflect emission 

rates that can be achieved over a 30-day period because stack testing is usually designed to assure 

compliance with PM limits that must be met over a three-hour period. The commenter asserts that the 

agency’s 2009 “Clean Air Act National Stack Testing Guidance,” which applies to both MACT and 

NSPS, makes clear that stack testing to determine compliance with these short term limits should be 

conducted under conditions that “are most likely to challenge the emission control measures of the 

facility with regard to meeting the applicable emission standards.”

1

The guidance further explains that 

stack testing should be conducted when boilers are operating at peak capacity, and using the dirtiest fuel 

that it can legally burn because stack testing under these conditions is designed to measure the maximum 

emissions that will occur within any three-hour period over the course of a year or more.2The 

commenter believes that actual emissions averaged over 30 days during periods when units are operating 

at lower capacity with cleaner fuels – are likely to be much lower. 

Response to Comment 4: The comment is moot, as the rule no longer has numeric emissions limits 

applicable during periods of startup or shutdown.

2. Commenters supporting annual compliance periods rather than 30-day periods.

Comment 5: Numerous commenters (17623, 17627, 17714, 17716, 17736, 17757, 17774, 17800, 

17873, 17885, 17902, 17909, 17930, 18018, 18037, 18498, 18831, 19032, 19041, 19114) state that the 

compliance period should be increased from a 30-day rolling average to a 12-month or 365-day rolling 

average. 

Commenters 17623 and 17774 state that the EPA has authority under the CAA to use discretion to shape 

compliance periods and averaging times for MACT limits and suggest that the EPA use a 12-month 

rolling average compliance period rather than the proposed 30-day rolling average period, because a 12-

month rolling average still requires compliance reporting every month but helps limit the number of 

violations resulting from normal seasonal variability in electricity use and associated emissions. 

Commenter 17774 notes that the EPA has used 12-month rolling averages in a number of other MACTs

(e.g., boat manufacturing and magnetic tape).

Response to Comment 5: The agency disagrees with the commenters, noting that for this rule, an 

averaging period of 30 boiler operating days, as opposed to a 12-month or 365-day rolling average, is 

sufficient to account for normal variability, as well as other brief, inadvertent occurrences. 

3. Support annual averaging due to SSM issues.

Comment 6: Multiple commenters (17714, 17627, 17718, 17757, 17800, 17925, 18831) state that the 

proposed rule requires utilities to meet emissions limits at all times including periods of startup and 

shutdown but that the ICR stack testing data did not include startups or shutdowns and that it is 

inappropriate to establish limits that include startups and shutdowns. Commenters 17714 and 18831 

 

1

EPA, Clean Air Act National Stack Testing Guidance 15, 16 (2009).

2

Id.
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recognize that the proposed 30-day rolling averaging compliance period is likely to be helpful in 

addressing the variability in emissions during normal operations, but commenters do not believe a 30-

day period is sufficient to address inclusion of startup and shutdown emissions. Commenter 17714 states 

that absent sufficient stack testing data from real operations that include several periods of unit startup 

and shutdown across the range of units included in the affected source category, the averaging period 

should be increased to 365 days to accommodate periods of startup and shutdown. 

Comment 7: Several commenters (17718, 17627, 17757, 18037, 18539) note that ICR data did not 

encompass the full range of operating conditions including changes in operating variables (i.e., 

pulverizers taken out of service, fuel variability causing changes in control equipment operations, etc.) 

that a unit experiences in the normal course of operation. According to the commenters, the EPA can 

alleviate some of the effect of variability on unit emissions that was not accounted for in the 2010 ICR

testing by allowing annual averaging, while still achieving the same emission reductions. 

Comment 8: Commenter 17925 states that while the EPA indicates the 30-day averaging time addresses 

concerns with startup, shutdown, and malfunction (SSM), according to some utility industry

experiences, an unexpected period where more than one startup/shutdown cycle occurs will significantly

impact compliance with MACT emission limits. According to the commenter, this is understood by 

considering the number of hours involved in a startup and the impact of treatment equipment coming to 

equilibrium with the changing temperatures, gas flow rates and pollutant loadings. 

Comment 9: Commenter 17800 states that the utility industry has limited experience with some of the 

continuous monitoring devices that suggests such spikes can occur and may not be representative of 

stack gas concentrations. According to the commenter, the EPA should allow reasonable exemptions for 

startup, shutdown and malfunction conditions or lengthen the 30-day rolling averaging time. The 

commenter notes that the State of Illinois has adopted a Hg standard that is based on a 12-month rolling 

average. 

Comment 10: Commenter 17736 states that a 30-day rolling average, especially if SSM periods are 

included, makes compliance nearly impossible. According to the commenter, a few hours of ESP 

downtime can destroy a 30-day rolling average. The commenter suggests that the use of a 12-month 

averaging period helps to ensure that compliance results will not be skewed by SSM periods. The 

commenter states that an annualized averaging period is equally effective in reducing the total emissions 

as is a 30-day period. 

Comment 11: Commenter 17758 states that the EPA’s assumption that providing a 30-day averaging 

period will smooth out any emissions increases associated with infrequent startup and shutdown periods 

is predicated on infrequent startup and shutdown periods of short duration. According to the commenter, 

the frequency and duration of startup and shutdown periods varies for different types of units and 

different fuels. The commenter states that the EPA’s assumption that 30-day averaging addresses this is 

unsupported in the record by data from actual unit operations. Accordingly, asserts the commenter, the 

EPA has not demonstrated that 30-day averaging will enable affected units to comply with a 

continuously applied MACT standard. 

Comment 12: Commenter 17774 notes that the use of a 12-month rolling average also assists regulated 

facilities in meeting what are extremely strict standards. For example, the commenter states, one of 

commenter’s PM CEMS is installed on one of the most controlled units in their fleet, which utilizes 

ESP, wet FGD and SCR technology. According to the commenter, the data from these CEMS (see 

attachment to EPA-HQ-OAR-2009-0234-17774-A1.pdf) show that this unit will not consistently meet 
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the proposed 30-day rolling average PM limit. The commenter states that although this unit typically

operates below the proposed limit, there are numerous events (87 exceedances of a 30-day average in a 

2-year time period) where unplanned shutdown/startup events and temporary spikes in PM emissions 

push the 30-day rolling average above the proposed limit. Similarly, the commenter notes that Hg 

CEMS, which are installed on two of their most controlled units using ESP, wet FGD, and SCR

technology show that these units will not meet, on a consistent basis, the proposed 30-day rolling 

average Hg limit. (See attachment to EPA-HQ-OAR-2009-0234-17774-A1.pdf.) According to the 

commenter, while these units usually operate below the proposed limit, there are a number of events (93 

exceedances of a 30- day average in a 2-year period) where unplanned startup/shutdown events and 

unpredictable short term spikes in Hg emissions push the 30-day rolling average above the proposed 

limit. It is commenter’s experience that the cause of these Hg spikes cannot be attributed to any

particular operating parameter or fuel characteristic that the commenter can reasonably control. The 

commenter supports a 12-month rolling average to allow for flexibility in compliance by

accommodating unplanned startup/shutdown events and inevitable spikes in emissions while 

maintaining a high level of environmental integrity. According to the commenter, it also will help to 

limit noncompliance, and therefore promote overall adherence to the rule. The commenter asserts that 

such flexibility will assist in alleviating the very high burden imposed by the proposed Utility MACT. 

Comment 13: Commenter 17873 states that averaging time is important in dealing with non-steady state 

operations and emissions during these periods should either excluded from the compliance 

determination, or the averaging period should be lengthened from a 30-day average to a 12-month 

rolling average, calculated monthly. The commenter offers an example of the practical importance of a

longer averaging period when in 2007, Xcel Energy upgraded the Allen S. King Generating (“King”) 

Plant. The commenter states that this upgrade included the installation of new pollution control 

equipment, modification of the plant heat rejection system, and improvements to the boiler and that the 

new control equipment consisted of a SCR reactor for NOX control, a spray dryer absorber lime-based, 

FGD system for SO2 control, and a pulse-jet cleaned fabric filter for additional PM control. According to 

the commenter, the cyclone-fired boiler burns subbituminous coal and is considered to have BDT

equipment installed, and the King Plant’s SCR and FGD systems require specific flue gas temperatures 

and the boiler to be at specific steam pressures in order to operate properly. According to the 

commenter, given this, King cannot operate the SCR and FGD during periods of startup when flue gas 

temperatures and steam pressures are lower than required. The commenter states that the plant’s current 

permit limits require compliance based on lb/MMbtu of SO2 and NOX using a 30-day rolling average, 

and the commenter’s experience provides strong evidence of the difficult many units will have in 

meeting emission units using that averaging approach. At King, the commenter found that permit limits 

can be met if there is only a single start-up within a given 30-day period, but additional start-ups 

significantly jeopardize compliance for both SO2 and NOX. According to the commenter, it is not 

uncommon for King and other similar units to experience more than one start-up within 30 days in cases 

of forced outages and even planned maintenance. The commenter states that it is unrealistic and 

unreasonable to require compliance with the proposed Hg, HCl, and PM limits on a 30-day rolling 

average basis. 

Comment 14: Commenter 17904 notes that even one of its best performing units (Oak Grove Unit 1), a 

well-controlled unit, would likely not be able to achieve 100 percent compliance. According to the 

commenter, this is because the EPA’s proposed standards have been set too stringently, even for these 

units that were put into commercial operation since 2009 and are equipped with the most advanced, 

commercially available controls. According to the commenter, operating conditions and fuel quality can 

vary over short time periods, and periods of startup and shutdown can also affect emission rates over 

short time periods. The commenter urges the EPA to establish longer averaging times to smooth out this 
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variability. The commenter notes that the EPA has previously explained in response to interagency

comments that its concern with a longer averaging period is that EGU owners may overspend on Hg 

control as the result of over-injection of sorbent or lack of sufficient maintenance. According to the

commenter, apparently the EPA believes this would increase owner or operator risk of non-compliance 

and liability associated with non-compliance, because owners and operators would decide to only check 

control devices once per year. However, the commenter states the length of the compliance period is 

extremely unlikely to drive behavior that is not optimal for owner or operator control of emissions and 

costs. According to the commenter, it is in the best interest of these parties to both minimize the cost of 

control and to maintain compliance. Thus, the commenter states that the EPA’s argument against an 

annual averaging period is not persuasive. According to the commenter, importantly, longer averaging 

times would simply help redress the variability issues. The commenter asserts that the EPA would only

create the same variability problems if it promulgated standards with longer averaging times but at the 

same time applied its UPL variability analysis to set a lower numerical emissions rate. 

Comment 15: Commenter 17774 states that despite the EPA’s statements in the preamble that it will 

provide a measure of leniency with regard to instances of malfunction, they have serious concerns about 

the attendant uncertainty regarding how affected sources may be penalized. According to the 

commenter, in addition, even with a promise of reasonableness from the EPA, regulated entities could 

still be vulnerable to citizen suits. Although the commenter supports the EPA’s proposal that not all 

malfunction events would necessarily result in a violation the commenter asserts that regulated facilities 

would still be subject to significant EPA and state discretion concerning such occurrences and would be 

forced to shoulder the burden of proving an affirmative defense. According to the commenter, these 

requirements distract from efficiently reducing emissions consistent with the EPA policy and as such, 

are not an acceptable approach to periods of malfunction. 

Comment 16: Commenter 19121 states that it appears that the compliance averaging time for 

operational limits is substantially more stringent than for the numerical emissions limitations set under 

the proposed rule. According to the commenter, this will have the effect of further limiting operational 

flexibility. It will also negate the effect of blending in startup/shutdown events so that MACT limits can 

be met. The commenter states that although a given numerical limit could be met on a 30 boileroperating day average, operating limits could not be met on 1-hour, 4-hour, or 12-hour periods blending 

the same events. According to the commenter, continuous compliance should be shown based upon 

emissions monitoring only. 

Comment 17: Commenter 17740 states that the EPA’s conclusion that EGUs “do not normally startup 

and shutdown frequently” effectively, and incorrectly, assumes that all units are operated as base load

units. As the Seventh Circuit recognized in United States v. Cinergy, “[u]tilities operate power 

generation equipment in three general ways: baseload, cycling, and peaking.” 623 F.3d 455, 459 (7th 

Cir. 2010). According to the commenter, non-baseload units start up and shut down frequently, and even 

supposed “base load units” are often, and unpredictably, shut down for unit “trips” (i.e., unplanned 

outages). The commenter asserts that the EPA further assumes that basing the proposed standards on a 

30-day rolling average will account for any increased emissions during periods of startup and shutdown 

and that the EPA made a same faulty assumption in the proposed rule that preceded the Boiler MACT, 

see 75 FR 32,012-13, and rejected it in the final rule, see 76 FR 15,642. According to the commenter, 

the EPA has not demonstrated that the 30-day rolling average will address the substantial operating 

variations among EGUs or even within an EGU. While a number of the MACT pool EGUs are newer, 

well controlled, baseload units, the commenter asserts that the EPA cannot assume that the entire 

universe of coal-fired EGUs, even baseload units, will operate as reliably as newer units. According to 

the commenter, as EGUs age, they tend to experience more forced outages than when they were newly
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constructed; thus, an older EGU with highly efficient controls may not be able to meet a 30-day standard 

in months in which it experiences a number of forced outages. 

Response to Comments 6 - 17: The final rule established work practices for periods of startup and 

shutdown, which addresses this concern about the impact of such periods on compliance with a 30-day

rolling average. See the preamble discussion for further detail on EPA’s rationale for excluding startup 

and shutdown periods from calculating compliance with the emission limits in the final rule. For 

malfunctions, EPA provides an affirmative defense for exceedances that may be caused by such events. 

With these provisions, EPA believes that the concerns raised in these comments are appropriately 

addressed without modifying the general use of 30-day rolling averages for this rule. With respect to the 

one comment about the proposed operating parameter limits being based on a shorter time period, those 

comments are now moot given the lack of operating parameter limits with 12-hour or similar averaging 

periods specified in the final rule.

4. Supporting longer averaging time due to health outcomes.

Comment 18: Several commenters (17716, 17725, 18014, 18498) state that a 30-day rolling average 

compliance period is inconsistent with health effects and that the EPA has presented insufficient 

findings related to the prerequisites for reaching an “appropriate and necessary” determination for 

regulating EGUs under CAA section 112(n)(1)(A). Several commenters (17716, 17725, 18498) state 

that even if one accepts the EPA’s explanation of the potential hazards of the relevant HAP, that 

explanation does not justify compliance on a rolling 30-day basis because no exceedances of HCl, HF or 

HCN standards were documented in the 1998 Utility HAP Report to Congress and no hazards to public 

health have been established based on HAP emissions from EGUs. Commenter 17716 takes exception to 

the EPA’s direction of attention to alleged potential hazards that might result from long-term cumulative 

exposure in the absence of any short-term exposure concerns associated with emissions from EGUs

because, according to the commenter, nothing has been shown to suggest a hazard from 30-day exposure 

to current EGU HAP emissions, and in these circumstances, the value of monthly testing is neither 

apparent nor warranted to protect against a cognizable risk. Commenter 17716 goes on to state that 

absent a showing of need or benefit for monthly testing, yearly testing should be applied as providing 

the requisite level of protection against the inchoate long-term potential risks alleged to be involved.”

Comment 19: Multiple commenters (17627, 17757, 18498, 18539; 18644, 19032, 19041, 19114) state 

that the EPA has not demonstrated why a 30-day averaging period would be more protective to human 

health than an annual period, particularly for Hg emissions, where mass emissions are the key issue. 

Commenter 17725 states that no short-term exposure concerns associated with the ambient level 

contributions from EGU. According to the commenter, if any risk exists at all, the EPA can only suggest 

that they are related to chronic, long-term exposure or related bioaccumulation manifesting over years; 

thus, if the emissions from a source are a little higher one month due to a control upset but are then 

offset by lower emissions during the next month(s), the health impact would be essentially identical to a 

source with no “ups and downs” in the monthly emissions but with the same annual emissions.

Comment 20: Multiple commenters (17716. 17689, 17702, 17718, 17798, 17885, 18037, 18443) state 

that the risk and concern expressed by the EPA centered around long term emissions (e.g., 

bioaccumulations) and that therefore the use of a rolling average that would need to be calculated every

day is unwarranted. Commenters suggest that compliance should only be assessed on an annual basis 

and this would still produce the same control and environmental outcome. Commenter 17798 states that 

the EPA should distinguish and structure requirements based on whether the hazardous pollutant creates 

acute or accumulative impacts. For example, according to the commenter, acid gases are of concern for 
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even very short periods of exposure whereas for metals, including Hg, the impacts are more related to 

the total loading and accumulation in the environment.

Response to Comments 18 - 20: The EPA establishes the limits based on the maximum achievable 

control technology, not the specific timeframe over which health risks from the applicable hazardous air 

pollutants may manifest themselves. The monitoring and testing provisions are established to ensure 

continuous compliance with those standards. The EPA believes that the final rule’s monitoring and 

testing provisions provide a cost-effective means of ensuring continuous compliance with the standards, 

and take advantage of a range of options, with significantly reduced monitoring and testing where the 

margin of compliance indicates a reduced likelihood for potential noncompliance situations.

Comment 21: Several commenters (17716, 17725, 18014, 18498) suggest the use of block averages for 

PM, Hg, and HCl CEMS data as performance indicators, not as direct measures of compliance. 

Response to Comment 21: An Hg CEMS or an HCl CEMS are options for use as the performance test 

method for the applicable Hg and HCl emission limits. If a source is concerned about the use of these 

methods in such a manner, the rule provides for other options (sorbent trap monitoring for Hg and stack 

testing for Hg and Cl). There is no use of a PM CEMS as a direct performance test method for the PM 

emission limit. The PM CPMS is used as an operating parameter monitoring approach to demonstrate 

compliance with a site-specific operating limit expressed in terms of the raw output of the PM CPMS. 

The operating limit aids in ensuring that the source is operated and maintained in accordance with good 

air pollution control practices to minimize emissions so that the source can continue to operate in 

compliance with the emission limit as demonstrated in a periodic stack test. 

Comment 22: Several commenters (17689, 17885, 17930, 18443, 19032) support an annual average 

because most utilities will be using a sorbent trap because Hg CEMS technology is not likely to yield 

accurate and precise measurements. According to the commenters, sorbent traps have approximately 2-

week collection intervals, so should a problem develop with one sample, 30-day compliance 

demonstrations would be extremely problematic. Further, asserts the commenter, as the EPA is well 

aware, a major factor in Hg emissions concentration is the Hg fuel content, so it is quite possible the Hg 

content variability in coal utilized over a 30-day period could determine non-compliance regardless of 

best efforts of a utility to limit Hg emissions. Commenter 17930 states that Hg peaks are often 

experienced month-to-month and the current rule should revise the averaging time to annual to account 

for this variability. 

Response to Comment 22: The agency believes a number of Hg CEMS will be able to provide 

continuous data regarding mercury emissions; should an owner or operator choose to use sorbent traps 

in lieu of Hg CEMS, such an owner or operator will be able to use his knowledge regarding process, 

mercury fuel content, and control device operation to tailor the time the sorbent traps collect samples. 

Note that sorbent traps are allowed a maximum sample time of 15, not 30, days.

5. CEMS uncertainty.

Comment 23: Several commenters (17725, 18014, 18498) state that in reviewing the CEMS data for 

compliance purposes, the EPA would need to take into account the uncertainty of the measurements 

along with the emissions reported for other months. 

Response to Comment 23: The CEMS data will be quality-assured in accordance with the rule 

requirements. Provided the monitoring systems are producing valid, quality-assured data, EPA will use 
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all such data in determining compliance with the emission limits monitored by such a device, in the 

same manner as any other performance test data may be used. These principles have been in use by EPA 

since first promulgating CEMS QA provisions in Appendix F to part 60 in the 1980s. The data under 

this rule will be treated in accordance with those longstanding principles and regulatory provisions.

6. Support annual B/C penalty for rolling 30 days.

Comment 24: Several commenters (17705, 17716, 17725, 18014) state that the 30-day rolling average 

is also inappropriate because it repeatedly penalizes sources for a single emission controls upset because 

if a source experiences very high emissions one day (startup, shutdown, or malfunction) that single day

will affect the 30-day average calculated not only for that day, but also the calculated averages for the 

next 29 days). Several commenters (17725, 18014, 18498) refer to this situation as not only double 

jeopardy but thirty-fold jeopardy. Commenter 17800 states that due to the stringency of the proposed 

standards and the measurement methods required (CEMS and/or emission testing) a short term variation 

in the process could result in a source being out of compliance for a significant period of time. 

According to the commenter, one high magnitude but short duration spike in emissions will impact the 

30-day rolling average for an extended period of time even if a source takes immediate corrective 

action.

Response to Comment 24: See response to Comments 6 through 17, above.

7. Support annual fuel variability.

Comment 25: Several commenters (17702, 17725, 17930, 18018, 18644) state that a 30-day rolling 

average for compliance may be unworkable for some units and is unnecessarily restrictive. The 

commenters state that many coal-fired EGUs are designed to bum a variety of coal types. According to 

the commenters, trace chemical constituents (metal, sulfur, halogen, Hg, chlorine) of coals from the 

same source can vary significantly. The commenters assert that in certain cases, variations in chlorine 

content in a coal may mean the difference between compliance and noncompliance with the EPA’s 

proposed air toxics rule. 

Response to Comment 25: As the rule no longer contains fuel content metals or acid gas operating 

limits but maintains the UPL calculations to account for variability, as discussed elsewhere, the agency

believes a 30 boiler operating day rolling average will be sufficient to account for normal variation in 

fuels for sources that use a CEMS to demonstrate compliance with the standards in the final rule.

Comment 26: Commenter 18443 states that a major factor in Hg emissions concentration is the Hg fuel 

content. According to the commenter, the currently proposed Hg limit does not account for the 

variability of Hg in the fuel or varied plant operations and draws only on 40 hand-picked best 

performing units, and it is possible that the Hg content in a particular coal shipment could be high 

enough over a 30-day period to exceed the Hg limit despite the best efforts of a utility to limit Hg 

emissions. 

Response to Comment 26: The agency disagrees with the commenter and notes that the Hg emissions 

limit was established using data from the best performing sources that were adjusted statistically using 

the UPL procedure to account for variability. Properly maintained and operated Hg control devices 

should enable source owners or operators to meet the rule’s Hg emissions limit.

8. Suggested alternative compliance approaches.
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Comment 27: Commenters 17928 and 18644 state that the 30-day averaging time is too short to account 

for transient events (startup, shutdown and upset conditions), and variability of CEMS data. In order to 

facilitate the practical use of facility averaging provisions outlined in the proposal, the commenters

recommend that a minimum 90-day averaging time be considered, to account for uncontrollable events 

and emissions variability. Commenter 17928 notes that there has been little real world experience with 

HCl, PM and Hg CEMS data in general with EGUs and with the lower measurement levels that will be 

needed to demonstrate compliance. The commenter is concerned that the proposed averaging time may

not be long enough to be useful for a facility averaging plan, since an extended maintenance outage of 

the over-controlled units at a facility could force the other units in an averaging plan to be out of 

compliance. 

Response to Comment 27: See response to Comments 6 through 17, above.

Comment 28: Commenter 19121 encourages the EPA to reconsider increasing either the averaging time 

for limits or the actual PM or Hg limits. According to the commenter, based on recent testing, the 

commenter’s unit is proven to be one of the lowest emitters of Hg in the nation. The commenter notes 

that the State of Utah has set a Hg limit that is more strict than that the EPA is proposing but that the 

State rule requires an annual averaging period. According to the commenter, this is an example of 

balance between limits and limits averaging that would still be protective of human health and the 

environment, and meet the requirements of NESHAPS. 

Response to Comment 28: As mentioned in earlier responses, the agency believes the rule’s averaging 

time appropriately accounts for brief, transient emissions spikes enabling the agency to focus its 

response on poor performing or problematic sources, instead of penalizing inadvertent occurrences. 

Given that the commenter’s EGU appears to meet a more stringent state Hg standard, it should have no 

problem meeting the standard contained in the rule.

9. Requests for clarification/explanation.

Comment 29: Commenter 17638 urges the EPA to clarify that a “30 operating day rolling average” is 

determined by averaging all applicable hours in the 30-day period. According to the commenter, in some 

cases, the proposed rule appears to indicate that a new daily average would be calculated each day and 

then 30 daily averages would be averaged to determine the 30-day average, while other language 

appears to indicate that all of the hourly emissions for the preceding 30 boiler operating days would be 

averaged to determine the 30-day rolling average. According to the commenter, defining a 30-day period 

based on daily averages is not fair to units that frequently cycle on and off and could weight a 15-minute 

period equally to a 24-hour period. 

Response to Comment 29: The final rule clarifies that the average is based on all valid hourly averages 

during each 30-day rolling average period. Hourly averages are not summed to a daily average as an 

intermediate data value for purposes of determining each 30 boiler operating day average. 

Comment 30: Commenter 18034 states that the rule must be revised to provide for proper calculation of 

emissions during a malfunction. The commenter observes that section 63.10005(l) only applies to 

startup and shutdown operations. According to the commenter, if power production during a 

malfunction approaches zero, calculated output-based emissions will spike exponentially. The 

commenter states that any malfunction causing power production to cease completely for more than an 

hour while the boiler is in operation will result in the calculated emissions becoming infinite for that 

hour as will the calculated rolling average that includes that hour and that the 30 boiler operating day 
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average does not address this issue, because Appendix A, Section 6 (76 FR 25144), Equation A-4 

requires Hg emissions to be calculated on an hourly basis before calculating the 30 boiler operating day

average according to Equation A-5. According to the commenter, this issue does not appear limited to 

Hg emission calculations, as proposed section 63.10010 requires that the 30-boiler-operating-day rolling 

average for other pollutants be determined as the average of all the hourly emissions data for the 

preceding 30 boiler operating days. The commenter indicates that the proposed rule does not appear to 

contemplate malfunctions in the power production side of a facility and under some circumstances 

require sources to divide by zero when calculating emissions.

The commenter suggests that the calculation for compliance with the 30 boiler operating day average for 

the proposed NESHAP rule could be revised to be consistent with how the EPA has proposed 

demonstrating compliance with proposed revision to 40 CFR 60 subpart Da, i.e., the sum total emissions 

for the 30 boiler operating days divided by the sum total output over the 30 boiler operating days. 

According to the commenter, as the EPA has proposed the rule, sources would be automatically in 

violation of the rule for even miniscule emission rates during a malfunction in which power production 

ceased for more than an hour.

Commenter 17755 states that a boiler is a separate unit from the generator and can be operated 

independently, and the boiler units can and do combust fuel without producing electricity (i.e., during 

SSM and maintenance periods). The commenter notes that the emission limits in lb/MWh could only

apply when the generator is producing electricity (MWh), that if not producing electricity then the MWh 

would be zero and would produce an invalid lb/MWh ratio, and that most excess emissions occur during 

SSM and maintenance when generator is not operating, and the commenter questions whether emissions 

that occur when the generator is not producing electricity would be unregulated for these new sources.

Response to Comment 30: Sources are required to comply with the standards at all time, including 

periods of malfunction. To the extent a source experiences a malfunction that causes the boiler to shut 

down, the emissions during that period must be included in the 30-day averaging period and, if the 

malfunction causes the source to exceed the limit for the applicable 30-day averaging period, the source 

is in noncompliance and subject to penalties unless the source demonstrates that the affirmative defense 

applies.

Comment 31: Commenter 17705 recommends that the final rule define “boiler operating day” as a 24-

hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours to 

ensure that compliance is always based on at least 720 hours of operation. Commenter 17705 contends 

that the EPA should specify a minimum number of operating hours necessary to calculate a 30-day

rolling average; if the requisite number of hours is not obtained, the EGU should have the option of 

combining data from that period with the data from the next 30 boiler operating day period until the 

requisite number of hours is obtained. According to the commenter, the EPA specified a similar 

procedure in the 40 CFR Part 60, subpart Da provisions for calculation of a 24-hour average in section 

60.48Da(g)(3), which requires a minimum number of valid hours to calculate an average. 

Response to Comment 31: The EPA disagrees. See responses to comments under Comment Code 

5A12 of this document for further discussion on data availability. 

Comment 32: Commenters 17740 and 17767 request the EPA to provide clarification to address the 

following factors: 1) the number of valid data points or minutes required for a valid operating hour, 2) 

the number of valid data points or minutes required for a valid operating day, and 3) the number of valid 

data points required for a valid 30-day average. 
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Response to Comment 32: Section 63.8(g)(2) provides the general rules for hourly averages for all 

CEMS. There is no minimum for a valid operating day, as an operating day is a day in which fuel is 

combusted and is not dependent on obtaining valid monitoring data in that day. There is no minimum 

number of data points for a 30-day average. See responses to comments under Comment Code 5A12 of 

this document for further discussion on data availability. 

Comment 33: Commenter 18023 requests clarification with respect to the method to calculate the 30 

operating day rolling average. According to the commenter, in some cases, the proposed rule appears to 

indicate that a new daily average would be calculated each day and then 30 daily averages would be 

averaged to determine the 30-day average, while other language appears to indicate that all the hourly

emissions for the preceding 30 boiler operating days would be averaged to determine the 30-day rolling 

average. The commenter provides some examples of their confusion, and asserts that:

 Table 8 in the proposed rule suggests that the 30-day rolling average is calculated as the average 

of 30 individual boiler operating day values (Proposed Table 8 (7.b) (convert “hourly emissions 

concentrations to 30 boiler operating mg/dscm values”).

 Proposed section 63.10010(g)(5), however, specifies that a 30 boiler operating day rolling 

average is calculated as “the average of all of the hourly particulate emissions data for the 

preceding 30 boiler operating days.” 76 FR 25,112.

According to the commenter, several other references, e.g., 76 FR 25,097, 25,111, suggest that the EPA 

intends the 30 boiler operating day rolling average to be based on all the hours in a 30-day period rather 

than the 30 daily averages. The commenter urges the EPA to clarify that a 30 boiler operating day is 

based on the average of all applicable hours in the 30-day period. According to the commenter, 

finalizing the rule based on the average of 30 daily averages would be challenging if the unit frequently

cycles on and off, and further, the daily averaging approach would not be fair because it would weight a 

15-minute period (i.e., one boiler operating day) as being equal to a 24-hour period (i.e., also one boiler 

operating day). 

Response to Comment 33: The final rule clarifies that the average is based on all valid hourly averages 

during each 30-day rolling average period. Hourly averages are not summed to a daily average as an 

intermediate data value for purposes of determining each 30 boiler operating day average.

Comment 34: Commenter 17927 requests clarification of the averaging periods which will be used to 

demonstrate continuous compliance with the applicable emission limits in the proposed rule. 

Response to Comment 34: Averaging periods apply for emission limits where a CEMS is used to 

determine compliance and for the sole remaining operating limit where a PM CPMS is used. In these 

situations, the final rule uses a consistent 30 boiler operating day rolling average, based on all valid 

hourly averages during each successive rolling 30 operating day period.

Comment 35: Commenter 17681 states that section 63.10031(d)(2) of the proposed rule appears to 

require a description of the deviation in the compliance report. Commenter 17681 asks for clarification 

of when compliance is determined within the proposed 30-day compliance period; the commenter asks 

“If an event occurred on December 31 and the 30-day average starting on December 31 and ending on 

January 30, would that deviation be required to be reported in the January 31 compliance report? And if 

so, how would a facility know that such an event would deviate from the 30-day average until the end of 

that 30-day averaging period unless the deviation was extreme?”
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Commenter 17730 notes that the EPA has proposed a new averaging time for the emission standards as 

a 30 boiler operating day average which appears to be different than the historical use of the 30-day

rolling average and requests that the EPA provide an explanation of why the EPA is seeking to change 

the manner in which the averaging times for emission standards have historically been calculated 

at EGUs. Commenter 17730 believes that the EPA should not impose a more restrictive averaging time 

for the proposed emission standards. 

Response to Comment 35: The rolling average uses a 30-day rolling period as calculated at the end of 

each successive operating day, based on all valid hourly averages in the preceding 30 boiler operating 

days. In terms of reporting, a deviation that occurs in January would not be included in the report that 

must be submitted by the end of January, as that report covers the time period of July 1-December 31.

Comment 36: Commenter 17775 states that once the operating limit is established, proposed section 

63.10010(g)(5) specifies that a 30 boiler operating day rolling average is calculated as “the average of 

all of the hourly particulate emissions data for the preceding 30 boiler operating days” (citing 76 FR

25,112/2). According to the commenter, proposed Table 8, on the other hand, suggests that the 30-day

rolling average is calculated as the average of 30 individual boiler operating day values (citing proposed 

Table 8 (7.b) (convert “hourly emissions concentrations to 30 boiler operating mg/dscm values”)). 

According to the commenter, calculating and averaging separate boiler operating day values would 

make the limit much more stringent for any period that includes a startup or shutdown. According to the 

commenter, regardless of which the EPA intended to propose, neither has been sufficiently supported.

Response to Comment 36: The final rule clarifies that the 30-day average is based on all valid hourly

averages from the PM CPMS in the preceding 30 boiler operating days, with no intermediate daily 

values used to determine the 30-day average.

Comment 37: Commenter 17796 suggests that the Hg compliance metric be stated succinctly in section 

63.10010(f). According to the commenter, it is clearly stated in section 63.10010(g)(5) that compliance 

is based upon a 30-day rolling average emissions rate on a daily basis. However, the commenter was 

unable to find this language for the Hg compliance limit for CEMS. The commenter asserts that Section 

63.10010(f) refers the reader to Appendix A, but Appendix A does not state the compliance metric. 

Response to Comment 37: See Section 6 of Appendix A to the final rule for the calculation procedures.

Comment 38: Commenter 17807 states that the rule proposes to use heat-input-weighted emission 

limits based a 30-day rolling average. According to the commenter, the rule is not clear on how to 

calculate the 30-day rolling averages. The commenter proposes calculating a daily total for each 

constituent, summing the mass and heat input and then calculating the rolling average. 

Response to Comment 38: The final rule clarifies that the average is based on all valid hourly averages 

during each 30-day rolling average period. Hourly averages are not summed to a daily average as an 

intermediate data value for purposes of determining each 30 boiler operating day average. See also 

Section 6 of Appendix A to the final rule for Hg calculation procedures.

Comment 39: Commenter 17820 states that the 30-day rolling average limits should contain at least 30 

full days of operation. 

Response to Comment 39: The EPA disagrees. A boiler operating day is a day in which any fuel is 

combusted, and each such day is a day for purposes of calculating the average.
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Comment 40: Commenter 18014 states that Table 8 requires the source is to convert “hourly emissions 

concentrations to 30 boiler operating mg/dscm values,” which suggests that compliance is assess based 

on the average of 30 individual daily values. However, according to the commenter, section 

63.10010(g)(5) states that 30-day rolling average is calculated as “the average of all of the hourly 

particulate emissions data for the preceding 30 boiler operating days.”

Response to Comment 40: See response to Comment 33, above.

Comment 41: Commenter 18023 requests clarification on the averaging times for operational 

parameters. According to the commenter, the EPA has provided four inconsistent descriptions as to how 

the operational parameter limits would be set (i.e., 90 percent of the test average, the lowest 1-hour 

average, the 12-hour block average, and the average of three minimum values). According to the 

commenter, the electric utility and industry has no way of knowing which of the definitions the EPA 

intended to propose. According to the commenter, the EPA must adopt a definition that provides 

sufficient flexibility to account for changes in unit operations. The commenter states that the average of 

three runs and the lowest 1-hour average are clearly unreasonable because, by definition, there will be 

values during the testing that are above and below the average and, on a longer term basis, these values 

may vary even more. 

Response to Comment 41: See response to Comment 36 above for the only remaining operational 

parameter that applies under the final rule.

10. Rule language corrections.

Comment 42: Commenter 17775 believes that the reference to the 30 boiler operating day compliance 

period for PM in proposed Table 8 (7.b) is inconsistent with the reference in proposed section 

63.10010(g)(5) because proposed Table 8 (7.b) suggests that only 30 daily values are averaged while 

section 63.10010(g)(5) indicates that up to 720 hourly values are averaged. Commenter 17775 believes 

that calculating and averaging separate boiler operating day values would make the limit much more 

stringent for any period that includes a startup or shutdown and concludes that “[R]egardless of which 

EPA intended to propose, neither has been sufficiently supported. “

Response to Comment 42: The final rule clarifies this issue; see response to Comment 33, above.

Comment 43: Commenter 17638 requests a mass-based alternative compliance option by converting the 

existing rate-limit (pounds per million Btu) to a mass-limit (pounds per hour with an annual average), 

based on the unit’s permitted heat input. The commenter notes that Florida has recent positive 

experience in utilizing mass-based limits in permits, achieving substantial environmental benefits while 

lessening the burden on the source. According to the commenter, the EPA also has extensive experience 

developing NESHAP compliance requirements on a mass basis, having promulgated at least six such 

regulations (40 CFR part 63, subparts MMM, XXX, GGGGG, GGGGGG, LLLLLL, and NNNNNN). 

The commenter further notes that mass rate were used in the modeling supporting the rule and well as in 

setting the standards (using stack tests date). 

Response to Comment 43: While the EPA appreciates the suggested alternative, we have not 

conducted analyses to assess what specific limits would be necessary to meet MACT statutory

requirements under this alternative scenario and believe that the proposed format provides an adequate 

means of limiting emissions in accordance with the statutory provisions and in such a way as can be 
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monitored and tested for compliance. Thus, the EPA does not believe this type of alternative is 

necessary or supported at this time.

Comment 44: Commenter 17881 believes that Equation 5 may not always yield an accurate 12-month 

rolling average emission rate when there is a large disparity in the total monthly heat input (or steam 

output) across all units included in the averaging plan. According to the commenter, specifically, 

Equation 5 gives each monthly average emission rate used to calculate the 12-month rolling total an 

equal weighting (i.e., 1/12, or 8.33 percent). The commenter suggests that it would be more accurate if 

the 12-month rolling average emission rate was calculated as follows:

Where, Eavg = 12-month rolling average emissions rate (lb/MMBtu heat input; lb/TBtu for Hg).

Eri =

Average weighted emission level for month i for PM, HCl, HF, non-Hg HAP metals or 

Hg, in units of lb/MMBtu (lb/TBtu for Hg) of heat input, calculated consistent with 

63.10009(f)(1).

Hbi =

Total heat input for all units included in the averaging plan for month I, in units of 

MMBtu. 

Response to Comment 44: The rule replaces a 12-month rolling average with a quarterly weighted 

average. As the monthly weighted average (ERi) already makes the adjustment suggested by the 

commenter, per Equation 3 or Equation 4, the Agency sees no reason for keeping Equation 5, so it has 

been removed from the rule.

Comment 45: Commenter 17881 requests clarification, with respect to Equations 1-5, as to the value of 

“Er” in those cases where the “performance test” consists of the use of a CEMS to determine a 30-day

rolling average emission rate. According to the commenter, as 30-day rolling averages at the end of a 

given month could include several days worth of data from prior months (assuming that operation is not 

continuous), there is a high degree of likelihood that the 30-day rolling average emission rate at the end 

of a month will not line up with the associated calendar month, thereby introducing a disconnect 

between the average emission rate and heat input value used for weighting purposes. The commenter

states that Equations 1 – 4 should specify procedures for reducing CEMS data into average values for 

purposes of the “Er” term. The commenter suggests a simplistic approach would be to average all valid 

1-hour emission rates determined during each calendar month for purposes of Equations 3 and 4. 

Response to Comment 45: The commenter’s suggestions regarding use of emissions averaging 

between or among EGUs with CEMS, CPMS, or sorbent traps and EGUs that rely on emissions testing 

(per Table 5) are incorrect: Emissions averaging can be used only by those EGUs that rely on emissions 

testing. While there is no need to account for CEMS data in emissions averaging, the rule will clarify

that emissions averaging can be used only by those EGUs that rely on emissions testing.

Comment 46: Commenter 17621 states that individual measurements that comprise the baseline data 

pool are incompatible with anticipated compliance measurements. According to the commenter, the 

EPA approach (as stated on FR 25041) to calculation of a UPL is based on an average of three 

compliance test runs, each of which follows the underlying measurement protocol that was used for the 

component baseline data. According to the commenter, compliance options in the proposal typically are 

at variance with this requirement. The commenter asserts that most require compliance to be determined 

on a 30-day rolling average using a CEMS. According to the commenter, it should be realized that the 

statistical properties of these two monitoring approaches are different. (See statistical study provided in 

Appendix D.)
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Response to Comment 46: The commenter appears to confuse the agency’s standard setting activities 

(that include UPL calculations) with collection of CEMS data. The compliance options that rely on use 

of a 30 boiler operating day rolling average are not at odds with the statistical approach for determining 

the emissions limit. Use of the statistical approach provides a tangible measure of variability that is a 

component of the emissions limit, while use of CEMS supplies data that for well-operated EGUs are 

expected to be equivalent or less than the emissions limit 99 of 100 times. As mentioned in earlier 

responses, establishing an emissions limit in this fashion allows the agency to focus on the poorly 

operated or problematic EGUs. 
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5A03 - Testing/Monitoring: Fuel analysis methods

Commenters: 17316, 17386, 17402, 17621, 17715, 17718, 17722, 17725, 17730, 17731, 17754, 17758, 

17760, 17775, 17781, 17796, 17800, 17801, 17807, 17808, 17816, 17820, 17821, 17881, 17902, 18014, 

18015, 18025, 18428, 18447, 18483, 18498, 19033, 19114, 19121, 19536, 19537, 19538

1. Exempt natural gas.

Comment 1: Commenters 17316 and 17386 request that the EPA exempt the fuel analysis of natural gas 

for dual fuel-fired units that fire gas. According to the commenters, in particular, in sections 

63.10005(c)(1) and (2), and 63.10006(s), the provisions requiring a fuel analysis for “each type of fuel 

burned” should explicitly exclude pipeline natural gas. The commenters state that the exemption should 

be based on natural-gas-fired units being both insignificant source of HAP and otherwise being exempt 

from the rule. The commenters also suggest that section 63.10005(c)(4), which provides an exemption 

from the performance of an initial fuel analyses if a unit burns a single fuel type, be extended to 

exemption any unit which burns only one fuel type, aside from pipeline natural gas (i.e., burns 2 fuel 

types, but one is pipeline natural gas).

2. Initial compliance fuel analysis.

Comment 2: Commenter 17316 states that that it is unclear why units that burn a single fuel type are 

exempt from conducting an initial compliance fuel analysis, which appears to be the intent of section 

63.10005(c)(4). The commenter believes the rule seems to be saying that units which intend to 

demonstrate compliance by fuel analysis are not required to conduct an initial compliance 

demonstration.

Comment 3: Commenter 17775 requests the EPA clarify the requirements for EGUs combusting single 

fuels. Although proposed section 63.10005(c)(4) suggests that such EGUs are exempt from any initial 

fuel analysis, proposed section 63.10011(c)(1) only appears to exempt such EGUs from the requirement 

to determine the fuel “mixture” that would result in the maximum emission rates. The commenter

assumes the EPA intended liquid oil-fired EGUs demonstrating compliance through fuel analysis to 

conduct an initial demonstration using fuel analysis, but that such EGUs that combust only a single fuel 

type are not required to make any other demonstrations regarding that sample. The commenter believes 

the EPA should confirm that understanding in the final rule and provide consistent language in the two 

provisions.

Comment 4: Commenter 17722 notes that section 63.10005 exempts units firing “a single type of fuel”

from the fuel sampling and analysis requirements. According to the commenter, the rule does not define 

what constitutes a single fuel. The commenter questions if the definition is as broad as coal, natural gas, 

and fuel oil, or more narrowly defined by ranks (e.g., bituminous, subbituminous, lignite) or even more 

narrowly ranked by mine location or even coal seam.

Comment 5: Commenter 17775 suggests for EGUs opting to demonstrate compliance using fuel 

analysis (as opposed to performance testing), the EPA should clarify or remove the reference to 

operating limits. The commenter believes proposed section 63.10005(c) inexplicably refers to 

requirements to establish operating limits under section 63.10011 and Table 8. According to the 

commenter, the only sections of section 63.10011 or Table 8 that could have any applicability to EGUs

complying through fuel analysis are the fuel input emission rate calculations in proposed section 

63.10011(c) and the fuel pollutant content restrictions in Table 8 (6). The commenter suggests the EPA 
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make clear in the rule that the other operating limits in those provisions do not apply to units 

complying through fuel analysis.

Comment 6: Commenter 17881 notes that 63.10011(c) is unclear how fuels not covered by the rule 

(i.e., natural gas) factor in when co-fired with fuels which are subject to the rule.

Comment 7: Commenter 17881 notes that due to the limited number of samples required (3), the P90

calculation in section 63.10011(c) could show a value much greater than the arithmetic average. The 

commenter believes if this potential HCl content is greater than the limit, the facility should have the 

option of periodically collecting fuel samples and showing that the actual results meet the limit.

Comment 8: Commenters 18014 and 18498 suggest EPA clarify fuel sampling provisions for multiple 

fuels. According to the commenters, for units firing a single fuel type, fuel sampling and analysis is not 

required for supplemental fuels used only for startup, shutdown or for maintaining flame stability per 

§63.10005(c)(5)). The commenters believe this exemption does not appear to apply to units that fire 

multiple fuel types or blends and suggest EPA clarify this exemption in the final rule.

3. Fuel sampling procedures.

Comment 9: Several commenters (17316, 17386, 17881) state the fuel sampling procedures specified in 

section 63.10008(c) and (d) appear to be applicable only to solid fuels and that this section should clarify

that these procedures are not applicable to oil (liquid) fuel sampling. Commenter 17881 requests that the 

EPA clarify if there are any requirements for non-solid fuels; for example, it is not clear for a unit cofiring natural gas if fuel sampling of the natural gas required.

Comment 10: Commenters 17316 and 17386 suggest that fuel sampling for oil-fired EGUs follow 40 

CFR 75 Appendix D provisions, which reference ASTM D4057 sampling procedures.

Comment 11: Commenter 17402 suggests the EPA clarify that fuel contaminant levels calculated 

during performance tests will be used to calculate maximum contaminant levels for fuel content, 

including allowance for some fuel variability, and not dictate the fuel operating limit directly as an 

average. According to the commenter, fuel sampling is necessarily a point-in-time sample, while fuel 

content varies. As a result, asserts the commenter, by setting a standard based on a simple average, the 

EPA could unnecessarily subject roughly half of all facilities to compliance penalties for using fuel with 

the identical variability present during the performance tests – i.e., those for which the fuel sample was 

taken from an above-average portion of the fuel. According to the commenter, instead of effectively

encouraging facilities to burn the most contaminated fuel they can during performance testing, the EPA 

should grant facilities with low emissions a safety margin to reflect variability in fuel and operations. 

The commenter suggests that the EPA specify that facilities may use fuel contaminants to set a percent 

reduction for the system, and thus establish a fuel contaminant level (with adequate safety margin) 

which facilities may use to comply without conducting periodic performance tests as frequently.

Comment 12: Commenters 17730 and 17800 believe the EPA should revise section 63.10008 to make 

clear that the sampling and compositing procedures in Table 6 may be used. According to the 

commenters, proposed section 63.10008 requires fuel analysis tests according to the “procedures in 

paragraphs (b) through (e)” and Table 6, and paragraphs (c) and (d) specify minimum sampling 

procedure and compositing procedures. However, assert the commenters, Table 6 also provides 

sampling methods that can be used in lieu of those in paragraph (c) and some of those procedures 

address compositing. For example, state the commenters, ASTM D2013, which the EPA proposes to 
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require for “preparation of composited fuel samples,” also contains procedures for “Preparation of 

Composite Samples to Represent Lot-Size (or Consignment-Size) Quantities of Coal.” The commenters

state the EPA should make clear that any procedure identified in Table 6 can be used in lieu of 

procedures in paragraphs (c) and (d).

Comment 13: Commenter 17722 notes that section 63.10011 requires fuel samples to be collected and 

analyzed during initial performance testing that “establishes maximum fuel pollutant input levels.” The 

commenter believes there is a very low probability that one composite coal sample will contain the 

maximum concentration of every non-Hg HAP metal that could be expected while combusting coal –

even if that coal is from the same mine. Accordingly, the commenter believes it is impossible to 

demonstrate compliance with section 63.10011. According to the commenter, a typical coal 

specification sheet will provide the range, average, and standard deviation of the metals in the coal, and 

it is not unusual for the standard deviation to be 10 to 15% of the average value.

Comment 14: Commenter 17881 notes that section 63.10008 requires the collection of three fuel 

samples, which seems to be a one-time requirement, whereas the reference to section 63.10008 within 

section 63.10011(c) would suggest that the provisions be used for on-going periodic sampling.

Comment 15: Commenter 19033 notes proposed regulation section 63.10008 and Table-6 requires fuel 

sampling for non-Hg metals, regardless of whether or not the EGU operator elects to comply using the 

PM emission limit. The commenter believes a more representative indicator of fuel content that will 

impact PM emissions is ash content. In the event the EPA does not accept its recommendation that fuel 

sampling only be required in the absence of CEMS, the commenter recommends that Table 6 be 

amended to include an option to sample for ash content, if the EGU operator elects to comply using the 

PM emission limit.

Comment 16: Commenter 19033 notes that proposed regulation section 63.10011 (b)(3) specifies that a 

maximum non-Hg metals HAP input be established. According to the commenter, that requirement is 

valid if the EGU operator elects to comply with the non-Hg metals HAP emission limit and does not 

operate a PM CEMS. However, in the event the EPA does not accept its recommendation that fuel 

sampling only be required in the absence of PM CEMS, the commenter believes the regulation should 

allow establishment of maximum ash content, if the EGU operator elects to comply with the PM 

emission limits. The commenter recommends that section 63.10011(b)(3) be amended as follows:

“lf you elect to comply with the non-Hg HAP metal emission limits, you must establish the 

maximum non-Hg HAP metals fuel input level (HAP metal input) during the initial performance 

testing using the procedures in paragraphs (c)(3)(i) through (iii) of this section. lf you elect to 

comply with the PM emission limits and do not operate a PM-CEMS, you must establish the 

maximum ash content fuel input level during the initial performance testing using the 

procedures in paragraphs (c)(3)(i) and (iii) of this section.”

In this same connection, the commenter recommends that 63.10021(a)(2) be amended as follows:

(2) As specified in Sec. 63.10031(c), you must keep records of the type and amount of all fuels 

burned in each EGU during the reporting period to demonstrate that all fuel types and mixtures of 

fuels burned would either result in lower emissions of HCl, HF, SO2, non-Hg HAP metals(if you 

choose to comply with the non-Hg HAP metals emission limit), or Hg, than the applicable 

emission limit for each pollutant (if you demonstrate compliance through fuel analysis and do not 

operate a CEMS for the pollutant or surrogate), or result in lower fuel input of chlorine; fluorine, 
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sulfur, non-Hg HAP metals (if you choose to comply with the non-HG HAP metals emission 

limit), ash (if you choose to comply with the PM emission limit), or Hg than the maximum values 

calculated during the last performance tests (if you demonstrate compliance through performance 

stack testing).

Comment 17: Commenter 19121 believes the EPA is overly prescriptive concerning performance test 

fuel sampling. Specifically, at section 63.10008(c) and (d), the commenter believes the EPA is not 

recognizing other methods for collecting and preparing representative fuel samples. The commenter 

states that ASTM has developed methods that utilize automated and continuous sampling systems, and 

such equipment is present at many coal plants, and the systems are bias tested against ASTM standards. 

The commenter also notes there are also ASTM approved sample preparation standards utilizing riffle, 

grinding, and drying equipment designed to meet applicable ASTM methods.

4. Fuel sampling requirements for sources with CEMS.

Comment 18: Multiple commenters (17402, 17725, 17800, 17820 18014, 18498) believe that the EPA 

did not intend to require sources using a CEMS to also conduct fuel sampling, but the EPA should 

clarify this issue in the final rule.

Comment 19: Commenter 17402 requests that the EPA revise section 63.10007 to indicate that fuel 

sampling is not required when the applicable HAP (or surrogates) are monitored using a CEMS. The 

commenter requests that the EPA modify the rule to explicitly state that sources using CEMS for 

compliance for a particular pollutant are exempt from all fuel sampling requirements for that pollutant. 

According to the commenter, the text of the rule appears to indicate that fuel sampling requirements 

apply only to those units that demonstrate compliance through “performance testing” for a particular 

pollutant. The commenter states that as each unit must conduct initial “performance testing,” this could 

imply that facilities complying by using CEMS must also be required to carry out fuel analysis. The 

commenter believes that the EPA did not intend to require sources using a CEMS to also conduct fuel 

sampling, but the EPA should clarify this issue in the final rule.

Comment 20: Several commenters (17725, 17820, 18014, 18498) believe the fuel sampling 

requirements for units using a CEMS to demonstrate compliance are unclear because of conflicting 

language in the proposed rule. According to the commenters, the rule does not explicitly state that 

sources using a CEMS for compliance for a particular pollutant are exempt from all fuel sampling 

requirements for that pollutant. However, the commenters do not believe that the EPA intended to 

require sources that demonstrate compliance via CEMS to also have to perform fuel sampling and 

analysis. The commenters note that fuel sampling is certainly required for oil-fired sources that 

demonstrate compliance through fuel analysis, and section 63.10011(b) specifies that sources that 

demonstrate compliance through “performance testing” for a particular pollutant must also perform fuel 

sampling to “establish maximum fuel pollutant input levels.” According to the commenters, while not 

formally defined, the rule generally implies that “performance testing” refers to emissions (stack) 

testing. However, note the commenters, in section 63.10005(a) the EPA states that “performance 

testing” may also consist of CEMS operating data, thereby creating ambiguity in whether other parts of 

the rule that pertain to units using stack test data to comply also apply to those units using a CEMS for 

compliance.

Comment 21: Commenter 17800 believes it is unclear from the way the regulation is written if EGUs

complying with CEMS systems must meet fuel input limits established during the performance testing. 

The commenter cites section 63.10011(b), noting that since all EGUs are required to demonstrate initial 
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compliance with each emission limit “through performance testing,” and the proposed rule defines 

“performance testing” to include the first 30 operating days of CEMS data, the proposal appears to 

require that EGUs meet fuel input limits regardless of the “performance testing” option they choose. 

According to the commenter, the proposal appears to require that EGUs meet operating limits for all 

relevant control devices and load regardless of the “performance testing” option they choose.

Comment 22: Commenter 17758 notes that proposed section 63.10008 lays out in detail a fuel sampling 

and analysis regimen; however, none of the fuel information is meaningful or relevant when either all of 

the regulated HAP or their surrogates are continuously monitored. The commenter notes that proposed 

section 63.10008(a) contains an “as applicable” clause, but its meaning is never explained.

Comment 23: Commenter 17881 suggests that section 63.10011(b)(2) not apply to units with Hg 

CEMS (i.e., categorically all solid fuel-fired units, as these units are required to install Hg CEMS). The 

commenter also believes the Hg content of coal may not correlate to the Hg emissions at the stack, 

therefore trying to establish a maximum Hg fuel input level in the fuel prior to testing is not a good 

indication of what will actually be emitted when utilizing the equations. According to the commenter, 

for example, the form of the Hg emissions from coal combustion (i.e., elemental, oxidized and particle 

bound) can have a major impact upon Hg emissions, as these forms are controlled to varying degrees by

prevalent control technologies. The commenter states that certain coals tend to favor elemental forms of 

Hg emissions as opposed to oxidized forms of emissions. Thus, according to the commenter, you could 

have a case where a coal with a high Hg content also results in a high percentage of Hg emissions in the 

oxidized and particle bound forms. According to the commenter, such a coal may yield lower Hg stack 

emissions than a coal with a lesser Hg content but that yields a much higher percentage of elemental Hg 

emissions (as this form of Hg is not as readily removed in prevalent control technologies).

Comment 24: Commenter 18015 requests that the EPA clarify the applicability of the fuel analysis 

requirements; specifically, the commenter recommends that the EPA state in the preamble and the final 

rule that fuel analysis is not required for units that use CEMS to continuously comply with emission 

standards. According to the commenter, should the EPA agree with the commenter’s request to allow a 

percent removal MACT standard approach (discussed separately), then the Hg content of the coal will 

have to be determined in a routine manner.

Comment 25: Commenter 17881 believes it is not clear if the requirement contained in section 

63.10021(a)(8) applies to solid fuel-fired EGUs which are demonstrating compliance with the PM 

surrogate. The commenter believes that is should not apply, as a CEMS is installed to verify continuous 

compliance, and that this paragraph makes little sense for units without PM CEMS that are required to 

test monthly or bi-monthly; thus, the tests would already be conducted within the frequency (60 days) 

specified in the paragraph.

5. Fuel sampling requirements for single-fuel units that comply with one or more standards based 

on stack testing.

Comment 26: Commenters 17402 and 18498 believe that the EPA should allow facilities to conduct 

more frequent fuel sampling to show continuing compliance based on their performance tests instead of 

using CEMS.

Comment 27: Several commenters (17402, 17820, 18498) believe the rule is unclear as to whether units 

that fire a single type of fuel are exempt from all fuel sampling and analysis requirements. According to 

the commenters, the EPA appears to exempt units that fire a single fuel type from conducting fuel 
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analysis as part of the initial compliance requirements in section 63.10005(c)(4). However, state the 

commenters, in section 63.10011, the procedures used to establish the fuel operating limits include a 

directive for handling single-fuel units. Despite these inconsistencies, the commenters believe that it was 

probably the EPA’s intention not to require single-fuel sources to conduct ongoing fuel sampling, and 

thus the commenters propose fuel testing only be required every six months, unless a facility changes

fuel type. According to the commenters, this approach is consistent with the approach taken in the final 

Industrial Boiler MACT rule, which did not require any ongoing fuel testing. The commenters note that 

the EPA explicitly states in the definition of “fuel type” in section 63.10042 that changes in vendors for 

a particular fuel type are not considered a change in fuel type, and assert that this indicates a belief that 

fuel sampling is not required within fuel types. According to the commenters, the EPA should clarify the 

fuel sampling requirements for single-fuel units that comply with one or more standards based on stack 

testing.

Comment 28: Commenters 17725 and 17820 note that for units firing a single fuel type, fuel sampling 

and analysis is not required for supplemental fuels used only for startup, shutdown or for maintaining 

flame stability (section 63.1 0005(c)(5)) According to the commenters, this exemption does not appear 

to apply to units that fire multiple fuel types or blends, and they request that the EPA clarify this 

exemption in the final rule.

Comment 29: Commenter 17722 requests that EPA clarify that fuel testing is not required for sources 

that combust a single fuel, excluding limited secondary fuel use for startup, shutdown or flame 

stabilization. The commenter believes single-fuel plants should be exempt from the requirements under 

section 63.10007(c) which states “you must conduct the performance tests at the maximum normal 

operating load while burning the type of fuel or mixture of fuels that has the highest content of chlorine, 

fluorine, non-Hg HAP metals, and Hg, and you must demonstrate initial compliance and establish your 

operating limits based on these tests.”

Comment 30: Commenter 17775 recommends the EPA clarify or remove the operating limit 

requirements, and clarify the fuel analysis requirements for single fuel EGUs and supplemental fuels.

6. Low emitting EGUs.

Comment 31: Several commenters (17402, 17754, 17808) believe the LEE monitoring requirements are 

overly burdensome. Commenter 17808 believes in many cases, monthly fuel testing would be redundant 

as this requirement would result in the repetitive testing of the same fuel shipment (see further 

discussion below in the context of oil-fired units). Commenter 17402 believes the monthly sampling 

requirements are arbitrary as there is no requirement in the rule to establish a fuel operating limit. 

Further, although fuel changes are addressed in the preamble, they are not directly addressed with regard 

to LEEs in the rule itself. For LEE single fuel facilities, Commenter 17402 believes that fuel sampling 

should only be required every six months, or on a change of fuel. Further, Commenter 17402 believes 

that if any increases in concentration are small enough that based on the facility’s demonstrated 

contaminant reduction performance on the prior stack test they would not cause the LEE limit to be met, 

then retesting of performance should not be required.

Comment 32: Commenter 17775 states that if EPA intended to require that LEEs perform monthly fuel 

analysis under section 63.10006(c), the EPA needs to make clear that compliance with the maximum 

fuel input levels is not required and explain why it chose monthly testing. According to the commenter, 

analyzing fuel monthly when the fuel supply or mixture has not changed seems unnecessary. The 

commenter states that if the EPA intended to require that LEEs establish and comply with maximum 
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fuel input levels as an “operating limit” under section 63.10011(b), rather than perform monthly fuel 

analysis, the EPA needs to explain that the fuel analysis is an operating limit and not a demonstration of 

compliance using fuel analysis under section 63.10011(c). According to the commenter, the EPA also 

needs to remove the monthly fuel sampling and analysis requirement in section 63.10006(c). If the EPA 

intended to require that LEEs establish and comply with operating limits other than maximum fuel input 

levels, the commenter states, the EPA needs to issue a proposal that explains the purpose of those limits 

and how they apply.

Comment 33: Several commenters (17725, 17820, 18498) believe the fuel sampling requirements for 

LEE units are ambiguous and provide no compliance value since the rule does not require the 

establishment of a fuel input operating limit. According to the commenters,, the requirements do not 

address single-fuel units, changes in fuel type, or units that burn or co-fire multiple fuels. The 

commenters assert that presumably, LEE units would follow an analogous procedure as non-LEE units 

and reassess the ability to meet LEE status based on the new fuel type/blend; this would require sources 

that burn multiple fuel types or blends to establish a fuel-input operating limit during the initial 

compliance demonstration. Consistent with the non-LEE requirements, the commenter suggests the EPA 

remove the arbitrary monthly sampling requirement and allow sources to conduct fuel sampling only

when there is a change in the fuel type. For single-fuel units, the commenters suggest the EPA specify

that these units are not required to comply with any of the fuel sampling requirements.

Comment 34: Commenter 17754 suggests that to the extent that the EPA does not revise the proposed 

rule to allow LEE units to demonstrate continuous compliance through annual performance testing only, 

rather than monthly fuel evaluations, and instead insists upon requiring that all LEEs demonstrate 

continuous compliance using a fuel factor based approach, the EPA should nonetheless revise the 

specific fuel factor based approach currently required under the proposed rule. The commenter believes 

the requirement to use the 90th percentile confidence level to determine the operating limit for Hg is 

improper, because the use of such value could cause a LEE to lose its LEE status, even though the unit’s 

actual Hg emissions remain substantially below the LEE thresholds.

Comment 35: Several commenters (19536, 19537, 19538) believe the EPA should discard its “Low 

Emitting Units” monitoring protocols. The unavoidable variability claimed by the EPA, moreover, 

indicates that plant emissions range as much as 50 times higher than the results of a three-run test. As a 

result a plant with test data at 50% of the proposed standard will likely – indeed, almost certainly –

exceed the prescribed limit during its operations. Yet the only compliance monitoring required for an 

LEE is an initial performance test, and subsequent check-up performance tests every 5 years, coupled 

with monthly fuel sampling. That monitoring provides no assurance of continuous low-HAP emissions. 

Fuel sampling would reveal no information about HCN, which is a byproduct of combustion and cannot 

be inferred from fuel sampling. Further, fuel sampling would disclose no information about HAP that 

did not originate in the fuel. Additives, such as PVC, are sometimes blended with the fuel to facilitate 

Hg control. Metals are present in the reagents (limestone, lime) and water used in scrubbers. Metals are 

also released from the boiler, duct work, and control systems. These would not be detected by fuel 

sampling.

Comment 36: Commenter 17808 recommends that for non-Hg HAP as well, owners/operators of a LEE 

unit have the option to conduct an annual performance test to demonstrate that emissions are less than 

50 percent of the relevant emissions standard. The commenter notes that the EPA proposes that for all 

other HAP, LEEs would demonstrate continuous compliance and maintain LEE status through monthly 

fuel analysis as well as performance (stack) testing every 5 years. However, in many cases, according to 
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the commenter, monthly fuel testing would be redundant as this requirement would result in the 

repetitive testing of the same fuel shipment.

Comment 37: Commenter 17807 suggests the EPA reconsider the use of fuel samples as the method of 

compliance for the maintenance of LEE status and alternatively suggests using the fuel samples as a 

control similar to the intent of the EPA; however, the compliance should be based on a 12-month rolling 

average of the key parameters in the fuel. According to the commenter, if the 12-month rolling average 

of fuel samples shows a monitored parameter over the threshold then a stack test would be triggered. 

This procedure would ensure that only an actual emissions exceedance could cause a unit’s LEE status 

to be lost.

7. Liquid oil-based EGUs.

Comment 38: Several commenters (17758, 17775, 18428) suggest the alternative fuel analysis 

provisions should apply to all affected liquid oil-based EGUs. One commenter cites the summary of the 

rule proposal 76 FR 25031, in which the EPA states that this provision applies only to limited-use oil 

units and not other affected oil units. The commenter explains that the provisions of the proposed rule 

itself (sections 63.10005(c) and 63.10006(s)) appear to indicate that owners/operators of all affected 

liquid oil-fired units may perform fuel analyses to demonstrate initial and continuous compliance with 

applicable emission limitations, as an alternative to performance stack testing. The commenter requests

that the final rule clarify that the alternative to use fuel testing to demonstrate initial and continuous 

compliance applies to all affected liquid oil-fired EGUs, not only limited-use units. Commenter 17775 

also requests that the EPA further explain its preamble statements in order to allow meaningful comment 

on that procedure.

Comment 39: Commenters 17386 and 17621 believe the fuel oil metals analysis methods are not 

sensitive enough to support compliance monitoring for limited use oil EGUs. Commenter 17386 states 

that based on contacts with a number U.S. laboratories, standard available analytic techniques are not 

capable of achieving the detection limits required to demonstrate compliance with proposed MACT

emission limits for certain HAP Metals (such as cadmium, beryllium and antimony) in liquid fuel oils. 

The commenter states the fuel oil concentration for cadmium, beryllium and antimony would have to be 

< 5 ppb to demonstrate compliance with MACT limits, and none of the laboratories contacted could 

achieve this detection level.

Comment 40: Commenter 17386 notes the detection limits of the analytical methods for non-Hg metals 

in oil are too high to support compliance verification. According to the commenter, in the ICR Part III 

database, most of the fuel oil metal concentrations are non-detect values, with detection limits ranging 

from 0.25 to 10 parts per million by weight (ppmw). The commenter states that this range is equivalent 

to approximately 10-6 to 10-4 lb/MMBtu, while the proposed MACT metal emission limits for existing 

oil-fired units range from 10-7 to 10-6 lb/MMBtu. The commenter states that fuel samples from several 

oil-fired EGUs were analyzed with ASTM D6357, the method specified in the ICR for coal, not oil, and 

that this method gave lower detection limits, on the order of 0.01 ppmw, or approximately 10-7 

lb/MMBtu. According to the commenter, the use of ASTM D6357 for oil samples may give inaccurate 

results for metals because the ashing step that works well for coal can cause the loss of metals in oil 

samples, resulting in erroneously low metal concentrations. The commenter asserts that fuel oil metals 

concentrations would need to be quantifiable below 0.01 ppmw to demonstrate compliance. According 

to the commenter, the analytical techniques currently used for fuel oil samples by most laboratories 

cannot measure accurately at those levels. The commenter suggests allowing fuel oil monitoring to be 
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used as a compliance method for limited-use EGUs, a new or improved standard certified method for 

fuel oil will be required.

Comment 41: Commenter 17718 suggests the EPA should clarify whether the fuel analyses and 

procedures in the proposed regulatory language (40 CFR section 63.10008) are only applicable to liquid 

oil-fired EGUs that desire to meet their applicable emission limits through fuel sampling.

Comment 42: Commenter 17760 suggests the EPA should clarify that all liquid oil-fired units may

demonstrate compliance through fuel analysis. The commenter believes the language in the preamble to 

the proposed rule and the proposed regulatory language are inconsistent regarding the availability of the 

fuel analysis option. The commenter believes the preamble seems to limit the option to limited-use 

liquid oil-fired units, citing 76 FR 25031, while the regulatory language seems to allow all affected 

liquid oil-fired units to utilize the fuel analysis option, citing 40 CFR 63.10000.

Comment 43: Commenter 17796 suggests the requirements for liquid oil-fired units are confusing and 

should be rewritten for clarity. The commenter cites “What Are My General Requirements/or 

Complying with this Subpart”, paragraph (c)(2), which states that liquid oil-fired EGUs can demonstrate 

initial and continuous compliance using fuel analysis, noting that these general requirements are 

contradicted in section 63.10006, which specifies different continuous compliance methods for liquid 

oil-fired units.

Comment 44: Commenter 17718 suggests that within the proposed regulatory language (40 CFR

section 63.10011(b)), where reference is made to conducting fuel analyses and establishing maximum 

fuel pollutant input levels “...as applicable”, the EPA should clarify that the fuel sampling, analyses, and 

maximum input levels are only applicable to liquid oil-fired EGUs that choose to meet their emission 

limits through fuel sampling methodologies. The commenter believes the establishment of fuel limits 

appears applicable only to facilities that choose to comply via fuel analysis. The commenter believes if 

facilities apply CEMS, accurate compliance can be determined at the emission point and, therefore, the 

fuel input becomes irrelevant. The commenter also states that there are numerous inaccurate 

section/paragraph references within the proposed regulatory language of 40 CFR section 63.10011(b). 

The commenter suggests the EPA carefully review this section to properly link references to the 

appropriate sections and paragraphs.

8. Monthly fuel analysis.

Comment 45: Several commenters (17386, 17758, 17760, 17902) believe the monthly fuel analysis 

contained in section 63.10006(s) would be unnecessarily burdensome, costly and impractical. One 

commenter suggests requiring fuel analysis to be performed on each shipment of oil received should be 

adequate to demonstrate compliance. Commenter 17760 notes that oil-fired plants require verification 

that fuel oil meets certain specification prior to accepting a delivery and after a plant accepts a shipment 

of fuel oil and places it in a storage tank and that it is highly unlikely that the composition of the fuel oil 

will change. Commenter 17386 notes that for large fuel oil storage tanks which receive oil deliveries 

less frequently than monthly the requirement is unjustified and proposes fuel sampling for oil-fired units 

shall be performed quarterly only during periods when fuel oil replenishment has been made to the fuel 

oil storage tank. Commenter 17902 recommends that this requirement be revised to require sampling 

only when there is a fuel switch, new fuel, fuel shipment, or change in fuel source. In addition, this

commenter suggests the final rule should allow use of fuel supplier data for each shipment as an 

alternative approach.
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Comment 46: Commenter 17731 suggests the EPA remove the requirement that EGUs without control 

devices conduct HCl emission testing every month, 76 FR 25029/3, for units that otherwise meet the 

HAP emission limits. The commenter believes this burdensome requirement offers no environmental 

benefit because compliant emission levels can be explained by fuel sources. The commenter suggests a 

better alternative would be yearly stack testing with a monthly fuel sampling.

Comment 47: Commenter 17807 notes that although they prefer that SO2 be used as a surrogate, they

do not object to allowing utilities to opt to perform routine HCl testing or continuous emission 

monitoring. The commenter requests that the EPA allow utilities to choose to demonstrate compliance 

for HCl through routine fuel sampling. According to the commenter, most facilities currently utilize 

some type of fuel sampling methodology to test their fuels burned, and the chloride content can be 

analyzed using ASTM 4208/300 along with existing fuel test methods. The commenter notes that 

facilities will need to establish an upper chloride threshold in the fuel as demonstrated by HCl stack 

testing and that once the limit is established, the daily or weekly chloride analyses on a 30-day rolling 

average will demonstrate compliance provided the threshold is not exceeded. The commenter believes 

this will provide an established procedure to ensure compliance.

9. Site-specific fuel analysis plans.

Comment 48: Commenters 17775 and 17800 state that although the commenters do not object to a 

requirement to submit a plan or to use standardized procedures, as required by section 63.10008; 

however, because there is so much diversity in how fuel is received, stored, and processed at individual 

facilities, the commenters assert that the EPA needs to allow more flexible procedures to accomplish the 

primary objective.

Comment 49: Commenters 17775 and 17800 discuss that under proposed section 63.10008(b)(1), the 

proposed plan must be submitted to the Administrator at least 60 days before the fuel analysis. Because 

some of the information required to be included may change from analysis to analysis, the commenter

assumes the EPA intends sources to submit a new plan or update the existing approved plan if 

information changes. For example, the commenter notes, the plan must include identification of all fuel 

types anticipated to be combusted and whether the source or fuel supplier will conduct the analysis. 

Proposed section 63.10008(b)(2). According to the commenter, although it might be possible to submit 

that information 60 days in advance of the initial demonstration and receive approval before conducting 

the analysis, it may not be possible for subsequent analysis in response to changes in fuel type or fuel 

mixtures (since those might occur with less notice or planning). According to the commenter, the 

requirement to submit a new or revised plan also makes little sense if monthly analysis is required. The 

commenter requests that the EPA either remove the requirement for advance submittal and approval of a 

plan after the initial compliance demonstration, or remove the requirement to include in the plan 

information that might change.

Comment 50: Commenter 17821 does not object to the requirement to develop a site-specific fuel 

analysis plan and does not object to submitting it to the EPA; however, the commenter sees little value 

in the requirement that the EPA must approve the plan before it can be implemented. The commenter

believes that the requirements for development of the plan are specified in the proposed rules and 

sources are fully capable of following and implementing those requirements. The commenter notes there 

will be hundreds of fuel analysis plans submitted to permitting agencies and the EPA in a very short 

period of time which can result in a backlog of plans to be reviewed, which could easily mean that a 

source submitting a plan before the 60-day deadline in advance of testing may not receive approval to 

use the plan before it must conduct that testing. The commenter notes that if the delay is extensive, this 
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could mean that a source might not be able to complete performance testing before the deadlines 

specified in the rules. The commenter therefore urges the EPA to modify this section of the proposed 

rule to eliminate the requirement for the EPA to approve fuel analysis plans prior to conducting testing.

Comment 51: Commenter 17881 notes that section 63.1008, requiring development of a site specific 

fuel analysis plan, as applicable, is very unclear how to determine if you need a fuel analysis plan as 

section 63.10005 does not stipulate which units are required to conduct fuel analysis on an on-going 

basis. Provision (b)(2)(iv) requires that the minimum expected detection level for chlorine, fluorine, Hg, 

and metals be included in the plan. The commenter notes that the EPA should clarify that fluorine is 

only applicable for oils. The commenter advocates that the EPA provide guidance on required minimum 

detection levels for these parameters.

10. Performance testing and fuel analysis.

Comment 52: Commenter 17775 cites proposed section 63.10011(b) that “if you demonstrate 

compliance through performance testing, . . . [y]ou must also conduct fuel analysis according to § 

63.10008 and establish maximum fuel pollutant input levels according to paragraphs (c)(1) through (5).”

(The commenter notes that Table 8 actually refers to section 63.10011(c) and (d), but the EPA probably

intended to reference (b) and (c).) According to the commenter, table 8 also requires EGUs to continue 

combusting only the fuel types and mixtures used to demonstrate compliance with fuel input levels 

under section 63.10011(b) and (c). The commenter states that accordingly, any unit that demonstrates 

compliance using “performance testing” would, under Table 8, be limited to combusting only those fuels 

or mixtures used during initial performance testing.

Comment 53: Commenter 19033 suggests the EPA clarify the meaning of “highest content” contained 

in 63.10007(c). The commenter cites an EGU operated which is a coal-fired unit with natural gas firing 

capability during periods of start-up; however, the coal burned in this EGU comes from more than 

one mine source. The commenter notes that it will make a good faith effort to identify the coal that has 

the maximum anticipated amount of chlorine, and Hg, and base its tests on that coal; however, it will be 

unable to certify that coal from another section of the mine will not have higher chlorine or Hg content 

than what was tested, due to the variable nature of coal. The commenter also notes it may also be 

possible that a coal with a maximum chlorine content may not be the coal that also has the maximum 

mercury content.

Comment 54: Commenter 18447 questions the EPA statement in the preamble of the proposed rule that 

“For units without wet or dry FGD scrubbers that must comply with an HCl emission limit, you must 

measure the average chlorine content level in the input fuel(s) during the HCl performance test. This is 

your maximum chlorine input operating limit.” The commenter believes that this means that once the 

HCl performance test has been completed and the chlorine results are known, the fuel that was used 

during the test cannot be used again. According to the commenter, this is because the fuel’s measured 

average chlorine value now becomes the maximum chlorine limit; the fuel that created the maximum 

chlorine limit (by virtue of its average) will now exceed the maximum limit 50% of the time (by virtue 

of the normal distribution curve) and therefore cannot be used again. The commenter believes as written, 

it creates a possible incentive to test with a fuel with a high chlorine content, and then switch back to a 

fuel with a lower chlorine content, whose maximum chlorine content is less than test fuel’s average 

chlorine content.

Comment 55: Commenter 19033 suggests that the EPA clarify section 63.10007(c) with respect to the 

requirement that coal which has the highest non-Hg metals must be tested, especially if the EGU
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operator elects to comply using the PM emissions limit, which is a surrogate for non-Hg metals. The 

commenter suggests that the phrase in question be amended, as follows:

“You must conduct performance tests at the maximum normal operating load while burning the 

type of fuel or mixture of fuels that has the highest content-of chlorine, . fluorine, non-Hg HAP

metals (if you elect to comply with the non-HG metals HAP emission limitation), and Hg, and 

you must demonstrate initial compliance and establish your operating limits based on these tests.”

11. Continuous compliance.

Comment 56: Commenter 17881 suggests the provisions of section 63.10021(a)(2) should state that 

fuels used for start-up/shutdown and flame stabilization are exempted from this requirement. Also, 

according to the commenter, it is the fraction of heat input which is relevant to meeting the emission 

limit, not the overall fuel mass (based on the HAP input calculations at section 63.10011). According to 

the commenter, the requirement to keep records of the amount of fuel burned in each EGU is not 

relevant to any compliance requirement in the rule, and the utility industry already reports fuel usage to 

the Department of Energy, Energy Information Administration in various reports. The commenter notes 

that this information is available for the EPA to access.

Comment 57: Commenter 17881 suggests that with respect to section 63.10021(a)(5), if the EPA allows 

actual sampling vs. theoretical results, then these provisions would not apply as direct sampling would 

be used to demonstrate compliance. The commenter believes the monthly compliance demonstration 

through fuel analysis is all that is required to comply with the Hg emission limit instead of trying to 

theoretically pre-qualify a fuel. 

Comment 58: Commenter 17781 suggests that with respect to 63.10021(a)(3), if the EPA allows actual 

sampling versus theoretical calculated results, then the provisions of this paragraph would not apply as 

direct sampling would be used to demonstrate compliance. The commenter believes the EPA should 

leave it up to the facility to demonstrate compliance, as it does not make sense to try and pre-qualify 

emissions. According to the commenter, the logistics of trying to pre-qualify a fuel does not work in the 

real world, as what is sampled for the pre-qualification analysis is most likely not what is really burned, 

as oil is blended in a storage tank prior to burning; the onus of proof of compliance is on the facility.

12. Chloride concentration variability.

Comment 59: Commenters 17816 and 19114 note HCl CEMS currently are not commercially available 

or adequate for in-stack measurements at coal-based EGU’s, and are not anticipated to be available by

the compliance date of the rule. As a result, according to the commenters, sources will be forced to 

either take a fuel limit or an operating parameter limit. The commenters believe the fuel analysis limit is 

impractical because of the inherent variability of chloride concentrations in coal, both between various 

ranks of coal and within the same coal category. According to the commenters, it will be impossible to 

control fuel deliveries in such a manner as to negate the possibility of burning coal with chlorine content 

above that which was used during compliance testing.

13. Stop belt sampling (section 63.10008(c)(1)(i)).

Comment 60: Commenters 17715 and 19114 suggest the EPA remove the provisions for affected 

sources to conduct stop belt sampling or to pull samples from the coal piles during testing. The 

commenters believe stop belt sampling is neither safe to conduct due to stored energy in the conveyor 
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belts, nor is it representative of a unit’s operation. According to the commenters, a unit may have to 

reduce process rate due to a decrease or a lag in the time that the fuel is being delivered. The 

commenters assert that sampling from the coal pile will not gather coal samples that are representative 

of what is being burned. The commenters note they have coal piles that are greater than 15 acres in area 

and gathering five samples uniformly spaced at a depth of 18 inches will not adequately represent what 

is being burned during the test period.

Comment 61: Commenter 17722 notes that stopping and starting a coal belt that is moving tons of coal 

is problematic and labor intensive. According to the commenter, the sampling procedures are applied to 

screw conveyors, and the commenter believes it is impossible to withdraw a six-inch wide cross section 

from a screw conveyor because of the auger system.

Comment 62: Commenters 17722 and 19114 suggest the EPA should allow the EGU operator to 

determine the best available method to collect a representative sample. Commenter 19114 suggests that 

the EPA specify a number of representative fuel samples during the testing.

Comment 63: Commenter 17800 believes the proposed stop belt sampling requirements for collecting 

composite fuel samples is not reasonable and apparently would not allow for the use of continuous belt 

samplers. According to the commenter, in addition, many belts cannot be restarted with coal on them 

because the belt is too heavy for the motor to start. The commenter asserts that for sampling piles or 

trucks, the rule requires (among other things) use of a “square shovel,” collection of samples at a depth 

of exactly “18 inches,” collection at five locations “uniformly spaced over the surface of the pile,” and 

breaking of pieces larger that exactly 3 inches (citing proposed section 63.10008(c)(2)(ii) and (d)). The 

commenter believes representative samples can be taken with shovels of other shapes, at depths greater 

or less than 18 inches, and without measuring the actual size of individual coal pieces. The commenter

requests that the EPA remove the prohibition on moving belt samplers and reexamine and moderate the 

pile sampling requirements to provide more realistic criteria (e.g., use the same shovel for all samples, 

collect samples at a uniform depth of approximately 18 inches, and break apart large pieces (e.g., pieces 

greater than 3 inches).

Comment 64: Commenter 17881 expresses concern over sampling from a belt, as there are significant 

safety risks with reaching across a belt. The commenter asserts that according to safety requirements, the 

belt would have to be locked out and tagged out in order to cross the vertical plane of a belt. According 

to the commenter, plant personnel currently collect coal samples from a feeder chute just prior to the 

coal mill, and the commenter suggests the EPA should consider other sampling alternatives to those 

currently presented in section 63.10008(c). 

Comment 65: Commenter 18015 believes the EPA requirement of stopping the coal belt to take coal 

samples in a swath across the belt is unnecessary and can create operating problems. According to the 

commenter, every time a coal belt is stopped, a risk is incurred, however slight, of having difficulty

restarting the belt, and it is possible to get good representative samples without stopping the coal belt. 

According to the commenter, EGUs have been following such practices successfully for many years. 

The commenter believes the EPA should eliminate the requirement to stop the coal belt to take samples.

Comment 66: Commenter 19121 believes requiring belt stop and starts during plant operation is 

dangerous, logistically and operationally intrusive, and unnecessary.

14. Coal sampling methods.
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Comment 67: Commenter 17821 objects to the requirement of a manual coal fuel-sampling method as 

proposed in section 63.10008(c), (c)(1)-(2). The commenter notes they utilize automated mechanical 

coal sampling systems that are operated under procedures such as those described in ASTM D2013. 

According to the commenter, these automated methods are widely accepted and do not require the laborintensive and time-consuming procedures described in the above referenced sections of the proposal. 

The commenter believes the EPA should allow the use of automated sampling procedures that follow 

standard practices referenced in appropriate ASTM or other such methods that are written by experts in 

their fields and are peer reviewed. In other rulemakings, the EPA has referenced ASTM standard 

practices. The commenter suggests these rules should allow the use of those standards and should not 

require a manual method of sampling.

Comment 68: Commenter 17821 strongly urges the EPA to avoid writing detailed sample preparation 

procedures as specified in section 63.10008 (d), (d)(1)-(7). In lieu of the agency writing their own 

procedures, the commenter believes the proposal should reference appropriate ASTM standards that are 

widely used by the utility industry, and others and such sample preparation methods that are written by

experts in their fields and are peer reviewed. The commenter notes that in other rulemakings, the EPA 

has referenced ASTM standard practices. According to the commenter, these rules should allow the use 

of those standards and the EPA should not take on the challenge of writing special procedures that are 

unique to this rulemaking.

15. Other comments.

Comment 69: Commenter 17725 notes that the EPA defines the two coal-fired unit subcategories as 

based on 1) the calorific value of the coal the boiler is designed to combust and 2) the boiler dimensions 

in terms of height-to-depth ratio. According to the commenter, the larger boiler dimensions are a result 

of the inherently higher mineral matter of these fuels. The commenter states that there are two issues that 

warrant clarification so that compliance requirements are easily determined and understood: First, many, 

if not most lignite units burn a blend of coals, e.g., lignite and PRB; and second, the industry standard 

for determining heating value of as-received coal is based on an ultimate/proximate analysis. According 

to the commenter, clarification is needed from the EPA regarding their reliance on the moist mineral 

matter free heating value (ASTM D388) of coal. The commenter states that this method is typically

relied upon to classify distinct coal regions and individual seams don’t vary significantly within a 

region. According to the commenter, the ASTM D388 method specifically excludes any samples of 

weathered or oxidized coal be used for coal rank classification and further requires no less than three 

samples to be taken within the same mine or locality of the coal bed in accordance with U.S. Bureau of 

Mines sampling methods.

Comment 70: Commenter 17725 suggests the EPA remove redundant stack test requirements. The 

commenter notes that the EPA has established alternative limits for compliance for various HAP groups 

and these options provide the sources with a measure of flexibility. However, the commenter believes 

the EPA is requiring stack tests for both the pollutant and surrogate. According to the commenter, since 

limits for each pollutant (or surrogate) have been independently established to assure effective 

reductions in accordance with section 112 of the CAA, the commenter believes there is no need to test 

for both the pollutant and surrogate. The commenter believes a performance test should only be required 

for the pollutants and surrogates with which the source is choosing to show compliance (e.g., if a source 

is demonstrating compliance for acid gas HAP using SO2, it should not be required to conduct a HCl

performance test) and suggests the extra tests are superfluous since the surrogacy has already been 

established.
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Comment 71: Commenter 17881 discusses issues with Table 6 – Fuel Analysis Requirements, noting 

that this requirement stipulates the use of Method 19 fuel factor (F-factor) methodology to convert 

emission concentrations into units of lb/MMBtu. According to the commenter, Method 19 does not 

contain procedures for converting any constituent other than sulfur percent by weight into an equivalent 

pollutant emission rate on an energy input basis. Furthermore, states the commenter, it is wholly unclear 

how one would convent a fuel constituent concentration into units of lb/MWh, as such a conversion 

would not be based on just the fuel characteristics (i.e., constituent concentration and heating value) but 

would instead also relate to the heat rate of the unit in which the fuel is to be combusted. The commenter

suggests the EPA should either remove the reference to converting the concentration to units of 

lb/MWh, or should provide clear procedures for conducting the associated calculation(s).

Comment 72: Commenter 18025 recommends the EPA set a percent water content limit for oil, rather 

than setting HCl and HF emissions limits for liquid oil-fired EGUs. The commenter notes ASTM test 

methods are available for measuring the percent water content of fuel oil (D95 and D473). The 

commenter suggests that plant operators would test each shipment received to ensure compliance with 

the proposed limit.

Comment 73: Commenter 18483 suggests that should such IGCC or other generating units remain 

subject to the rule, fuel sampling should be allowed as a sole compliance demonstration option in lieu of 

a Hg CEMS or sorbent trap methodology due to Hg being removed from the fuel prior to combustion 

and the lack of post-combustion controls.

Comment 74: Commenter 19114 notes that IGCC processes are inherently different from other methods 

of coal-based electric generation and more similar to natural gas combined cycle units in terms of design 

and emissions. According to the commenter, if IGCC units are not exempted in the final rule, then the 

standards should be revised to address the unique characteristics of IGCC processes. The commenter 

believes that issues that would need to be addressed include: the applicability of fuel sampling 

requirements, gasifier feedstock sampling, raw syngas sampling, clean syngas sampling, syngas fired in 

the combustion turbines, syngas fired in a flare, processed syngas fired in thermal oxidizer, etc.

Comment 75: Commenter 17775 notes concerns with applicability with provisions and paragraphs cited 

in section 63.10011(b). With respect to operating limits, the commenter believes proposed section 

63.10007 does not discuss applicability at all. According to the commenter, with the exception of the 

filterable PM limit applicable to units using PM CEMS, Table 7 also does not distinguish between 

compliance options. Instead, states the commenter, Table 7 refers to various parameters depending on 

which control device “your operating limits are based on” (citing section 63.10011(b)(6)). (The 

commenter notes that although the rule actually cites section 63.10011(c)(6), that provision addresses 

fuel sampling, not operating limits. As a result, the EPA probably intended to reference (b)(6).) 

According to the commenter, Table 7 also refers only to specific control devices and not compliance 

options. With respect to fuel input levels, the commenter asserts that paragraphs (c)(1) through (5) 

specify how fuel input levels are established but do not identify which EGUs must establish them. The 

commenter notes that proposed section 63.10008 requires “performance fuel analysis tests” “as 

applicable”; Table 6 requires fuel analysis “as stated in section 63.10008”; and proposed section 

63.10031 requires compliance reports to address compliance with fuel input limits “for sources that 

demonstrate compliance through performance testing.”

Comment 76: Commenter 17801 notes on page 25037 of the proposal the EPA provides an option to 

monitor inlet chlorine, fluorine, non-Hg metals and Hg in liquid oil to meet outlet emission rate limits, 

noting that it is reasonable to do so because oil-fired units remove these fuel-borne HAP from the oil 
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before combustion in lieu of installing air pollution control devices (APCD). In response to the EPA’s 

request for comment on the viability of this approach for IGCC, the commenter agrees that fuel 

monitoring (of the syngas) should be an option for IGCC as well based on the same reasoning as to that 

fuel “clean-up” vs. APCD. The commenter believes fuel sampling should be allowed as a sole 

compliance demonstration option for IGCC in lieu of a Hg CEMS due to Hg being removed from the 

fuel prior to combustion and the absence of post-combustion controls in lieu of pre-combustion control. 

Response to Comments 1-76: Based on the comments received and a further review of the technical 

challenges associated with the proposed fuel analysis requirements, the EPA has not finalized the 

proposed fuel analysis requirements. Fuel analysis of moisture for certain liquid oil-fired units remains a 

compliance assurance option. As the rule no longer requires operating limits for pollutants based on fuel 

content or fuel analysis, the comments summarized above are largely moot. For low emitting EGUs, the 

agency agrees that the proposed LEE ongoing eligibility requirements were overly burdensome and 

restrictive. As a result, existing solid- or liquid-fired units that qualify for LEE status for Hg will be 

required to conduct a 30-day test for Hg using Method 30B each year. Neither fuel analysis nor 

adherence to an operating limit will be required. Should an annual test show ineligibility for LEE status, 

the unit would revert to the requirements for Hg monitoring using CEMS or sorbent traps or quarterly

emissions testing. For other pollutants, a unit can qualify for LEE for an applicable pollutant if all 

performance tests over a 3-year period demonstrate that the unit remains below 50% of the emission 

limit for the applicable pollutant. Under those circumstances, the unit would qualify for emissions 

testing of that pollutant every 3 years to demonstrate ongoing compliance with the rule. 

The only fuel analysis provision in the final rule is an optional compliance assurance method for liquid 

oil-fired units. If you combust liquid fuels, if you wish to demonstrate ongoing compliance with HCl and 

HF emissions limits by measuring fuel moisture content, and if your fuel moisture content is no greater 

than 1.0 percent, you must measure fuel moisture content of each shipment of fuel if your fuel arrives on 

a batch basis; or measure fuel moisture content daily if your fuel arrives on a continuous basis; or obtain 

and maintain a fuel moisture certification from your fuel supplier. Should the moisture in your liquid 

fuel be more than 1.0 percent, you must either: (1) conduct HCl and HF emissions testing quarterly and 

develop a site-specific monitoring plan to monitor appropriate operating parameters to ensure that 

operations remain consistent with those present during performance testing; or (2) use an HCl CEMS 

and/or HF CEMS. 
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5A04 - Testing/Monitoring: Detection levels

Commenters: 17316, 17386, 17621, 17622, 17711, 17715, 17725, 17730, 17775, 17790, 17800, 17821, 

17873, 17902, 17914, 18034, 18429, 18443, 18498, 18023

1. Analytical techniques and detection levels.

Comment 1: Commenters 17316 and 17386 state that based on contacts with a number of laboratories, 

it appears that standard available analytic techniques are not capable of achieving the detection limits 

required to demonstrate compliance with proposed MACT emission limits for certain metals, such as 

cadmium, beryllium and antimony, at least in oil. Commenter 17316 refers to a Table (note: this table is 

not attached to the comment), that allegedly addresses the concentration in oil for each regulated HAP

metal corresponding to proposed MACT emission limits for oil fired EGUs. According to the 

commenter, for cadmium, beryllium and antimony, the concentration in oil would have to be < 5 ppb to 

demonstrate compliance with MACT limits, and according to the commenter, none of the laboratories 

contacted could achieve this detection level. Moreover, the commenter questions the accuracy of 

analysis results determined by the specialized methods used to reach the detection levels required for 

such a compliance demonstration on fuel oil. 

Response to Comment 1: The requirements for fuel sampling and analysis for the listed metals have 

been removed from the final rule.

Comment 2: Commenter 17622 states that based on information provided in the proposed rule, they 

cannot validate that technology exist to accurately measure the proposed emission limits for new units. 

The commenter states monitoring systems have to be capable of accurately measuring emissions below 

the limits established by the EPA and in practice emission control technologies must be able to provide 

long term control at emission levels below the proposed limits. The commenter notes that when the EPA 

sets an emission limit, all EGUs establish operating levels below the EPA or permit levels, to some 

extent, to compensate for operational variability, fuel changes, and startup and shut down times that 

occur during normal plant operations, and in order to remain in compliance over the averaging period. 

Therefore, according to the commenter, emission limits need to be established within the capabilities 

and accuracy of monitoring systems, and when owners/operators purchase control equipment, they may

add an operational margin in their specification and request for performance guarantees. The commenter

believes compliance monitoring and measurement for the proposed new unit emission limits are of 

concern, and vendor guarantees may be problematic without the ability to consistently measure 

remaining pollutants at the low emission levels proposed. 

Response to Comment 2: As more thoroughly discussed in 4A03 of this document, the new source 

limits have been revised in order to represent the representative detection level (RDL) instead of the 

MDL determined by a single source.

Comment 3: Commenter 18429 believes the EPA’s proposed test methods are not adequate for the 

excessively low limits for new sources, including both Hg and HCl CEMS. The commenter references 

EPRI analyses. The commenter suggests the EPA complete a re-review of the limits and test methods 

for new units to provide a meaningful MACT with which new units can continuously comply. The 

commenter notes that consistent with CAA section 112(d), the emission limits must be measurable by

current technology. 
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Response to Comment 3: In response to comments, the final rule allows the option to perform periodic 

stack measurement or monitoring for PM, HCl, HF, and non-Hg HAP metals. In addition, the emissions 

limits have been set at a minimum level of three times the RDL to provide for the variability for at the 

method detection limits and truncation of the operations variability.

Comment 4: Commenter 17914 is concerned that available CEMS equipment is not accurate enough in 

commercial field applications to reliably report total PM at the proposed MACT emissions limit for new 

coal. The commenter states that for a supplier of new boilers and associated AQCS equipment, these 

extremely low limits present a significant challenge for them to provide performance guarantees in light 

of the inaccuracies of the reference methods for PM. The commenter notes that the proposed rule 

indicates no allowance was made for data collected at or below the MDL and instead a default value of 

the MDL was used, and suggests this logic would appear flawed, as setting a compliance limit that is 

only 2 times the MDL for the test method which could result in errors as high as 50%. The commenter

references U.S. EPA “Review of National Primary Drinking Water Regulations: Analytical Methods -

Reassessment of Practical Quantitation Limits, noting that the EPA guidance suggests a multiplier of 5-

10 times the MDL for determining the PQL (in absence of sufficient inter-laboratory study data). 

Response to Comment 4: In response to comments, the final rule does not have a total PM limit. The 

facilities also have the option of periodic filterable PM testing in lieu of the installation of PM CPMS. 

The EPA has also finalize alternative equivalent compliance options by establishing a total non-Hg 

metals limit and individual non-Hg metal limits.

Comment 5: Commenter 17621 performed an analysis of method sensitivity to evaluate the ability of 

test methods to measure HAP and surrogate parameters at the MACT limits, and includes a summary

table to the test method adequacy in their comments (Table 2-1). The commenter notes that as the 

proposal also requires facilities to establish operating limits for some HAP based on initial performance 

tests, which would then become the effective emissions limits for that facility. According to the 

commenter, as those operating limits would be lower than the MACT limits, there may be additional 

restrictions on the use of test methods beyond those indicated in the table.

Response to Comment 5: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS and provides the option for periodic testing for non-Hg HAPs. Hg 

Sorbent monitoring allows for sensitivities below the emission standards.

Comment 6: Commenter 18034 states the proposed emission limits for some of the pollutants are very

near and in some cases significantly less than the documented MDL of the required emissions testing 

and monitoring methods and even contradict certain recordkeeping provisions, which makes it 

impossible for companies to demonstrate compliance with the emission limits. The commenter

recommends the EPA bring the emissions limits into harmony with the capabilities of the prescribed 

methods and procedures for demonstrating compliance. The commenter provides specific examples for 

proposed Hg limits for new coal-fired EGUs under the greater than or equal to 8,300 Btu/lb subcategory. 

Response to Comment 6: The proposed Hg limit for new coal-fired EGUs was measured within the 

calibration range of the analytical technique and met all QA/QC criteria of Method 30B in a 4-hour run.

Comment 7: Commenter 17715 notes that NIST traceable standards, gaseous oxidized standards 

traceable to NIST and agreed to standard Hg vapor curves are not available, and without them there will 

be non-uniform reporting of emissions. 
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Response to Comment 7: It is the EPA’s position that the Interim EPA Traceability Protocol for 

Qualification and Certification of Elemental Mercury Gas Generators and the Interim EPA Traceability

Protocol for Qualification and Certification of Oxidized Mercury Gas Generators both published on July

01, 2009 are adequate to establish the NIST-traceability necessary for mercury monitoring programs at 

this time. The major vendors of mercury CEMS have, for some time, been marketing elemental mercury

calibration gas generators that are directly traceable to NIST elemental mercury reference standards. We 

agree with the commenters’ point that NIST does not currently directly certify oxidized mercury gas 

generators. However, oxidized gas generator NIST traceability is established through the assessment of 

the individual components of the calibrator. The interim protocols for certifying mercury gas generators 

allow sufficient flexibility to certify the gas generators in an appropriate range from existing NIST 

traceable gas standards. The EPA does not believe it necessary to make available standard mercury

vapor pressure curves in order to implement the mercury monitoring program set forth in this rule as the 

EPA’s primary approach to NIST traceability for calibration gases is based on direct comparisons with 

NIST reference materials and standards.

Comment 8: Commenter 17790 believes the EPA should specify specific guidelines for analytical 

detection limits stack testing for non-Hg HAP metals and how to handle results that are below the 

detection limit. 

Comment 9: Commenter 17800 believes the non-Hg metals data collected during the 2010 ICR showed 

reported detection limits for laboratory analysis that were highly variable even for data for the same 

metal and from the same laboratory. The commenter suggests the EPA specify minimum detection 

limits and procedures for combining front and back half fractions to report total concentrations in order 

to determine compliance on a consistent basis. 

Response to Comments 8 - 9: The MDL for non-Hg metals will depend on volumes samples and the 

analytical finish used. Table 5 will be revised to specify the procedures for handling MDL results while 

adding up multiple fractions.

Comment 10: Commenter 17902 believes the EPA must allow for a margin of compliance when setting 

the final MACT standards as the measurements for Hg and other HAPS in the rule are completed at very

low levels of detection, leaving a greater potential for error. 

Response to Comment 10: As more thoroughly discussed in Section 4A03, the emission limits for new 

and existing sources were set at a minimum of three times the RDL to provide for measurement and 

process variability at low levels when the UPL based on the data was not greater than three times the 

RDL.

Comment 11: Commenter 17775 agrees that performance testing for units using CEMS should not be 

required any more frequently than every 5 years. The commenter also supports inclusion of a reduced 

testing provision for tests conducted more frequently. However, the commenter does not believe that the 

EPA has provided sufficient support for many of the testing requirements in this proposal. Moreover, the 

commenter does not believe that the 50 percent criterion is reasonable given the extremely low levels of 

the EPA’s proposed limits. The commenter requests that the EPA remove this restriction. The 

commenter states the EPA has provided no reason for this restriction, or data suggesting that any source 

could achieve 50% of the proposed emission limits, some of which are established at or near the 

detection limit. The commenter does not understand how a source could test at a percent of the detection 

limit. The requirement that source and control device operation remain consistent with prior successful 

testing should be sufficient to ensure representativeness of the prior test(s). 
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Response to Comment 11: In the final rule, there is no requirement for periodic stack testing where a 

CEMS is used. The QA requirements for a CEMS, including Relative Accuracy Test Audits, are 

adequate to ensure that the CEMS data remain valid for purposes of determining compliance with the 

emission limits under this rule. The EPA disagrees and will retain the 50% criterion for reduced testing. 

Sources operating at low levels can show compliance with the 50% limit by increased sampling 

volumes. Also, the sources may opt to use CEMS or CPMS in lieu of the repeated periodic testing.

Comment 12: Commenter 17730 suggests the EPA specify minimum detection limits for laboratory

analysis for all pollutants and provide procedures for calculating total PM combined concentrations of 

single metals and total non-Hg metals. The commenter notes that based on data collected in the ICR, the 

reported detection limits for laboratory analysis were highly variable even for data for the same analyte

from the same laboratory. The commenter suggests that to determine compliance on a consistent basis, 

the EPA needs to specify minimum detection limits and procedures for total PM for combining the front 

and back half fractions to report total concentrations. 

Response to Comment 12: The EPA disagrees that we should specify a prescriptive minimum detection 

limit for laboratory analysis of all pollutants. Minimum detection limits will improve with future 

technology and analytical techniques. Since total PM has been removed from the final rule, procedures 

for combining total PM are not necessary.

Comment 13: Commenter 18443 suggests Hg, PM and HCl CEMS should be used as compliance 

indicators and not compliance methods. The commenter notes that the precision and accuracy of the 

current continuous HAP emission monitoring is not field proven to reliable reflect actual emissions data. 

The commenter believes very low HCl, Hg and PM concentrations are difficult enough to measure using 

stack tests (as evidenced by the numerous values at or below detection levels in the ICR data set), and 

accurately measuring these concentrations with CEMS is nearly impossible. According to the 

commenter, to date Hg, PM and particularly HCl CEMs have not been designed to measure very low 

pollutant concentrations. The commenter believes that the EPA should recognize the limitations that 

these CEMS have and use them only as an indicator of compliance, not as a compliance method. 

According to the commenter, these shortcomings, when used in series to determine emission rates, will 

result in substantial monitor downtime and the potential for numerous non-compliance events. 

Response to Comment 13: An Hg CEMS or an HCl CEMS are options for use as the performance test 

method for the applicable Hg and HCl emission limits. If a source is concerned about the use of these 

methods in such a manner, the rule provides for other options (sorbent trap monitoring for Hg and stack 

testing for Hg and HCl). There is no requirement to use a PM CEMS as a direct performance test 

method for the PM emission limit. The PM CPMS is used as an operating parameter monitoring 

approach to demonstrate compliance with a site-specific operating limit expressed in terms of the raw 

output of the PM CPMS. The operating limit aids in ensuring that the source is operated and maintained 

in accordance with good air pollution control practices to minimize emissions so that the source can 

continue to operate in compliance with the emission limit as demonstrated in a periodic stack test. The 

final rule does provide for the use of a PM CEMS to determine compliance with the filterable PM 

emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 14: Commenters 17316 and 17386 state that establishing HAP emission limits at the 

boundary of what can be detected by available analytic techniques does not seem reasonable and that the 

incremental benefits (HAP reductions) to be achieved by extending emission limits to such low levels, 

lying at the edge of detestability, do not seem justified. 
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Response to Comment 14: As further discussed in Section 4A, the emission limits are set at levels 

which EPA believes are consistent with the requirements of the CAA.

Comment 15: Commenter 18023 believes the EPA should not use data that is below the MDL to 

establish the MACT floor. The commenter states that despite not being able to “meaningfully quantify

the concentration(s),” the EPA used data that was identified as being “below detection limit” (BDL) or 

“detection level limited” (DLL) when establishing the MACT floors. The commenter suggests this 

means that many of the new and existing source MACT limits are based on data that is unquantifiable. 

The commenter references the comments submitted by EPRI that discusses that using BDL and DLL 

data also caused several of the new source limits to be so stringent that they are actually below the 

applicable method sensitivity. The commenter recommends the EPA should only use values that are 

above the MDL in calculating the MACT floor. 

Response to Comment 15: The EPA’s treatment of the data is consistent with the recommendation. All 

data determined to be below the detection limit was treated as measured at the method detection limit for 

use in the floor. Further discussion of the treatment of BDL and DLL data can be found in 4A03 of this 

document.

Comment 16: Commenter 17821 states the EPA’s effort to set emission limits for all HAP emitted by 

EGUs is greatly complicated by the fact than a number of HAP were emitted at levels at or below the 

reporting limits for the test methods required for collection of HAP emissions data during the ICR. The 

commenter cites Amoco Oil Co. v. EPA, stating that the legal history is that an emission limit must not 

be set below the quantification level of the method chosen for demonstrating compliance, and that if an 

emission limit is set below the quantification level, then as the court in Amoco Oil cautioned, the limit 

would be unenforceable. The commenter also cites a January 2011 memo in which the EPA 

acknowledged that measurements at levels below analytical detection and quantitation levels are 

associated with increased measurement uncertainty. The commenter provides additional discussion on 

quantitation limits and recommends that the EPA use quantitation limits rather than detection limits 

when establishing limits for the new standard. 

Response to Comment 16: As further discussed in 4A03/4 of this document, the emission standard 

limits were set at a minimum of three times the RDL. The RDL was based on a pool of method detection 

limits reported from the labs or previously established method detection limits. Although the final rule 

does not require sample volumes to reach the quantification limit of the methodology, sources are 

welcome to increase sampling volumes that the emissions limits would be within the quantification or 

calibration level.

Comment 17: Commenter 17873 believes that the new source Hg limit is below the detection limit of 

any current or planned instrument, and even if a new unit could meet the limit, there is no way to assess 

compliance. The commenter suggests the EPA’s proposed new source limit for Hg would act to ban the 

construction of new coal plants. According to the commenter, nothing in the CAA authorizes or 

mandates this result, and it has significant implications for the long-term energy security of the nation. 

The commenter believes the EPA should not be setting national energy policy through a CAA 

rulemaking. 

Response to Comment 17: The Hg limit for new coal-fired EGUs was measured within the calibration 

range of the analytical technique and met all QA/QC criteria of Method 30B in a 4-hour run.

2. Concerns with specific test methods.
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Comment 18: Commenter 17711 notes several potential issues with the EPA Methods 5, 23, 26/26A

and 29 as reference methods for measuring source emissions of PM, dioxins/furans, HCl, and Hg. The 

commenter notes that the extraction, processing, and analysis of samples can lead to random errors to 

the final measurement and provides examples such as where compound concentrations are inconsistent 

due to changes in fuel mix over time, contamination occurs, or improper instrument calibration or matrix 

interference. 

Response to Comment 18: The EPA Method 23 is not required for the final rule. The EPA agrees that 

“extraction, processing and analysis” can lead to random error and variability that would not be seen due 

to the truncation of the data set at the MDL. This is the basis for the emission standards being set at no 

less than 3 times the RDL as discussed in the preamble and 4A03 of this document.

Comment 19: Commenter 17711 states that aside from a 1996 study by R. Shigehara, the commenter is 

not aware that the EPA has published any results from studies necessary to determine the detection and 

quantitation limits of its reference stack test methods nor that the EPA has even proposed a method for 

determining the values of these parameters of the reference methods. The commenter states that of the 

five test methods that were utilized to collect data for setting the proposed MACT standards and would 

be used to demonstrate compliance with the proposed standards, the EPA has provided the detection 

limits for only Method 29, and even in those cases no EPA reports are available to assess the validities

of the detection limits specified with the test methods. According to the commenter, even in the absence 

of such reports, if one assumes that these values are correct and then applies the 3.18 Student-t 

multiplier for three samples to the detection limits, the estimated quantitation limit of Method 29 would 

be 1.8 μg/m3. An examination of the data in the EPA’s MACT database shows that it includes 

measurements below these values. The commenter suggests that values below a method’s quantitation

limit should not be used to set emission standards. 

Response to Comment 19: The EPA disagrees with the comment. The Method 29 detection limits 

published in the method only represent approximate estimates for each analytical technique to provide a 

guideline on choosing the appropriate analytical technique. The EPA Method 5 MDL was published 

with the promulgation of Method 5I. The Method 26 and 26A typical method detection limits were also 

published. As more thoroughly discussed in 4A03 of this document, the EPA disagrees that only values 

above the method’s quantitation limit should be used.

Comment 20: Commenter 17725 provides a discussion regarding a caveat of Method 30B that allows 

for an alternative approach for quantifying low masses. The commenter notes the caveat allows for 

estimates for masses below the lowest point on the calibration curve (i.e., LOQ), but above the MDL. 

The commenter suggests this caveat is of significance because there are no ongoing quality 

assurance/quality control (QA/QC) requirements for the response factor mass estimates. According to 

the commenter, this fundamentally differs from masses that fall within the calibration curve; all points 

used in the generation of the calibration curve must be within ±10% of the expected value. Furthermore, 

according to the commenter, continuous calibration verification standards (CCVS) must be performed 

no more than every 10 field sample analysis and also be within ±10% of the expected value for the field 

samples to be considered valid. The commenter asserts that therefore, any masses and ultimately effluent 

concentrations that are determined using the response factor approach are not of the same quality or 

uncertainty a those determined by the calibration curve (i.e., masses above the LOQ). According to the 

commenter, all masses determined above the LOQ are of acceptable quality and a known uncertainty of 

±10 percent, and conversely, masses determined using the response factor approach are of unknown 

quality and uncertainty, they are merely estimates. 
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Response to Comment 20: The agency agrees with the commenter that this could be a concern, 

especially in light of the low Hg concentration levels that may be measured under this rule. Therefore, 

we are proposing in a separate rulemaking an amendment to Method 30B that would lower the specified 

Hg concentration for which the tester must have his sample results within the calibration curve from 0.5 

μg/dscm (current specification) to 0.01 μg/dscm. This will mean that in the future, concentrations down 

at least to 0.01 μg/dscm will be of known quality as described by the commenter.

Comment 21: Commenters 17725 and 18498 disagree with the EPA simply stating a generic 

MDL/LOQ for the entire Method 30B, as MDL and LOQ data collected vary among labs, analyzers and 

analysts. One commenter suggests that although the theoretically calculated MDL and LOQ has been 

shown to be as low as 2ng, in practice the QA/QC at that level is not obtainable. The commenters

believe that in practice 10ng is a reasonable range for the LOQ to collect data of acceptable quality and 

known uncertainty (i.e., ±10 percent) and 5ng is pushing the envelope on the lowest LOQ that should be 

used when evaluating low level effluent concentration data (i.e., ≤ 0.1μg/m3). The commenters suggest 

the response factor approach is used for merely estimating masses below the LOQ, but above the MDL

and should not be used when establishing an emission limit as the data of are of unknown quality and 

uncertainty. According to the commenters, it then follows for a typical ICR test (i.e., 2hr test run 

collecting 120l of volume) that effluent concentrations ranging between 0.04μg/m3 and 0.08μg/m3 are 

the lowest that can be reasonably be determined with acceptable quality and uncertainty. 

Response to Comment 21: The EPA agrees that, in general, the response factor approach in Method 

30B should not be used for estimating masses below the LOQ, but above the MDL when reporting 

emissions data for compliance determination as these data of are of unknown quality and uncertainty. It 

is the EPA’s intent to ensure that reported Hg emissions data are of known and acceptable quality. In 

response, the EPA is about to propose an amendment to Method 30B that would lower the specified Hg 

concentration for which the tester must have his sample results with the calibration curve from 0.5 

μg/dscm (the current specification) down to 0.01 μg/dscm. This will mean that in the future 

concentrations down to at least 0.01 μg/dscm will be of known quality. The EPA disagrees that effluent 

concentrations ranging between 0.04 μg/m3and 0.08 μg/m3are the lowest that can be reasonably be 

determined with acceptable quality and uncertainty. In fact, recent testing conducted as part of the 

Utility MACT ICR demonstrated that an average stack Hg concentration of 0.01 μg/m3could be 

measured as part of a triplicate 4 hour emissions test with all Method 30B performance criteria being 

met.

Comment 22: Commenter 17725 believes the EPA Methods 26A and 26 have proven to be reliable 

stack testing methods and produce high quality results; however, there are limitations with each method 

with regards to detection limits. The commenter questions if either method can consistently provide 

reliable data for compliance determination for the proposed limit as factors such as blank contamination, 

positive and negative biases due to flue gas interferences, and analytical errors raises questions. The 

commenter believes the proposed HCl emission limit of 0.00030 lb/MMBtu is very low with respect to 

the in-stack detection limit for HCl. The commenter notes that based on multiple sites that underwent 

testing during the ICR, in-stack detection limits were in the area of 0.000050 lb/MMBtu, and the ICR

required very long run times of 180 minutes for increased detection. According to the commenter, even 

with the long run times, the proposed emission limit was only six times greater than the in-stack 

detection limit for the HCl. The commenter asserts that in theory, HCl can be measured at this level but 

the issue is the ability to produce reliable, repeatable, high quality results this close to the detection limit. 

Response to Comment 22 The EPA agrees with the commenter’s description of math, but notes that an 

emissions standard that is six times the detection limit would be consistent with the setting the emissions 
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standards at no less than three times the RDL. While the EPA agrees that these levels will require 

extended runs times, the EPA disagrees that quality results cannot be achieved.

Comment 23: Commenter 17621 suggests that Method 29 does not have adequate sensitivity to 

measure antimony accurately at the alternative individual metal MACT limits for existing units. The 

commenter provides a table (Table B-1) which shows that at the individual metals MACT limits for new 

coal EGUs, most metals would not be measured accurately. The commenter notes that ASTM D6764-02 

states a lower limit of quantitation for Hg of 0.5 μg/m3, which corresponds to a stack emission for coalfired units of approximately 0.45 lb/Tbtu and this level of sensitivity is adequate to measure Hg at the 

MACT limit for existing coal units, but not at the limit for new units. The commenter also discusses that 

analytical detection limits do not consider the many sampling- and matrix-related factors that can raise 

detection limits at the stack. However, the commenter believes method sensitivity could also be better in 

practice than indicated in Table B-1 due to improvements in instrumentation and collection of larger 

sample volumes than required by the ICR. According to the commenter, therefore, this comparison was 

not given as much weight as the ICR results in the determination of method adequacy.

Response to Comment 23: The individual metal MACT limits have been reassessed to ensure that they 

are no less than three times the RDL. ASTM 6674-02 has been removed from Table 5 for use with 

compliance determination to ensure adequate sensitivity for compliance due to the sample volume 

restrictions of the method. The EPA agrees that method sensitivity will be improved in the future with 

improvements in instrumentation and the allowance to run higher sample volume than required 

minimums listed in Tables 1 and 2.
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5A05 - Testing/Monitoring: Operating parameter monitoring

Commenters: 17197, 17316, 17383, 17402, 17622, 17627, 17638, 17675, 17677, 17681, 17689, 17696, 

17705, 17715, 17716, 17718, 17725, 17730, 17736, 17740, 17752, 17754, 17757, 17758, 17761, 17767, 

17772, 17775, 17776, 17790, 17795, 17798, 17800, 17804, 17805, 17807, 17808, 17813, 17816, 17820, 

17821, 17856, 17868, 17870, 17873, 17876, 17881, 17886, 17902, 17912, 17914, 17923, 17925, 17928, 

18014, 18015, 18021, 18025, 18037, 18426, 18428, 18429, 18437, 18498, 18539, 19033, 19114, 19120, 

19121, 19536, 19537, 19538, 18023

1. Objections to parametric operating limits for units with CEMS (section 63.10007(c)).

Comment 1: Numerous commenters (17383, 17402, 17622, 17627, 17638, 17675, 17677, 17681, 

17689, 17696, 17705, 17715, 17716, 17718, 17728, 17730, 17736, 17740, 17758, 17761, 17767, 17772, 

17775, 17798, 17807, 17808, 17813, 17856, 17868, 17873, 17876, 17886, 17902, 17914, 17923, 17925, 

18015, 18025, 18037, 18428, 18429, 18437, 18539, 19114 19120, 19121, 18023) oppose the proposed 

control-device-specific operating limits for demonstrating ongoing compliance on units that are 

equipped with CEMS because these commenters believe such parametric limits are duplicative to the 

MACT floor emissions limits that EGUs must meet, unduly burdensome, decrease operational 

flexibility, make it difficult to operate control equipment at optimum efficiency, and/or inconsistent with 

longstanding EPA policies under 40 CFR part 64.

Comment 2: Several commenters (17775, 17868, 18539, 19120) state that proposed section 

63.10007(c) is unclear because it does not indicate whether every affected facility is subject to the 

requirements to establish parametric operating limits, and recommends that the final rule should make it 

clear that units with CEMS are not required to perform parametric monitoring or take operating limits. 

Commenters believe that the purpose of operating limits is to determine compliance between 

performance tests and that units with CEMS or sorbent traps would not require such limits. Commenters

17758 and 17868 state that the EPA has not provided justification for requiring units with CEMS to also 

perform parametric monitoring for the same HAP or surrogate.

Comment 3: Commenter 17868 states that section 63.10022(b) provides that if you demonstrate 

compliance through performance testing you must establish operating limits in Table 4. According to the 

commenter, since all EGUs must demonstrate initial compliance with each emission limit “through 

performance testing,” and the proposed rule defines “performance testing” to include the first 30 

operating days of CEMS data, the proposal appears to require that EGUs meet operating limits for all 

relevant control devices and load regardless of the “performance testing” option they choose (see, e.g., 

proposed section 63.10005(a) and Table 5 (including stack tests, CEMS, and LEES in the list of 

“performance testing” options)). The commenter observes that the other provisions cited in section 

63.10011(b) provide little clarification, that proposed section 63.10007 does not discuss applicability, 

and that with the exception of the filterable PM limit applicable to units using PM CEMS, Table 7 does 

not distinguish between compliance options; instead, Table 7 refers to various parameters depending on 

which control device “your operating limits are based on.” The commenter also states that section 

63.10011(c)(6) addresses fuel sampling, not operating limits and that section 63.10011(b)(6), the 

provision the EPA likely meant to cite, refers only to control devices and not compliance options. 

Commenter 17868 concludes that the preamble discussion contains numerous inconsistent statements 

and no rationale by which one could determine the EPA’s intent with respect to these operating limits 

for units using CEMS and sorbent trap monitoring systems.
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Comment 4: Commenter 17718 states that the EPA should require no proof of compliance beyond a 

properly calibrated and installed CEMS and that the EPA should revise both the language and tables in 

the rule to clarify its intent as it relates to CEMS used for demonstrating compliance. According to the 

commenter, HCl CEMS are not commercially available or adequate for in-stack measurements from 

electric utility units and likely will not be available by the compliance date of the rule. The commenter 

asserts that sources will be forced to either take a fuel limit or an operating parameter limit and that the 

fuel analysis limit is impractical as it relates to a coal-fired facility because of chlorine variability that is 

inherent in coal. that it will be impossible to control fuel deliveries in such a manner as to eliminate the 

possibility of burning coal with chlorine content above that which was used during compliance testing.

Comment 5: Commenter 18428 states that the preamble discussion contains numerous inconsistent 

statements and no rationale by which one could determine the EPA’s intent with respect to these 

operating limits for units using CEMS and sorbent trap monitoring systems. For example, according to 

the commenter, the EPA suggests in the following statements that operating limits apply only to units 

without CEMS:

 IGCC units or units combusting coal or solid oil-derived fuel with PM controls but not using PM 

CEMS to demonstrate continuous compliance would also be required to conduct parameter 

monitoring and meeting operating limits established during performance testing.

 The second option that we are proposing would be for units without SO2 or HCl CEMS but with 

SO2 emissions control devices. For these units, parameter operating limits established during 

performance testing, would be monitored continuously, along with the already-mentioned 

frequent (every 2 months) HCl emissions testing.

 When a performance test is conducted, we are proposing that parameter operating limitations be 

determined during the test. Performance tests to demonstrate compliance with any applicable 

emission limitations are either stack tests or fuel analysis or a combination of both, “ ... units 

equipped with devices that control PM and HCl emissions but do not elect to use CEMS, would 

determine suitable parameter operating limits ...”

The commenter notes that in another statement, the EPA suggests that all EGUs with PM controls must 

establish operating parameters, whether or not they have CEMS:

 ... those EGUs with PM emissions controls, without HCl CEMS but with HCI control devices, or 

for LEE, we are proposing that you monitor during initial performance testing specified 

operating parameters that you would use to demonstrate ongoing compliance.

Comment 6: Commenter 17775 asserts that the EPA must recognize that there are limitations on the 

conditions under which the EPA can require EGUs to establish operating parameters because to comply

with CAA section 112, the EPA assessed capabilities of controls under conditions specified in the 2010 

ICR and established compliance testing and compliance assurance requirements consistent with that 

assessment, and the EPA has proposed continuous monitoring, initial stack testing, or periodic fuel 

analysis that it presumably believes are consistent with that assessment.

Comment 7: Several commenters (17775, 17902, 17925, 18539) state that as long as an EGU is 

complying with one of the options for demonstrating “continuous compliance,” there is no basis to allow 

the Administrator to specify some other test be conducted under some other set of conditions.
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Comment 8: Commenters 17740 and 17808 are concerned about adding unnecessary costs for sources 

demonstrating continuous compliance via CEMS and is also concerned that the proposed requirements 

will duplicate existing requirements in title V CAM conditions.

Comment 9: Commenters 17873 and 17886 express concern that the secondary operating requirements 

also create a “double jeopardy” compliance risk: as long as the EGU MACT includes these limits, a unit 

could be in compliance with the underlying emission standard (and therefore protecting the 

environment) but find itself out of compliance with a related operating limit.

Comment 10: Several commenters (17775, 17808, 17813) believe that it is inappropriate to hold EGUs

to limitations on the operations of its controls set during brief performance testing periods that may not 

reflect the full range of operating conditions that can comply with the emissions limits. The commenters

express the need to be able to make adjustments based on coal variability and other operating conditions 

that can differ from the conditions occurring during performance tests. Furthermore, the commenters

express concerns that many coal units are utilized to generate variable intermediate loads to meet 

variable electrical power demands and thus, do not operate in the steady state associated with normal 

performance tests. Commenter 17716 contends that such normal load variations are inconsistent with the 

proposed requirement to establish a minimum pressure drop and liquid injection rate on a wet PM 

scrubber because normal pressure drops at low load will result in the reporting of deviations compared 

to pressure drop limitations set at high load. These commenters advise that when variable load 

operations are combined with variable coal properties, operating parameters can differ significantly from 

steady state performance test conditions. These commenters contend that based on their operating 

experience, as long as the unit is in compliance as measured with the CEMS, there is no need to track or 

limit operating parameters because they vary by design. Commenter 17705 notes that the EPA has 

recognized many times that CEMS represent the best available method for tracking compliance with 

emissions limitations at a regulated source, and the commenter refers to provision of 40 CFR part 64 

(the CAM rule) that state when a CEMS is specified by the applicable standard, the requirements of part 

64 do not apply to that emission standard. The commenter cites the following reference to CEMS from 

the preamble to the CAM rule: “The EPA believes that these types of monitoring are preferable from a 

technical and policy perspective as a means of assuring compliance with applicable requirements 

because they can provide data directly in terms of the applicable emission limitation or standard.”

Comment 11: Commenter 19121 states that they support the use of parametric and fuel data to show 

compliance when outlet monitoring is not available. However, the commenter states that for those HAP

where a numerical limit and a monitoring method is set, other secondary operating restrictions should 

not apply. According to the commenter, such an approach would severely curtail operating flexibility 

and limit demand response. 

Comment 12: Commenter 17767 states that it is unreasonable to assume that ongoing compliance 

would meet the operating parameter average if compliance could not be met during the compliance stack 

test. According to the commenter, the proposed rule makes no mention of the tolerance of operating 

parameter limits set during initial compliance testing for any pollutant or surrogate. The commenter 

asserts that if an average of the tests runs is used to set a limit, then even the initial passing compliance 

test would have periods of noncompliance during the runs with parameters outside the final averaged 

target parameters.

Comment 13: Commenter 18021 states that one set of operating conditions do not produce operating 

limits that are properly reflective of what our systems are capable of. The commenter notes that current 

operation must be flexible enough to meet not only load swings but also future regulations.
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Response to Comments 1 - 13: The rule does not require monitoring operating limits where a CEMS is 

used for the applicable standard. If a source has PM control equipment and uses a PM CPMS based 

operational limit, no control device monitoring is required. The same is true for HCl or SO2 controls for 

coal-fired and other solid fuel affected units. The only additional operating parameter requirement will 

be for liquid oil-fired EGUs whose owners or operators choose to use quarterly acid gas emissions 

testing. The appropriate parameters, monitoring method, QA/QC provisions, and data reduction 

requirements will be established in a site-specific monitoring plan; please see the final preamble for 

further discussion. With respect to the need for variability in establishing parameter limits because of 

load changes or changes in fuel, the rule provides for establishing different operating limits based on 

different loads. Also, see the response to the following comments about establishing “deviations” from 

operating limits.

2. Duplication of pollutant testing.

Comment 14: Commenter 17716 states that the EPA has established alternative compliance limits for 

various HAP groups, providing sources with flexibility to measure the PM limit, limits for individual 

metals, or a total non-Hg metals limit to establish compliance for metal HAP and to monitor SO2 or HCl

for acid gas HAP. The commenter states that the proposed rule requires stack tests not only for the 

pollutant but also for the surrogate. According to the commenter, performance tests should be matched 

to either the pollutants or the surrogates chosen by the source to show compliance, the extra tests are 

redundant.

Response to Comment 14: The EPA agrees that if the source elects to comply with an surrogate 

standard such as filterable PM instead of the alternative equivalent total or individual non-Hg HAP 

metals, then the only performance test to be performed is the test to show compliance with the emission 

standard that applies (in this example, the filterable PM limit). The final rule clarifies this position.

3. General objections to enforceable parametric operating limits (section 63.10007(c)).

Comment 15: Multiple commenters (17402, 17622, 17675, 17677, 17681, 17696, 17705, 17715, 17716, 

17728, 17730, 17775, 17800, 17808, 17873, 17912, 18023) find that the proposed requirements for 

operating parameters at section 63.9991(a)(2) particularly problematic because the proposed definition 

of “deviation” includes operating limits, but the commenters feel operating limits should not be a 

reportable deviation since they are indicators of compliance and not emission limitations.

Comment 16: Multiple commenters (17730, 17775, 17800, 17820, 17868, 17912, 17914, 18428) 

believe that the proposed usage of parametric operating limits deprives sources of the use of any control 

device margin, and allows enforcement for events beyond the operator’s control. Commenters state that 

the EPA’s current proposal is based on the faulty assumptions that the values of the parameters 

identified by the EPA have a direct relationship to the level of emissions, and that exceedances of those 

limits therefore indicate an exceedance of the emission limit. The commenters’ view of operating 

parameters is that to the extent possible, operators will contract for control equipment designs that 

provide a “margin of compliance” with applicable emissions limits. According to the commenters, in 

addition to reducing the possibility of an exceedance of the limit, this margin is intended to provide 

flexibility for the source to account for inevitable control equipment or operational problems. The 

commenters believe that under the proposed parametric monitoring regime, sources with a margin of 

compliance will lose part of that margin of compliance if they conduct performance testing under 

normal operations because they will establish operating limits that would require them to continue to 

over-control forevermore. The commenters suggest that the only way such sources could avoid 
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surrendering whatever margin of compliance they have would be to deliberately reduce performance of 

their controls to attempt to generate the least stringent operating limits consistent with achievement of 

the applicable emission standard. The commenters conclude that the proposal encourages sources to 

focus their attention on learning how to manipulate operations to allow testing as close as possible to 

their emission limit by reducing performance of their controls. These commenters generally believe that 

the parameter ranges in Table 4 must be established as corrective action levels, not enforceable 

operating limits and each of these commenters recommends that the final rule adopt provisions similar 

to those for CAM under 40 CFR part 64 for assuring continuous compliance with the MACT standards 

rather than the proposed provisions for parametric monitoring. Commenter 17775 refers the EPA to an 

attached report by McRanie Consulting entitled “Comments on the Proposed Utility MACT Rule -

Operating Parameters” (July 2011). Commenter 17675 states that other MACT standards like subparts 

LL and MM take the right approach to parametric monitoring. The commenter states that these standards 

require that corrective actions are taken to respond to parameter excursions and that the failure to take 

corrective action is a violation.

Comment 17: Several commenters (17675, 18037, 18429) generally believe that the CAM approach 

(that allows operators to propose excursion levels and response requirements for approval by the title V 

permitting authority) is a proven method of obtaining reasonable assurance of compliance while 

recognizing the wide variations in parametric ranges that can occur during operating periods that are in 

compliance with the underlying emissions limit.

Comment 18: Commenter 17912 states the operating parameters may push events beyond the operator’s 

control into an unavoidable enforcement posture. According to the commenter, for example, for 

compliance with the proposed total particulate emission limit for new and reconstructed EGUs, the 

proposed emission limit is 0.050 lb/MWh as measured by a manual stack test. However, the commenter 

asserts, if a CEMS for filterable particulates is used to demonstrate compliance, then, to be in 

compliance on a continuous basis, the owner or operator must “[m]aintain the PM concentration 

(mg/dscm) at or below the highest 1-hour average measured during the most recent performance test 

demonstrating compliance with the total PM emissions limitation.” The commenter states that to 

demonstrate continuous compliance, the EPA proposes to average the emissions measured by the CEMS

over 30 days for reporting purposes. Nowhere, however, according to the commenter, does the agency

explain how an emission limit derived from a single, one-hour measurement can reasonably be expected 

to account for the all of the variable conditions that may occur during any given day, let alone a month 

or a year. The commenter states that federal courts have explained that an emission standard is 

“‘achieved in practice’ [when it] is interpreted to mean ‘achieved under the worst foreseeable 

circumstances’” and cites Sierra Club v. EPA, 167 F.3d 658, 665 (D.C. Cir. 1999).

Comment 19: Commenter 17873 states that in setting operating limits the EPA unreasonably extends its 

authority beyond establishing the appropriate emission standard to governing the way a company

operates a unit to meet a standard. According to the commenter, the prescribed operating parameters 

(scrubber pH, etc.) and averaging method used to demonstrate compliance with those limits create a 

secondary and overlapping regulatory obligation likely to result in excessive control process cost and 

material waste.

Comment 20: Commenters 17873 and 17740 state that operating limits make it difficult to bring 

additional renewable resources on-line. Commenter 17873 states that designing operating strategies to 

include multiple process set points for control equipment at different loads is difficult. The commenter

notes that the ability of its coal generating units to change load quickly and efficiently is critical in 

accommodating variable wind energy. The commenter is concerned about the adverse effect on grid 
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integration due to such additional plant operating constraints at the same time the company is supporting 

significant renewable energy penetration on its system.

Comment 21: Commenter 17902 states that the deviation of operating limits does not necessarily

indicate that an emission limit has been exceeded, and in certain instances, could even suggest lower 

emissions (such as increased pressure drop for a baghouse control). According to the commenter, due to 

the stringency of the proposed MACT emission limits for EGUs, companies will not have an option to 

allow air pollution control equipment to operate below optimal levels or in a manner that would 

jeopardize compliance. The commenter recommends that the operating limits should only be applied in 

this rule as a work practice standard with deviations requiring investigation and corrective action as 

appropriate or necessary, but should not be considered non-compliance. The commenter further notes 

that this approach should be applied along with revising the compliance demonstration measurement to a 

12-month rolling average basis for the applicable MACT emissions limits in Table 1 or Table 2.

Comment 22: Commenter 17982 recommends that, instead effectively setting enforceable site-specific 

operating limits that would have to be met at all times in addition to the emission limit for the surrogate, 

the EPA should allow reasonable, flexible alternative compliance demonstration options, including less 

frequent periodic stack tests – no more often than annually – and longer averaging times. According to 

the commenter, it may be difficult to meet these site-specific limits at all times under all operating 

conditions.

Comment 23: Several commenters (18023, 1775, 17800, 17821, 17868) state that a CAM approach has 

already been upheld as sufficient to satisfy the CAA’s requirements for demonstrating continuous 

compliance in NRDC v. EPA, 194 F.3d 130, 135–37 (D.C. Cir. 1999).

Comment 24: Commenter 17705 states that no bases for the proposed parameters in Table 4 are 

presented in the technical support documents. Commenter 17705 adds that the EPA should not consider 

enforceable limits on control device operations unless the agency clearly demonstrates this is the only 

means of assuring compliant emissions. Commenter 17705 states that establishing the appropriate 

parametric limits must be done on a case-by-case basis as allowed under CAM rules.

Comment 25: Several commenters (17725, 17808, 18025) state that the proposed rule is not clear 

regarding what the required response action would be in the event that a unit violated its parameter 

operating limits, and the commenter suggests that a facility must initiate a corrective action to address 

the excursion similar to what is required in 40 CFR part 64 for CAM.

Comment 26: Commenter 17716 recommends an alternative approach to establishing representative 

control device operating ranges based on a statistical analysis of historical operating data during periods 

when the control device was operating properly.

Comment 27: Commenter 18023 takes exception to the stated assumption in the preamble that a 

baghouse or ESP can meet the proposed PM limits and the associated site-specific operating limits

continuously because under the rule, sources will not know the design criteria for the operating limit 

until after an initial compliance test that will not take into consideration plant variability. Therefore,

according to the commenter, it is unclear what control technologies will be necessary to meet the sitespecific limit continuously. Commenter 18023 states that the site-specific limit is completely

unworkable and must be removed and that even if the EPA refuses to remove the site-specific limit, the 

EPA must account for the added costs and burdens sources will inevitably encounter trying to meet sitespecific limits.
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Comment 28: Commenters 17870 and 18025 state that units with appropriate CAM plans and units 

operating CEMS should not be required to have additional monitoring requirements.

Comment 29: Commenter 17776 states that the inclusion of operating parameter limits in the proposed 

rule effectively lowers the numerical MACT floor. According to the commenter, it makes little sense to 

set a MACT floor then establish a mechanism to tighten the limit. Likewise, asserts the commenter, with 

a mandated monitor in place giving continuous, real-time readings in the units of the standard, the 

collection of control parameters for the purpose of compliance determinations is burdensome, but more 

importantly, completely unnecessary. The commenter states that in contrast, if the agency has 

confidence in the operating limits as a mechanism of compliance, then the mandated PM monitors are 

not necessary. According to the commenter, it should be noted that Hg and SO2 CEMS data was deemed 

sufficient by the rule to assure compliance without the use of operating parameter limits.

Response to Comments 15 - 29: The EPA believes that continuous monitoring in the form of CEMS, 

sorbent traps, or CPMS or that frequent emissions testing is needed to ensure ongoing compliance with 

this rule. In order to minimize costs and reduce burden, the rule has removed most operating parameters 

except for: (1) the owner-defined signal from the PM CPMS, which remains as an operating limit for 

those owners who choose to use PM CPMS; and (2) for acid gas emission limits, an owner-defined 

parameter monitoring approach for liquid oil-fired EGUs that do not use the fuel moisture certification 

approach, and do not use an HCl or HF CEMS, but instead rely on quarterly emissions testing. See the 

final preamble for further discussion. We have not required any other control device parameter 

monitoring in the final rule. While we recognize the importance of continued control device 

performance to ensure emissions minimization, we are aware that other rules that apply to these units -

including but not limited to the operating permits rule, the compliance assurance monitoring rule, and 

the new source performance standards – already require ongoing parameter monitoring. Those rules will 

remain in effect, so additional imposition of operating limits on those units would be redundant. The 

limited operating limit requirements in the final rule address options (such as the PM CPMS in lieu of 

quarterly testing) or the potential gaps for liquid oil-fired units.

4. Requests to make parametric monitoring requirements more like CAM Program.

Comment 30: Numerous commenters (17402, 17622, 17638, 17715, 17716, 17718, 17725, 17736, 

17757, 17775, 17804, 17808, 17816, 17820, 17821, 17856, 18014, 18025, 18037, 18428, 18429, 18498, 

18023) generally suggest that the final rule should incorporate more flexibility in setting parametric 

monitoring ranges similar to the existing CAM program. These commenters suggest the following 

specific revisions to proposed parametric monitoring provisions:

1. Several commenters (17716, 17725, 18498) state that some of the proposed parameters are either 

unnecessary, inappropriate, or could otherwise be substituted with parameters that are already

monitored; for instance, wet scrubber parameters could be simplified based on scrubber pH and a 

calculated liquid-to-gas ratio, where gas flow is measured using an existing stack flow monitor and 

liquid injection rate is estimated based on the number of recycle pumps in service. According to the 

commenters, for ESP-equipped units, the use of total power may not be representative of PM emissions 

since removal efficiency is dependent on where the power is applied in the control device. The 

commenters suggest that other alternatives might include the use of an ESP model for predicting 

performance or specifying a minimum power level within each gas path. The commenters state that 

these examples demonstrate other monitoring alternatives that provide a reasonable assurance of 

compliance while allowing operators to implement more cost effective monitoring programs.
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2. Multiple commenters (17402, 17715, 17689, 17808, 18037, 18539, 19114) believe that the EPA 

should revisit the way operating parameters are set during performance tests that are typically completed 

during high-load, steady-state conditions because the operating parameters captured during these tests 

may not represent the variability of day-to-day operations across the full range of operating loads. 

Commenter 17808 recommends that units with appropriate CAM plans should not be required to have 

additional monitoring requirements. Commenters (17715, 17718, 17736, 17757, 17816, 17856, 18037, 

18539, 19114) express concerns with operating limits changing every 2 months based on the most recent 

performance test and the challenges of continuously revising operating procedures and alarm points. The 

commenters are concerned that sources will have no confidence that they will be able to demonstrate 

compliance over the full range of operating conditions that are normal for the source, and permitting 

authorities will have an impossible task to track different sets of operating limits for each unit in their 

jurisdiction.

3. Multiple commenters (17402, 17718, 17627, 17736, 17757, 17816, 18037, 18539, 19114) believe that 

as currently proposed, units would be constrained by unachievable operational parameters because the 

set of operating limits that a unit measures during its first performance test would be its maximum 

operating limits. According to the commenters, subsequent performance tests would further ratchet 

down operating parameters until they are no longer achievable during a 30-day or annual averaging 

period. The commenters state that control equipment operating characteristics during full load testing 

will not be suitable to monitor low load performance.

Commenters 17775 and 17868 state that even the “detuning” of a control device during performance 

tests will not ensure associated operating limits are necessary for compliance with the underlying 

emissions limit. Several commenters (17775, 17800, 17820, 17821, 17868, 18428) add that the EPA has 

previously recognized in the context of the NSPS and the CAM rule, “many sources operate well within 

permitted limits over a range of process and pollution control device operating parameters,” and 

requiring sources to continuously maintain parameters that “happened to exist” during the most recent 

performance test may not be “possible or wise.” 62 FR 54,900, 54,907, 54,926-27.

Multiple commenters (17718, 17775, 17800, 17820, 17821, 17816, 17868, 18428) state that the 

proposed control device parameters do not necessarily have a direct relationship to emissions but instead 

are interrelated with various parameters so that a single parameter may vary widely with little effect on 

emissions. The commenters acknowledge that the proposed provision of a 10% difference from the 

average tested value recognizes some of the normal operational variability of control devices, but 

believes the 10% margin will not be sufficient in some cases. The commenters conclude that without a 

clear correlation between the proposed operating parameters and emission limits, imposition of those 

values as enforceable limits unreasonably restricts operations and subjects operators to potential 

enforcement without any reliable evidence of emissions exceedances.

4. Commenter 17402 recommends that the operating limit should be based on the least stringent of the 

three minimum performance test runs and not the average of the runs (assuming, of course, that all three 

test runs demonstrated compliance with the MACT emission limits) because this would help account for 

real-world variability in operating parameters and would assure compliance because this testing certifies 

that when those (least stringent) operating parameters are met, the facility still meets the MACT limits. 

Moreover, the commenter believes, as long as the facility is in compliance via a certified CEMS or stack 

testing, there is no need to track the instantaneous values of operating parameters.

5. Commenter 17402 states that the normal variability of operating conditions further suggests that 

greater flexibility is needed for operators to substitute the EPA’s proposed parameters, some of which 
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are unnecessary or inappropriate, with parameters that are either already monitored by the facility or 

parameters that would allow the EGU to implement more efficient monitoring. The commenter suggests 

that the required parameters proposed for wet scrubbers could be simplified to simply scrubber pH and a 

calculated liquid-to-gas ratio, where gas flow is measured using an existing stack flow monitor and 

liquid injection rate is estimated based on the number of recycle pumps in service. The commenter

advises that FGD pressure drop varies with load and the number of recycle spray pumps that are in 

service, and therefore, the absorber pressure drop is not a good indicator of FGD performance. The 

commenter also advises that the proposed parametric requirements for ESPs (to establish minimum 

hourly average secondary voltage and secondary amperage and calculate the total secondary power input 

measured during the three-run performance test) fail to take into account which fields are being powered 

and where in the precipitator they are located. The commenter further advises that the appropriate 

secondary power will also vary with fuel and load making a minimum level set at a full load test 

inadequate to assure compliance at all loads.

6. Multiple commenters (17402, 17627, 17757, 17821, 18023, 18037, 18539, 19114) refer to existing 

requirements under 40 CFR part 64 commonly known as CAM plans in title V permits and state that the 

final rule should use the CAM program as the basis for parametric monitoring plans. The commenters

suggest that source operators should be able to rely on this existing framework, and to work with 

permitting authorities to develop a set of parameters that make sense for the facility and its control 

configuration. Commenters (17402, 17627, 17757, 18539, 19114) state that CAM plans were 

specifically developed to assure PM limit compliance through the measurement of opacity even though 

opacity is not a direct measurement of PM, but permitting authorities recognize opacity as an indicator 

of control device performance, and there are approved plans that have formally documented the 

appropriate use of this indicator in an ongoing monitoring program.

7. Several commenters (17402, 17725, 18014, 18498) state that normal variability of operational 

parameters should be taken into consideration in the EPA’s proposed procedures for establishing the 

compliance ranges. According to the commenters, the EPA proposes that EGUs would be required to set 

parameters based on 4-hour block averages during compliance tests and would demonstrate continuous 

compliance by monitoring 12-hour block average values below or above the lowest or highest 1-hour 

average measured during the most recent compliance test. The commenters do not believe that this 

approach adequately accounts for variability due to normal operation in some cases because (for 

example) the requirement to maintain a minimum pressure drop and liquid injection rate on a wet PM 

scrubber will result in the reporting of deviations during low generating loads. The commenters provide 

as another example the requirement to maintain sorbent injection rate at the rate established during the 

compliance test and state that such a requirement may result in the unnecessary reporting of deviations 

when these units fire lower pollutant-containing fuels. The commenters suggest that an alternative 

approach for establishing a more representative set of normal control device operating ranges might be a 

statistical analysis of historical operating data during which the control device was operating properly

(no malfunctions). According to the commenters, the resulting operating limits could be discreet upper 

and lower bounds on certain operating parameters or a correlation between the control device operating 

parameter and one or more boiler operating parameters. If operating parameters are required, variability

must be addressed. Therefore, one commenter recommends that the EPA should increase the averaging 

period from 12-hour block averages to 30-day rolling averages.

Similarly, other commenters (17808, 17870, 18025) state that setting an unreasonable operating limit 

that fails to reflect the full variability of the plant’s operating conditions could damage the control 

technology. For example, according to the commenters, the proposed rule requires a plant operator to 

measure the voltage and current of each ESP collection field during each Hg, PM, and metals 
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performance test, and the average of the three minimum hourly values would then be used to establish a 

unit’s site-specific minimum voltage and current operating limits for the ESP. According to the 

commenters, maximizing power input and electric field strength will generally maximize ESP collection 

efficiency and plant operators need a degree of flexibility to balance the power input to the ESP in order 

to avoid serious damage to the system and downtime. The commenters note that power input to an ESP 

is dynamically controlled by an automated voltage control system to maximize power levels while 

avoiding sustained arcing or sparking between the electrodes and the collecting plates, which can 

damage the ESP, including the transformer-rectifier and other components in the primary circuit and that 

automatic voltage control varies the power to the transformer-rectifier in response to signals received 

from sensors in the precipitator and the transformer-rectifier itself. According to the commenters, power 

levels will vary depending on the amount of moisture in the air, accumulated ash levels, and other 

factors, and as result, sustaining a minimum voltage and current level may not be possible or appropriate 

at all times, and could damage the control technology.

8. Several commenters (17775, 17800, 17821, 17868) state that sources are in the best position to 

determine what parameters and levels are consistent with compliance. According to the commenters, in 

many cases, multiple parameter relationships or supplemental operational data will provide a higher 

level of compliance assurance than the level that happens to be measured during a discrete performance 

test. The commenters assert that this is particularly true for sources with a significant margin of 

compliance (see EPA-HQ-OAR-2002-0058-0413, Attachment C at 4). The commenters recommend 

allowing extrapolation of parameter data to preserve operational flexibility and avoid repeated testing. 

According to one commenter, attempting to establish “worst case” test conditions on a scrubber or 

multi-section ESP, where the possible combinations of parameters are numerous, would at the least be 

difficult and could be impossible without a major research effort. The commenters assert that allowing 

extrapolation of results avoids the necessity of repeated testing. The commenters note the a similar 

approach has been used in CAM protocols for ESPs allowing extrapolation up to 1.25 times the recorded 

value for measurements at less than 80% of the applicable limit. Several commenters (17775, 17800, 

17820, 17821, 17868, 18428) recommend a CAM-like approach where once established parameter 

would be monitored for deviations that would triggers corrective actions. The commenters note that 

while the parameter range may in some cases be similar to the minimum values that would be 

established under the proposed rule, allowing sources to respond with corrective action (rather than 

simply record exceedances and report deviations) achieves the intended result without subjecting 

sources to potential unreasonable enforcement.

Response to Comment 30: As noted above, the rule does not require monitoring operating limits where 

a CEMS is used for the applicable standard. With respect to the need for variability in establishing 

parameter limits because of load changes or changes in fuel, the rule provides for establishing different 

operating limits based on different loads. Note that the ability to use parameter monitoring is a choice 

made by the owner or operator. Where parameter monitoring is chosen, we believe that continuous 

monitoring is needed to ensure ongoing compliance with this rule. As mentioned earlier, we require 

performance tests to demonstrate compliance with emission limits, we then use operating limits to 

ensure the source is operating similarly to how it was operating when it completed a successful 

performance test. Operating limits are not direct measures of emissions, but provide a measure of fuel 

characteristics and control device performance, and are established as enforceable operating limits 

routinely in NESHAP standards. You are also able to petition the Administrator for approval of an

alternative monitoring plan under section 63.8(f) of subpart A of Part 63. This would include the 

possibility of adapting existing CAM plans that may rely on different parameters. Finally, we agree with 

commenters that collecting continuous data, transforming it to 1-hour averages, and then calculating a 

30-day rolling average based on those 1-hour averages should address any variability concerns; 
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therefore the rule now contains a 30-day rolling average for the PM CPMS parameter. For acid gas 

emission limit compliance at liquid oil-fired units that use quarterly testing to demonstrate compliance, 

you will propose a site-specific operating parameter monitoring plan for your facility that should include 

the appropriate monitoring methods, QA/QC, and data reduction specifics for your unit. See the final 

preamble for further discussion.

5. ESP total secondary electric power (TSEP) requirements (section 63.100010(h)(2)(iii)).

Comment 31: Several commenters (17402, 17715, 17775) express concern about proposed 

requirements under section 63.100010(h)(2)(iii) for EGUs that have an operating limit requiring a total 

secondary electric power (TSEP) monitoring system on an ESP. Commenter 17402 requests that the 

EPA clarify how secondary power is calculated and if power is calculated on a field-by-field basis or 

across the whole ESP. Commenter 17715 states that this parameter fails to take into account which 

fields are being powered and where in the precipitator they are located. Commenter 17402 advises that 

under the EPA’s proposal, this monitoring will be problematic because ESP power and PM collection 

efficiency vary by ESP configuration, fuel quality (coal sodium content), ash resistivity, number of 

electrical and mechanical fields, plate alignment, gas flow distribution, gas temperature, particle size and 

chemistry, rapper/vibrator settings, and air in leakage. The commenter has observed ESP power 

fluctuations of 20 percent during steady-state operation, and during startup and shutdowns, the ESP 

power shows even greater fluctuations–as high as 83 percent from high to low load. Commenter 17715 

states that a TSEP minimum level set during a full load test is inadequate to assure compliance at all 

loads.

Comment 32: Several commenters (17775, 17800, 17868, 18428) request that the agency review the 

discussion on ESP performance in a report by McRanie Consulting entitled “Comments on the Proposed 

Utility MACT Rule - Operating Parameters” (July 2011) that was attached to their comments, because 

the report explains why proposed section 63.10011(b)(6)(iii) is flawed. According to the commenters, 

Mr. McRanie explains that ESP power input simply is not directly related to PM removal performance 

(particularly for the modern multi-section ESPs that are likely to be installed to comply with a proposed 

MACT standard), and the total amount of power is not nearly as important as the location at which the 

power is being applied in the ESP. The commenters refer to an attached report indicating that ESP 

parameters are likely to have no relationship to PM emissions at units that also have a wet scrubber, 

because wet scrubbers are highly effective in controlling high levels of PM from an ESP that is not 

performing at the intended control efficiency.

Comment 33: Commenter 17775 points out that many EGUs have discovered while seeking the high 

dust loads required under PS11 that even a fully disabled ESP may have little effect on resulting PM 

concentrations when a wet scrubber is operating at expected efficiency. Commenter 17775 concludes 

that EGUs should not be penalized for an ESP failure if another control, like a wet scrubber, is capturing 

the resulting PM.

Comment 34: Commenter 17800 states that when an ESP is used in combination with a wet scrubber 

the rule imposes operating limits on secondary power input to the ESP collection plates. (Section 

63.10011(b)(6)(iii)). According to the commenter, the EPA’s proposal is flawed. ESP power input 

simply is not directly related to PM removal performance, especially with a wet FGD following the 

ESP. According to the commenter, none of the ESP parameters are likely to have any relationship to PM 

at units that also have a wet scrubber, since those systems also are highly effective in controlling high 

levels of PM coming out of an ESP that is not performing at its intended control efficiency.
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Comment 35: Commenters 17402 and 17808 use the example of normal ESP operation to explain why

the proposed parametric constraints could lead to increases in emissions or damage to the control device. 

Commenter 17402 states that current, voltage, and total power are constantly reacting to boiler ash 

conditions, flue gas temperature, flue gas moisture, coal quality, coal moisture, flue gas flow rate, ESP 

cleanliness, ESP ash buildup, and fuel heat input. Commenter 17402 states that operating limits for 

control equipment based on a point-in-time stack test do not recognize the balancing act that plant 

operators perform daily to meet emission limits for not just HAP but all of the pollutants that are 

currently regulated. 

Comment 36: Commenter 17808 agrees with the principle underlying the proposed parametric 

constraints on ESPs (i.e., that maximizing power input and electric field strength will generally 

maximize ESP collection efficiency), but the commenter states that plant operators need a degree of 

flexibility to balance the power input to the ESP in order to avoid serious damage to the system and 

downtime because the power input to an ESP is dynamically controlled by an automated voltage control 

system to maximize power levels while avoiding sustained arcing between electrodes and collecting 

plates, which can damage the ESP; automatic controls adjust power in response to various sensors so 

that normal power levels will vary depending on the amount of moisture in the air, accumulated ash 

levels, and other factors. Commenter 17808 advises that this core functionality of ESPs may make the 

proposed constraint for minimum voltage and current level inappropriate at certain times, and such a 

requirement could damage the control technology.

Comment 37: Commenters 17808 and 17725 recommend that the final rule require proper operation of 

the plant’s pollution control equipment and appropriate parametric monitoring without establishing 

numeric operating limits.

Comment 38: Commenter 17772 notes that total secondary electric power is a poor measure of ESP 

performance. According to the commenter, this is especially true if it is tied to a minimum power 

concept. The commenter states that on some days particulate loading to an ESP can be low, yielding a 

lower number of fly ash particles to be charged. Moreover, according to the commenter, during periods 

of low loading, total power can go down to levels lower than that which may have been observed during 

the compliance test day if a larger number of fly ash particles were being sent to the ESP during the 

compliance test; voltage may still be high, but because current is lower; total power is lower, and that 

does not mean that the ESP is operating poorly relative to the compliance test levels. In such instances, 

according to the commenter, it is either not possible to maintain a high level of current or, if possible, it 

may be a waste of energy. Commenter 17772 believes that the requirement to maintain “the 12-hour 

average secondary power input at or above the operating limits established during the performance test”

as required in section 63.10011 (c) is inappropriate and is not a true indicator of the operating condition 

of the ESP.

Comment 39: Commenter 17821 states that the secondary power approach for ESPs simply does not 

work and this fact is easily demonstrated by real world operating experience. According to the 

commenter, precipitator power will vary depending upon a number of factors, including operating 

conditions, coal quality, load, and other factors. According to the commenter, this is a phenomenon that 

the commenter routinely sees in the operation of its own units. The commenter states that precipitator 

operation is complicated even further with the addition of sorbents into the flue gas for emissions control 

and that different fuels may require more or less dry sorbent injection, and those fuels will also cause 

changes in precipitator operation. According to the commenter, these changes will likely result in a 

change in the total secondary power to the ESP but not necessarily a reduction in removal efficiency. 

The commenter states that the proposed rule should instead require site-specific plans to be developed 
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for each EGU. According to the commenter, because ESP designs vary greatly, the parameters selected 

may include total percent of fields in service, or a limit on the number of fields in a given train that may

be out of service at one time. 

Comment 40: Commenter 17881 states that under Table 4 – Operating Limits for EGUs for ESPs, the 

requirement for ESPs conflicts with section 63.10011(b)(6)(iii), which does not impose a caveat on the 

ESP operating parameters such that it only applies to units with wet controls. The commenter further 

notes that the power input is calculated as the three-run average and not the lowest single run. 

Comment 41: Commenter 17925 states that monitoring of total secondary power of the ESP should be 

optional if more representative parameters can be shown to be acceptable. According to the commenter,

the EPA publication EPA-340/1-83-017 states that the efficiency of an ESP is directly related to the 

power delivered to the gas stream (watts/1000 acfm, page-171) and supports the notion that total 

secondary power of an ESP could be the monitoring parameter for ESPs. According to the commenter, 

however, using secondary power of each ESP operating field as the parameter, or total secondary power 

of the entire ESP, requires that combustion units maintain the same power level target parameter at 

lower fuel loads, which is difficult to accomplish. The commenter asserts that targeting of secondary 

power in each field is unnecessary for successful monitoring and compliance. The commenter

recommends monitoring of total power to the ESP as a more practical parameter to work with than 

power to the individual fields if adjusted for changes to unit operating rate. To account for lower ESP 

power at lower operating fuel loads, the commenter suggests that the ratio of watts/1000 acfm should be 

monitored and targeted. According to the commenter, since the gas flow rate is generally proportional to 

the fuel firing rate, a surrogate for gas flow is fuel input rate. Therefore, according to the commenter, an 

alternate surrogate for total ESP secondary power when the fuel is, for example, coal, would be total 

secondary power divided by total coal input rate or watts/pound. According to the commenter, this total 

secondary power to fuel ratio parameter has been used in the past at combustion units to meet MACT

requirements for ESP parameter monitoring and has been found to be acceptable both on a technical and 

regulatory basis. The commenter asserts that monitoring and setting the operational target for an ESP 

using this parameter ratio is superior to monitoring secondary power per field or even total secondary 

power to the entire ESP unit because it dampens the impact on the signal of unit operating rate.

Comment 42: Commenter states that difficulties can be encountered when attempting to set operating 

parameters entirely based on stack testing. According to the commenter, experienced equipment 

operators would not be willing to run equipment at potentially unsafe operating conditions that are not 

considered representative of normal operation, simply to provide set operating parameter ranges. The 

commenter also notes that while ESP power, a parameter that must be monitored as described in the 

EGU MACT rule, at minimum power, provides good ESP performance information, it is not necessarily

a reliable indicator of poor performance. The commenter states that lower power generally means poorer 

performance, but ESPs are segmented into many electrical sections and the power consumption for each 

section relative to its physical location can mean that similar power consumption scenarios can provide 

different levels of emissions control. According to the commenter, this type of information would be 

difficult to verify through stack testing, considering other variables like fuel quality, varying loads, etc.,

but can be easily evaluated using an ESP performance model. The commenter notes that where CEMS

are available that information should be used to evaluate excess emissions. 

Comment 43: Commenters 17775 and 17790 recommend the use of boiler models or emissions models, 

in addition to manufacturer specifications, to set up acceptable operating ranges. The commenter notes 

that, for example, in the CAM Program, the use of models and manufacturers information is allowed and 

that in the guidance document “Compliance Assurance Monitoring (CAM) Protocol for an Electrostatic 
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Precipitator (ESP) Controlling Particulate Matter (PM) Emissions from a Coal-fired Boiler”, use of ESP 

models is recommended, and the commenter refers to page 5 of this document: “An approach that has 

been demonstrated to provide a reliable indication of ESP performance is the use of an ESP performance 

computer model calibrated using site-specific data and other data in conjunction with continuous opacity

data.” Commenter 17775 states that the EPA should include in this rule an option similar to subpart Da

to use an ESP model on a daily basis to assess proper operation of an ESP in between performance tests. 

According to the commenter, if the use of the model as required under subpart Da is sufficient to assure 

compliance with the NSPS, it also should be sufficient under subpart UUUUU.

Response to Comments 31 - 43: Although the EPA notes some owners and operators have been 

successful in using parameters to model ESP performance, the comments are inapplicable, for the rule 

no longer requires parameter monitoring or operating limits for PM control devices.

6. Parametric limits for wet scrubbers (section 63.20011(b)(6)).

Comment 44: Commenter 17775 expresses concerns with the proposed parametric operating limits for 

wet scrubbers at section 63.20011(b)(6)(i) and (ii); the commenter states that the proposed parametric 

ranges established during performance tests lack a sufficient relationship with actual emissions over 

normal operating ranges. The commenter references an attached report indicating that the normal pH in 

a scrubber can vary significantly, but that as long as pH is within the normal range, its impact on 

scrubber efficiency is minor. According to the commenter, however, if pH falls too low, metal 

components can corrode, and if pH is too high, calcium sulfate deposits can develop. The commenter 

states that as a result, operators monitor pH to ensure it is within the desired range and react to bring pH 

back within that range if necessary. According to the commenter, operators have no incentive to allow 

pH to fall outside the normal range. Commenter 17775 concludes that requiring operators to artificially

maintain pH to the level during a performance test is not a useful requirement.

Comment 45: Commenter 17821 states that pH measurement is not sufficiently related to acid gas 

removal to apply enforceable limits. According to the commenter, the measurement of pH in an FGD

system is only a small part of the very complex chemistry in an SO2 removal system; the pH is mainly

used to prevent scaling of the modules. The commenter asserts that maintaining a higher pH does not 

guarantee any additional removal of SO2, HCl, or other acid gases, but that higher pH values will lead to 

scaling, which may lead to other operational problems. The commenter states that as an example, scaling 

can cause plugging of mist eliminators, which in turn could potentially increase particulate emissions. 

The commenter notes acid gases such as HCl and HF are strong acids and very readily dissolve in water, 

whereas SO2 is a weak acid, which explains why its transport from the gas phase into the liquid phase in 

a scrubber occurs at a slower rate. According to the commenter, the EPA acknowledges that acid gases 

are likely to be removed in typical FGD systems due to their solubility or their acidity (or both). The 

commenter states that the conclusion is that HCl and other acid gases are very effectively removed by

contact with water in a wet FGD system, so effectively removed in fact, that high removal rates will be 

maintained even at pH levels below those used for effective SO2 removal, provided there is an adequate 

recirculation flow. Instead of requiring FGDs to maintain a specified pH, the commenter suggests that 

the rule should require that sites develop site specific plans that incorporate parameters that more 

appropriately describe the operation of an FGD system. For example, the commenter suggests that

stations may elect to use parameters such as number of absorber recirculation pumps in service, 

measured SO2 levels from CEMS measurements, or other facility specific measurements.

Comment 46: Commenter 17821 states that there is ambiguity in what the EPA wants to restrict. There 

are two potential liquid flows in an FGD system; the first is the amount of chemical reagent that is added 
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to the FGD module. According to the commenter, this is most commonly either a water slurry of lime or 

limestone, the concentration of this material varies depending upon the operating condition, and the 

mass flow rate of reagent is directly proportional to the mass of SO2 that is removed in the scrubber per 

unit of time. According to the commenter, because the chemical reagent must be added at the proper 

stoichiometric ratio, it is totally inappropriate to require a fixed feed ratio based on full load, worst-case 

conditions; doing so will damage the FGD system and will render it ineffective for removing SO2 and 

other acid gases. As a result, the commenter concludes, the EPA is not attempting to regulate lime or 

limestone reagent flow but instead seeks to regulate the total amount of liquid flow that is recirculated in 

the module and sprayed into the flue gas stream. The commenter states that FGD modules use one or 

more recirculation pumps to remove large volumes of FGD liquor from a reservoir in the bottom of the 

module and spray it into the flue gas; these are high volume, centrifugal pumps that run at a single 

speed. According to the commenter, most sources do not normally install flow meters in this situation, 

and installing monitors in this application will not achieve the accuracy that the EPA specifies. The 

commenter states that most new FGD installations utilize fiberglass reinforced piping (FRP) to transport 

recirculation flow through the FGD module. According to the commenter, the FRP increases reliability

but is not conducive to external flow measurement techniques, and further complicating the matter is 

size of the piping—the larger the diameter, the more difficult to obtain accurate readings. According to 

the commenter, flow meters with the proposed accuracy of 2 percent are not practical for these FGD

installations. The commenter states that internal flow meters may be able to provide more accurate 

readings immediately after installation, but the harsh conditions of the FGD will cause them to lose 

accuracy quickly. In any event, according to the commenter, the length of FGD piping is short compared 

to its diameter, and has many elbows and fittings, so it typically does not have enough straight lengths of 

pipe to allow for the installation of highly accurate flow monitors. According to the commenter, even if 

the recirculation flow rate could be measured to the desired accuracy, those measurements would not tell 

the whole story. The commenter states that in a properly operating FGD system, the density of the 

recirculation flow has to change with different operating conditions to maximize removal efficiency and 

that when the density of a material being pumped increases, the volume of flow through a centrifugal 

pump decreases. According to the commenter, FGD operators do not have control over this recirculation

flow because the piping systems do not have any sort of flow control valves. In short, the commenter 

states, a recirculation pump is either on or off, and . therefore attempting to maintain volumetric flow 

rates at a level established during the performance test will cause operators to chase process parameters 

that would be counterproductive to achieving the best removal efficiency.

The commenter states that the EPA should also realize that when an EGU reduces its load, the volume 

of flue gas passing through the FGD system decreases, but the amount of recirculation flow stays 

relatively constant. According to the commenter, this results in an increase in the liquid to gas ratio, 

which in turn promotes even more efficient scrubbing. Therefore, the commenter states, the more 

appropriate metric would be to require that EGUs be required to maintain a minimum recirculation flow 

to gas ratio instead of a simple minimum liquid flow rate. According to the commenter, that would best 

be accomplished by requiring a minimum number of pumps to be kept in service at all times as 

demonstrated during the performance test, and as a result, flow monitors would not be needed or 

installed. In addition, the commenter states, it would be appropriate for the EPA to require sources to 

demonstrate that the flue gas is indeed going through the scrubber module and is not being bypassed. 

According to the commenter, these parameters will adequately ensure that the FGD operation will 

properly remove the acid gases that will be regulated in the final rule.

Comment 47: Commenter 17821 states that restricting FGD modules to minimum pressure drop 

requirements has no benefit. According to the commenter, in the proposed rule, stations would be 

required to measure differential pressure across the FGD module(s) during the annual performance tests, 
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and maintain a 12-hour pressure drop value above the average measured in the performance test. The 

commenter asserts that like other limits the EPA has proposed, this limit fails to account for reduced 

load operation. According to the commenter, FGD pressure drop is a direct function of the amount of 

flue gas flow through the module, and thus is directly related to boiler load. In a case where velocity 

doubles, the commenter stats, the pressure drop would quadruple. The commenter asserts that the 

reverse is also true, in that as the load drops, the scrubber pressure drop would also decrease. According 

to the commenter, there are different types of FGD systems such as open spray towers, and units with 

trays; however for all these designs, a reduced pressure drop at lower load does not by itself indicate a 

reduced level of HAP capture in a FGD system. In fact, according to the commenter, the scrubber 

performance is more likely to improve at reduced load because there is a higher ratio of liquid flow to 

flue gas flow; pressure drop is more a function of mist eliminator cleanliness than acid gas removal. The 

commenter notes that there may be steady state systems, such as waste combustors, where measuring 

pressure drop could be useful. The commenter asserts that instead of using pressure drop to demonstrate 

compliance, the EPA should require sources to develop site-specific plans to ensure the effectiveness of 

the FGD for particulate removal and acid gas removal, which would then be subject to review by state 

and local agencies and contain more appropriate requirements such as maintaining a minimum number 

of recirculation pumps in service, eliminating any bypasses of the FGD system, and periodically

inspecting internal components.

Comment 48: Commenter 18428 states the EPA’s proposal to use pH, pressure drop and liquid flowrate as operating parameters for wet scrubbers is subject to the same flaws as the EPA’s other proposed 

operating limits -- namely the lack of a sufficient relationship between the parameters measured during 

performance testing and actual emissions. For example, the commenter states, because scrubber pressure 

drop, liquid flow rate, and sorbent injection rate vary with boiler load, establishment of a limit based on 

conditions during performance testing may tell the EPA little about actual emissions under other load 

conditions.

Comment 49: Several commenters (17775, 17868, 17800) state that because scrubber pressure drop, 

liquid flow rate, and sorbent injection rate vary with boiler load, establishment of a limit based on 

conditions during performance testing may tell little about actual emissions under other load conditions. 

Moreover, according to the commenters, when the EPA in 2008 considered the relationship between 

liquid flow rate and PM in the context of the NSPS for electric steam generating units at 40 CFR subpart 

Da, the EPA concluded that, at the level of the NSPS (i.e., 0.015 lb/MMBtu), PM emissions controlled 

by an ESP were not particularly sensitive to the actual liquid flow rate (U. S. The EPA “Response to 

Public Comments on Rule Amendments Proposed June 12, 2008 (73 FR 33642)” (Nov. 2008), U.S. 

EPA-HQ-OAR-2005-0031-0284, at section 2.5.3).

Comment 50: Multiple commenters (17736, 17715, 17627, 17757, 18037, 18539, 19114) state that the 

proposed rule lays out a method to establish site specific operating limits for various types of control 

equipment in Tables 7 and 8. According to the commenters, for example, a wet scrubber would be 

required to meet site-specific operating limits for pressure drop and liquid flow rate for compliance with 

the PM standard. The commenters note that pressure drop and liquid flow rate may not be applicable to 

all types of wet scrubbers and that the parameters may not be directly related to emissions. According to 

the commenter, pressure drop is not a direct measurement of emissions and will naturally vary with load. 

The commenters also suggest that liquid flow rate is also a function of load and the ability to measure it 

accurately may be a problem. According to the commenter, the same issues are encountered when using 

these parameters as a metric for demonstrating continuous compliance with the HCl limits.
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Comment 51: Commenters 17775 and 17881 state operating limits are not direct measurements of 

emissions or compliance. The commenters state that the proposed rule includes a requirement for wet 

scrubber controls to maintain a pressure drop across the scrubber and a minimum liquid flow rate. The 

commenters note that pressure drop is not used for control purposes, it is used to determine when 

cleaning is required and is not necessarily accurate for assessing scrubber performance. Commenter

17775 states that the EPA must also recognize that Chiyoda scrubbers operate on a completely different 

set of parameters than typical spray towers and that L/G is a more useful indicator for some types of 

scrubbers. Commenter 17881 notes that under Table 4 – Operating Limits for EGUs for wet acid gas 

scrubbers the requirement states to maintain a minimum pH. Controlling pH is a maintenance incentive 

to prevent corrosion to major scrubber components. According to the commenter, the pH of the scrubber 

vessel is an indication of the limestone slurry feed into the vessel, not the effectiveness of the slurry

spray.

Comment 52: Commenter 18023 states that pressure drop and liquid flow rate are not indicators of the 

level of PM control being achieved by a wet scrubber. According to the commenter, the establishment of 

operating limits for pressure drop and liquid flow rate would unnecessarily limit the range of key FGD 

operating parameters. According to the commenter, pressure drop is not a universal indicator of the PM 

control achieved by wet scrubbers (Commenter refers to Figure 26 in its comment). According to the 

commenter, PM control by a modern jet-sparging type scrubber is not a function of pressure drop (three 

figures are provided in the document showing PM control vs. pressure drop, liquid flow rate and liquidto-gas ratio). The commenter further notes that liquid flow rate is not a universal indicator of the PM 

control achieved by wet scrubbers. In the commenter’s experience, PM removal by a modern spraytower-type scrubber varies widely for different liquid flow rates. According to the commenter, PM 

control is also not a function of liquid-to-gas flow rate.

With respect to HCl scrubbing, the commenter states that HCl is not easily monitored on a continuous 

basis in flue gas. According to the commenter, pressure drop, liquid flow rate, and pH are not indicators 

of the level of HCl control being achieved by a wet scrubber, and the establishment of these operating 

limits would unnecessarily limit the range of key FGD operating parameters. The commenter states that 

HCl control by modern jet-sparging type scrubbers is not a function of liquid submergence (or its 

corollary pressure drop). Liquid submergence effectively changes the liquid-to-gas ratio of a scrubber. 

The lack of correlation between HCl emissions and liquid submergence suggests that there is also no 

correlation between HCl emissions and liquid flow rate.

Response to Comments 44 - 52: The comments are moot, as the rule no longer includes specific 

requirements for parametric monitoring or operational limits for acid gas control devices.

7. Operating limits for low-emitting EGUs (LEEs).

Comment 53: Commenter 17402 states that operating limits are particularly inappropriate for low 

emitting units because the commenter believes the operating limit procedures in the proposed rule are 

repetitive, are counter to the purpose of the rule, and can result in facilities being deemed non-compliant 

when controls are operating properly. The commenter states that these concerns are even more 

applicable to LEEs, as the emissions associated with LEEs are dramatically lower than those of the rest 

of the fleet. The commenter is concerned that slight variations in operating limits that deviate from the 

operating conditions of the most recent performance test (that indicated the unit operates normally at a 

fraction of the standard) may be deemed non-compliant and cause the unit to lose LEE status when in 

reality the emissions never approached the MACT emissions limit. According to the commenter, this 

result is not consistent with the impact of minor variations in operating limits, and the EPA should 
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remove all operating limits from the rule, and in particular from application to LEEs, where such 

standards are especially inappropriate.

Comment 54: Commenter 18426 states that the proposed rule includes a LEE definition for compliance 

monitoring purposes. According to the commenter, for Hg, emissions less than 10 percent of the Hg 

emissions limitation or less than 22.0 pounds per year on an existing unit may qualify for LEE status for 

Hg. The commenter notes that for Michigan’s Hg rules, a cut-off of 9 pounds per year, per unit was 

developed as protective through the rulemaking process. According to the commenter, this could be a 

smaller utility unit (25 MW to 100 MW) or a larger unit with low utilization where installing a Hg 

CEMS is not feasible due to low emissions or economical due the unit utilization.

Comment 55: Commenter 17752 requests clarification on the criteria for qualifying for LEE with regard 

to references to operating parameter limits in proposed section 63.10005(k)(3) and section 63.10006(c). 

The commenter requests that the EPA clarify whether the use of ACI is permissible to qualify for LEE 

and how operating limits would apply in that circumstance. The commenter also requests clarification 

on fuel sampling as an operating limit and as a demonstration of compliance; it is not clear to the 

commenter if the proposed rule intends for LEEs to comply with maximum fuel input levels under 

section 63.10011(b) and the compliance provisions in section 63.10011(c).

Comment 56: Commenters 17775 and 17868 support the LEE option but find that the proposed LEE 

requirements for “operating parameter limits” are not clear. Commenter 17775 finds the following 

inconsistencies with respect to Hg testing periods that need to be addressed in the final rule:

1. Commenters 17775 and 17868 state that the EPA should remove or appropriately clarify the 

references to operating limits for LEEs. According to the commenter, proposed section 63.10005(k)(3) 

and section 63.10006(c) refer to establishment and maintenance of “operating limits,” but the provision 

cited in section 63.10005(k)(3) for establishing such limits – section 63.10010(k)(3) - does not exist and 

no other provisions address operating limits for LEEs. According to the commenter, proposed section 

63.10021(a)(17) states that, for LEEs, results of emissions tests and fuel analysis - presumably the 

monthly fuel analysis required under section 63.10006(c) - demonstrate continuous compliance, and the 

provision does not mention operating limits.

2. According to the commenters, the EPA’s descriptions of the requirements for LEEs suggest they are 

not required to establish or comply with operating limits. Specifically, the commenters say that the EPA 

states: For existing units that qualify as low emitting EGUs (LEEs), conduct subsequent performance 

tests for the LEE qualified pollutants every 5 years and perform fuel analysis monthly. Commenter

17775 states that if the EPA intended to require that LEEs perform monthly fuel analysis under section 

63.10006(c), the EPA needs to make clear that compliance with the maximum fuel input levels is not 

required and explain why it chose monthly testing. The commenter believes that analyzing fuel monthly

when the fuel supply or mixture has not changed seems unnecessary.

3. Commenter 17775 states that if the EPA intended to require that LEEs establish and comply with 

maximum fuel input levels as an “operating limit” under section 63.10011(b), rather than perform 

monthly fuel analysis, the EPA needs to explain that the fuel analysis is an operating limit and not a 

demonstration of compliance using fuel analysis under section 63.10011.

4. Commenter 17775 also states that the EPA needs to remove the monthly fuel sampling and analysis 

requirement in section 63.10006(c). According to the commenter, if the EPA intended to require that 
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LEEs establish and comply with operating limits other than maximum fuel input levels, the EPA needs 

to issue a proposal that explains the purpose of those limits and how they apply.

Comment 57: Several commenters (19536, 19537, 19538) states that the EPA should discard its “Low 

Emitting Units” monitoring protocols. According to the commenter, monthly fuel testing does not assure 

continuous compliance, and the EPA’s variability analysis indicates HAP emissions are variable. 

Monthly testing does not reveal any information about emissions between the monthly tests. According 

to the commenters, the LEE monitoring should be expanded to require operational parameter monitoring 

as required for all other compliance testing, and monthly fuel sampling further excludes emissions 

during startup and shutdown. The commenters state that the LEE exemption should be eliminated, or the 

threshold redefined to capture only those plants whose future emissions are assured to remain below the 

prescribed limits. According to the commenters, if the EPA were to provide reduced monitoring for 

certain low-emitting units, it should use a UPL for its thresholds, and if data from a unit indicates that 

the 99% UPL of that unit’s emissions are below 10% of the MACT limit, the EPA can be reasonably

assured that unit’s future emissions will be below that threshold.

Response to Comments 53 - 57: The comments are inapplicable because the rule no longer requires 

operating limits for LEEs.

8. Oil-fired operating parameter comments.

Comment 58: Commenter 18025 states that for oil-fired EGUs the commenter recommends an 

alternative approach that will better ensure proper operation of pollution control systems. Rather than 

establishing fixed operating limits, the commenter recommends that the EPA require proper operation of 

the plant’s pollution control equipment and appropriate parametric monitoring without establishing 

numeric operating limits.

Comment 59: Commenter 18428 states that it is not clear whether operating parameters and fuel input 

limits in proposed section 63.10011(b) to apply to oil-fired units. According to the commenter, the 

preamble statement suggests that operating parameters do not apply (“Except for liquid oil-fired 

units,...we are proposing that you monitor during initial performance testing specified operating 

parameters”). The commenter states that similar to LEEs, however, the EPA also suggests that liquid oilfired units must meet maximum fuel input limits as an operating limit. The commenter recommends that 

the EPA should make clear in section 63.10011(b) what operating limits apply as well as explain why. 

Response to Comments 58 - 59: The final rule clarifies that operating limits do not apply to these units, 

with the exception of where: (1) a source elects to use a PM CPMS and an associated operating limit as 

a means to ensure continuous compliance with an underlying filterable PM standard or non-Hg HAP 

metals standard (or all HAP metals standard for liquid oil-fired EGUs); or, (2) a liquid oil-fired unit uses 

quarterly testing to demonstrate compliance with acid gas emission limits (in which case the source must 

develop a site-specific monitoring plan). See the final preamble for further discussion. Note that liquid 

oil-fired sources may also use fuel moisture content analysis or supplier certification to show 

compliance with the acid gas standards.

9. Minimum sorbent injection rates.

Comment 60: Commenter 17821 states that there are multiple problems with the sorbent injection rate 

requirements. DSI and ACI feed rates are normally correlated with other plant conditions, such as unit 

load or flue gas flow, making a single fixed feed rate inappropriate. As an example, sorbent rates are 
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normally set as a mass flow per volume of flue gas, such as a pound of sorbent per hundred thousand 

cubic feet of flue gas. As a result, half the amount of sorbent would be injected when the flue gas flow is 

reduced to half the flow rate. Interestingly enough, the same mass feed rate of sorbent may actually be 

more effective at low flue gas flow rates, because it has more time to react due to the lower velocity. 

However it will also increase the amount of byproduct material generated. Commenter states that the 

problem of using one minimum flow rate for all conditions is the measurement of a sorbent has 

problems. The material handling equipment for a dry solid such as Trona, ACI or other materials 

whether milled or not, is not capable of precise weight measurements. Load cells are typically used to 

gather injection rates, but because the material can clump or surge, short term measurements such as a 

15-minute interval are too small to absorb all these fluctuations. Finally, DSI is also closely linked with 

ESP performance. Injecting a “minimum” amount of sorbent over the entire operating range of a unit 

could change the ash resistivity and thus impact precipitator performance, potentially making it 

impossible to be in compliance with the operating limits for both sorbent injection rate and ESP total 

secondary electric power. The commenter recommends that the EPA should allow sources to develop 

site-specific correlations between sorbent injection rates and an appropriate to source parameter such a 

flue gas flow or unit load. These rates would then be monitored over a longer time average such as 6-12 

hours. In cases where CEMS are used to demonstrate compliance with HCl or Hg standards, limits on 

sorbent inject rates should not be required since the CEMS would be used to demonstrate compliance.

Comment 61: Several commenters (17622, 18037 and 18023) refer to the proposed compliance 

approach for DSI systems (i.e., setting operational limits of reagent injection rate based on performance 

testing at 76 FR 25031 and 25129). Commenter 17622 states that if operational limits consisting of 

injection rates for DSI technology are going to be utilized to demonstrate compliance for a given level of 

HCl control, the reagent reactivity must also be considered an operational limitation. The commenters

advises that for Ca(OH)2, this could be accomplished by including reagent physical parameters such as 

porosity and surface area in the operational limitation. Commenter 17622 also advises that for sodium 

reagents, the physical properties of either Trona or sodium bicarbonate can impact the effectiveness of a 

specific reagent for an acid gas control application; as an example, the particle size to which Trona is 

milled prior to use is an important consideration. Commenters 18023 and 18037 state that the minimum 

sorbent injection rate may be an appropriate operating limit for DSI and/or carbon injection; however, 

the operating limit should be established in a way that accommodates operating over a wide load range 

because it would not be prudent (i.e., it would pass unnecessary costs on to electricity customers) to 

operate a sorbent injection system at the maximum injection rate when running at reduced load. 

Commenter 18023 concludes that the operating limit should allow normalizing for gas flow such as 

lb/MMacf or a calculated ratio. The commenter also states that dry scrubbers should have the option to 

maintain the SO2 removal rate at or above the lowest 1-hour average rate during the most recent 

performance test because this is more consistent with how dry scrubbers are operated in the industry. 

Commenter 18023 concludes that any minimum sorbent injection requirement for DSI, carbon injection 

and dry scrubbers should be set in a manner that allows for efficient use of sorbents across all operating 

load ranges because minimizing sorbent injection is an important consideration both environmentally

and economically and injecting sorbent in excess of what is necessary (simply to meet an arbitrary limit 

set by an emission test at one point in time) creates an additional potential waste stream that must be 

managed. Commenter 18037 states that setting a minimum injection rate will potentially hurt units as 

they attempt to balance their PM limit with the minimum injection of sorbent necessary to control Hg or 

HCI. According to the commenter, sources should be able to maintain the flexibility necessary to meet 

all of their emissions obligations.

Comment 62: Commenters 17775 and 17800 state that the EPA should consider and review data to 

evaluate use of a load factor adjustment for those operating parameters that are load dependent. The 
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commenters state that the EPA finalized a load factor adjustment in the Industrial Boiler MACT for 

sorbent and carbon injection; specifically, the EPA revised the definitions of “Minimum sorbent

injection rate” and “Minimum activated carbon injection rate” to take load into account by multiplying 

the “lowest hourly average” by a new term called the “load fraction” (see section 63.7575).

Comment 63: Several commenters (17627, 17715, 18539, 19114) take exception to the use of the 

minimum sorbent injection rate parameter for dry scrubbers or DSI in Table 4 because they assert that 

such a restriction removes all of the flexibility that a unit has to meet all of its obligations, and sorbent

quality may vary between suppliers requiring different injection rates per product. Additionally, they

assert, sorbent may be injected for reasons other than for HAP control; for example, during the periodic 

MACT performance test an injection rate may be set based on temporary atmospheric conditions 

requiring more injection for SO3 control; however proposed Table 4 would require the injection rate 

based on SO3 conditions must be utilized until the next performance test for HAP compliance, despite 

the fact that the injection rate was not related to HAP control.

Comment 64: Commenter 17805 states that according to the proposed rule requirements, ACI amounts, 

or other control media, would be set at the highest operating load and a unit would not be able to reduce 

the amount of product injected when running at lower loads and corresponding lower flue gas flows. 

According to the commenter, this does not make economic sense and is wasteful to add more material 

than necessary to control emissions.

Comment 65: Commenter 17881 states that Table 4 – Operating Limits for EGUs, the DSI sorbents are 

likely targeting HCl/HF, not just Hg as suggested in this requirement. According to the commenter, this 

paragraph should recognize that there may be multiple pollutant specific sorbents. 

Response to Comments 60 - 65: These comments are inapplicable because the rule no longer requires 

operating limits for sorbent injection.

10. PM CEMS operating limits (section 63.10011(d) and table 4, parameter 8).

Comment 66: Several commenters (17705, 17754, 17775) request that the EPA clarify how the PM 

operating limits must be established because the provisions of proposed section 63.10011(d) are 

inconsistent with the provisions for PM CEMS in proposed Table 4. Commenter 17775 adds that the 

EPA has provided no data or discussion to explain how the average of three Method 5 runs would be 

sufficient to capture variability under a various normal operating conditions. Commenter 17775 takes 

exception to the use of the term “highest hour” in proposed Table 4 item 8 because it is not clear to the 

commenter whether this term applies to Method 5 data or CEMS data. The commenter believes that item 

8 makes no sense relative to Method 5 data, since runs are not measured in hours but in sample volume 

(and runs will be more than one hour). The commenter also believes that item 8 makes no sense relative 

to hourly PM CEMS data because at the time the operating limit is established because the values would 

simply be output from the uncorrelated CEMS.

Response to Comment 66: In consideration of the PM emissions limit and the potential burdens 

associated with certifying a PM CEMS via PS 11, the agency decided to focus on the use of a PM 

instrument not as a CEMS but as a CPMS. The PM operating limit for use in conjunction with a PM 

CPMS functions in the same manner as parameter monitoring from other rules. The highest hourly 

average of the PM CPMS signal produced over three test runs is used as the operating limit, and that 

value becomes averaged over a rolling 30 boiler operating day average. The “highest hour” in Table 4 is 

correct and refers to the Method 5 run data. Section 63.10011(d) is revised to be consistent with this 
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approach. The final rule does provide for the use of a PM CEMS to determine compliance with the 

filterable PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

11. CPMS averaging times.

Comment 67: Commenter 17775 states that the EPA should clarify the averaging time of the required 

parametric monitoring. According to the commenter, although the EPA proposes to define the minimum 

operating parameters in section 63.10042 in terms of “90 percent” of the “test average” during the most 

recent performance test, and to require compliance on a 12-hour average basis under Table 8, other 

provisions and statements contradict that definition. For example, states the commenter, proposed Table 

4 instructs sources to maintain parameters “at or above the lowest 1-hour average” during the most 

recent performance test; proposed section 63.10021(c) requires determination of a “3-hour rolling 

average of the CPMS data collected”; proposed section 63.10022(a) requires units using emissions 

averaging to maintain the “3- hour average parameter values” for various control devices at or below the 

operating limits established during the most recent performance test; and in the preamble, the EPA 

describes operating limits as “[t]he average of the three minimum (or maximum) values from the three 

runs for each applicable parameter . . . .” 75 FR 25,029/3. The commenter assumes that the proposed 

definitions and the 12-hour average in Table 8 reflect the EPA’s intent. The commenter asserts that the 

EPA also must provide data to support achievability and enforceability of operating parameters under its 

proposed definitions. The commenter states that although the EPA does not explain the “90 percent”

criterion in this rule, when the EPA previously promulgated a similar definition in the 2004 IB MACT, 

the EPA explained that 90 percent value was intended to provide a range around the test average to 

account for normal variations in the operation of the source and the control device (EPA Response to 

Public Comments on Proposed Industrial, Commercial, and Institutional Boilers and Process Heaters 

NESHAP (Feb. 25, 2004), EPA-HQ-OAR-2002-0058-0611 at 54). According to the commenter, the 

EPA must provide data to confirm that the 10 percent allowed variance is sufficient. The commenter

states that before finalizing a rule that imposes parameters as enforceable limits, the EPA must analyze 

data to determine what definition provides adequate flexibility. 

Response to Comment 67: The rule retains two operating limits in the final rule: for a PM CPMS and 

for site-specific parameters from liquid-oil fired EGUs that choose to comply with quarterly emissions 

testing for acid gases. See the final preamble for further discussion. The rule plainly states the PM 

CPMS operating limit averaging period as each rolling 30-day operating period. The limit is set based 

on the highest 1-hour average monitor output signal during a successful performance test. That average 

serves as a measure of ongoing control of the unit in accordance with the operations that exist during the 

performance test, and is similar to how the Agency has established operating limits under a number of 

NESHAP standards. The appropriate parameter, monitoring approach, and data reduction requirements 

(including averaging periods as appropriate) for the liquid oil-fired units will be set forth in the source’s 

monitoring plan. See the final preamble for further discussion.

12. Optional moisture measurement technique.

Comment 68: Commenter 17715 proposes an additional option be available for measuring moisture: if 

the stack is saturated, a source should be able to use temperature, absolute pressure, and a psychrometric

chart to determine moisture; temperature and pressure transmitters can be calibrated with NIST traceable 

equipment; during periods when the stack is not saturated, default factors listed in the rule could be 

used.
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Response to Comment 68: While the rule does not contain the additional options mentioned by the 

commenter, the commenter remains able to request use of such instrumentation via the general 

provisions at section 63.8(f) of subpart A of part 63.

13. Frequency of QA/QC requirements for parametric monitoring devices.

Comment 69: Several commenters (17716, 17725, 18014, 18498) state that sources that are required to 

conduct control device parameter monitoring must follow prescriptive QA/QC requirements and 

performance evaluation schedules as outlined in section 63.1 0010. According to the commenters, some 

of these requirements are unnecessarily frequent, such as the need to check pressure taps at least once 

each boiler operating day, and the requirement to conduct annual evaluations of ESP power monitoring 

systems is excessive particularly for large ESPs with numerous electrical bus sections. The commenters

suggest that the EPA specify all operating parameter QA/QC activities and performance evaluations in 

accordance with manufacturer’s recommended procedures.

Response to Comment 69: In the final rule, the source owner or operator must prepare a site-specific 

monitoring plan for its PM CPMS, and, for those liquid oil-fired sources that choose to conduct 

quarterly acid gas emissions testing, for appropriate parameters to demonstrate that operations at the unit 

remain consistent with operations during the performance test. See the final preamble for further 

discussion. This plan identifies the QA/QC procedures the source will follow and calls generally for a 

daily performance evaluation of some form for most monitoring devices as a basic QC check. No 

specific QC checks have been prescribed in the rule; rather, the source owner or operator is able to 

choose the specific method that will be used to fulfill this QC check in conjunction with developing the 

site’s monitoring plan.

14. Consistency of rule with data gathered during the 2010 ICR.

Comment 70: Commenter 17775 believes that the EPA cannot require stack testing under conditions it 

did not consider in the standard setting process. Neither does commenter 17775 believe that the EPA can 

require EGUs to operate at a fixed load for 30 operating days. According to the commenter, the EPA 

proposes to require that all “performance testing” be conducted at “maximum normal operating load 

while burning the type of fuel or mixture of fuels that has the highest content of chlorine, fluorine, nonHg HAP metals, and Hg” (Proposed section 63.10007. The commenter states that the EPA also proposes 

that it be able to request that performance tests be conducted under other representative conditions, and 

that EGUs be required to provide records to determine those conditions upon request (proposed section 

63.10007(f)). The commenter states that for EGUs using CEMS, the “performance test” runs for 30 

operating days (proposed section 63.10005(a)). The commenter states that for these EGUs, the EPA 

must recognize that it may not be possible to maintain “maximum” normal operating load for a full 30 

operating days. According to the commenter, instead, the EPA should simply require representative 

operation. The commenter states that because such sources are monitoring compliance continuously 

after that point, there is no reason to require worst case testing conditions.

Response to Comment 70: The agency maintains that it has adequately incorporated variability into the 

final standards in response to other comments on this issue.

15. Frequency of stack tests.

Comment 71: Commenter 17736 states that bi-monthly stack testing imposes an unnecessary drain of 

resources and will, inevitably, force units into non-compliance. The commenter states that an EGU
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electing to comply with the total or individual non-mercury HAP metal emissions limit (without CEMS) 

is required to demonstrate continuing compliance by stack testing every two months and that stack 

testing at such a high frequency is an unnecessary drain of resources. According to the commenter, 

conducting six stack tests in one year is a grossly expensive, time consuming, and disruptive 

requirement. The commenter maintains that the proscribed parameter limits should be eliminated and 

replaced with provisions allowing facilities to work with states to develop site-specific compliance 

plans, if deemed necessary, bi-monthly stack testing is especially excessive if/when the unit is subject to 

any additional monitoring requirements.

Comment 72: Commenter 17775 states that proposed fuel input limits and frequent periodic stack 

testing requirements are duplicative because under the proposed rule, the maximum time between stack 

testing for non-Hg metals and HCl (for units using stack testing to demonstrate compliance) is 

approximately 60 days (i.e., every other month for EGUs with PM controls). The commenter states that 

if an EGU plans to combust a new fuel type or mixture and that fuel exceeds the maximum metals input 

level during the prior performance test, a new performance test is required within 60 days of combusting 

that fuel (proposed section 63.10021(a)(4), (6), and (8)). According to the commenter, because testing 

already is required every 60 days, the requirement to test following a revised maximum fuel input limit 

is duplicative. However, the commenter states, given the notice and planning requirements for stack 

tests, it also is not reasonable to require stack testing sooner. According to the commenter, current 

operating parameters provide a reasonable assurance of compliance prior to the any new performance 

test and requiring testing of new fuels, and stack testing in response to changes in maximum fuel input, 

are more than sufficient to addresses any concern that a change in fuel warrants reexamination of those 

operating parameters. The commenter contends that the EPA has not provided adequate justification for 

such frequent stack testing, and therefore the final rule should require stack testing no more frequently 

than annually unless such a test is triggered by a change in the maximum fuel input as a result of a 

change in fuel type.

Comment 73: Commenter 17798 recommends, for PM, stack testing every 2 years or at a maximum on 

an annual basis in conjunction with monitoring operating parameters. According to the commenter, for 

units without pollution control equipment the source should perform continuous monitoring or stack 

testing every 6 months. The commenter further recommends that the stack testing regime address 

determining minimum and maximum operating parameters of control equipment under different 

conditions to address variability. According to the commenter, for pollutants with emission limitations 

(acid gases and Hg) the EPA should apply the same structure for CEMS and stack testing as discussed 

here for PM requirements. The commenter states that also for these pollutants, testing and setting of 

pollution control operating parameters should be applied only in conjunction with the stack test 

compliance demonstration option. According to the commenter, these changes will streamline the 

process, reduce cost, and achieve the same environmental result.

Comment 74: Commenter 17902 states that testing should be allowed on a less frequent 3-year or 5-

year basis when HAP emissions are significantly below the MACT emissions limits (as the EPA has 

proposed in section 63.1 0006). The commenter states that additionally, EGUs that participate in an 

emissions averaging plan should not be restricted from reduced performance testing if the relevant HAP

emissions from the units in combination are in fact below the percent thresholds of the relevant MACT

limits.

Comment 75: Commenter 18426 states that emissions testing required monthly or every other month 

depending on the unit and pollutant specified in the proposed rule is excessive and inconsistent. 

According to the commenter, if an acceptable parametric monitoring system is developed, emissions 
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testing once a year or every other year should be sufficient, and even if no emission control system is in 

place, unless a significant change in the fuel characteristics occurs, emissions testing once a year or 

every other year should also be sufficient. The commenter recommends that at a minimum, the EPA 

should make the testing and monitoring requirements consistent for the units and pollutants.

Response to Comments 71 - 75: The agency agrees that fuel input and frequent periodic stack testing 

requirements could be duplicative; therefore, the rule no longer requires fuel analysis for pollutants. The 

rule requires quarterly emissions testing for units that choose to use emissions testing. In addition, 

sources remain subject to underlying parameter monitoring that applies to many of these units, through 

Compliance Assurance Monitoring (40 CFR Part 64) or other existing regulatory programs. For liquid 

oil-fired units that choose to use emissions testing, there is an additional requirement for continuous 

parameter monitoring of the method of control for acid gases. See the final preamble for further 

discussion. The quarterly stack testing period, coupled with underlying monitoring of control devices or 

the additional monitoring for liquid oil-fired units, is expected to be frequent enough to ensure that a 

unit’s emissions control devices and processes continue to operate in the same manner as during the 

previous stack test. If there are significant changes to the operation of the unit or the fuel, then a retest is 

required to reconfirm that the source remains in compliance under the new operating circumstances.

16. Operating parameters during SSM.

Comment 76: Commenter 17886 states that during startup, shutdowns, and malfunction periods use of 

established parameters set during performance tests would not be proper. The commenter notes that the 

EPA has not addressed this concern in the proposal but should consider some best management practice 

option during those periods.

Comment 77: Several commenters (17775, 18428, 17800) state that they are very concerned about the 

potential for enforcement of operating parameter and opacity limits during periods of startup, shutdown, 

and in the event of equipment malfunction. According to the commenters, the current proposal would 

allow enforcement of deviations from operating parameter limits during periods of startup and 

shutdown, when controls would not be expected to be operating at the same levels as during 

performance tests. The commenters note that the EPA did assert in the preamble that SSM conditions 

were taken into account by proposing use of 30 boiler operating day rolling averages and by the fact that 

EGUs often use cleaner fuel during startup. According to the commenters, these assertions regarding 

startup and shutdown are inapplicable to control device operating parameter limits, which are based on 

12-hour averages established during performance testing. In short, assert the commenters, the EPA has 

made no allowance in its operating limits for periods of startup and shutdown but to the contrary, the 

EPA has proposed to require sources to establish control device operating parameter levels that are 

dependent upon load during periods of “maximum normal operating load,” or other frequently used 

loads, and then maintain those levels during other periods, including startup and shutdown. The 

commenters urge the EPA to address these periods in another manner, for example by establishing 

simple work practice standards in lieu of operating parameters. 

Response to Comments 76 - 77: Because work practice standards apply during periods of startup and 

shutdown, EPA has clarified in the final rule that the PM CPMS operating limit does not apply during 

such periods. Instead, for coal and other solid fuels, the work practice standards for such periods will 

apply, together with the monitoring and recordkeeping required to document compliance with those 

work practices.

17. Operating limits based on total PM.
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Comment 78: Commenter 17402 states that they support operating limits based on total PM and not 

filterable PM. The commenter believes total PM is a more complete, more flexible, and better protective 

standard. The commenter asserts that that there is too much variability with PM CEMS technology for 

the operating limit to be set, given the high level of uncertainty involved in the test. Recognizing that 

continuous condensable PM monitoring technology does not exist, the commenter’s preference is to 

preserve the flexibility allowed in choosing to reduce condensable PM or filterable PM by setting the 

operational filterable PM limit based on the difference of the total PM limit and condensable PM

measured from stack testing (i.e., filterable PM (operational) = total PM limit (0.03) – condensable PM

(performance test)). The commenter believes this approach will provide flexibility and would address 

both variability concerns with testing, fuel supply and operations. 

Response to Comment 78: Given our decision to use a filterable PM standard as the PM emission limit 

under this rule, this suggested approach would not be appropriate. Moreover, the operating limit 

established for the PM CPMS is just that – an operating limit, and not a PM limit (filterable or total), and 

does not require the source to present the monitor output in terms of PM.

18. Request for clarification on multiple load testing (section 63.10007).

Comment 79: Commenter 17316 requests clarification on proposed provisions for multiple load 

performance tests at section 63.10007 to establish load-specific operating limits. The commenter states 

that it is not clear which operating limits are re-set following a performance test or whether a new 

performance test program erases all previous operating limits, or only those operating limits for loads at 

which testing was repeated. For example, the commenter asks if a unit initially conducted performance 

testing at 3 loads: 100 percent, 75 percent and 50 percent, but for the next annual test cycle, only 

conducted testing at 100 percent load to demonstrate compliance, whether the source could continue to 

use operating limits established in the initial test program for the 75 percent and 50 percent load 

levels. The commenter believes that it seems appropriate to allow continued use of operating limits for 

load levels at which testing is not repeated, so long as test results at the maximum load level 

demonstrate compliance.

Comment 80: Commenter 17767 states that control device operating parameters will vary according to 

unit output and those parameter levels equating to compliance at high loads might be unacceptable or 

unnecessary at lower loads. According to the commenter, absent a means to account for an acceptable 

tolerance in these parameters, the rule allows for multi-load testing but fails to outline what load ranges 

would be required, how to address operation between those loads and the costs of the testing regiment, 

which would be high. The commenter recommends adding operating range tolerances as an appropriate 

solution.

Comment 81: Commenter 17805 states that the section 63.10007 (Tables 5 and 7) contains compliance 

demonstration requirements, and specifically, demonstration “through performance testing”. According 

to the commenter, these provisions essentially require utility units to develop parametric limits at 

different operating levels and coal qualities. The commenter asserts that according to this section, stack 

testing is to be performed while units burn coal with the maximum concentration of HAP constituents, 

but units would still have to run at normal operating load. The commenter does not believe this would be 

possible since the commenter has observed that coal with the maximum HAP concentration

characteristics generally contains lower heat content. Therefore, the commenter asserts, running a 

performance test solely with coal having the higher HAP concentrations, and lower heat content, would 

not allow a unit to attain normal operating loads; numerous stack tests would be required during a single 

compliance period to determine parametric limits for each seam/quality or type of coal as proposed in 
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the rule and there could be multiple compliance periods in a year depending on a utility’s chosen 

compliance method. According to the commenter, this is burdensome. The commenter states that it 

would be helpful for the EPA to review data showing HAP concentration variability by coal-type and 

within coal-type before finalizing these monitoring requirements.

Comment 82: Commenter 17800 states that many units in the U.S. utility system are load following or 

cycling units that change load on a daily basis and that many of the control device operating parameters 

the EPA is requiring to be maintained will vary with load. The commenter states that to account for this, 

the EPA suggests that EGUs obtain differing operating limits at loads other than the “maximum normal 

load” required for stack testing by testing at those other lower loads (section 63.10007(c)). According to 

the commenter, requiring EGUs to conduct performance tests at multiple loads is not practical or 

reasonable, and the EPA has not considered the time or cost of that kind of extensive testing.

Response to Comments 79 - 82: The EPA finds these comments moot, for the rule no longer requires 

operational limits except for those EGU owners or operators who choose to rely on PM CPMS to 

demonstrate compliance. To the extent that those owners or operators choose to operate their units at 

load levels other than normal operating conditions, those owners or operators will need to ensure that 

their units remain in compliance with the emissions limits, which, as explained in the rule, may mean 

that additional emissions testing and correlation will need to occur. With respect to the commenter’s 

example, if emissions producing characteristics had not changed since the original correlation testing 

occurred, the commenter would be able to use the previous correlations for its operating parameters 

when the unit’s load changed. 

19. Miscellaneous.

Comment 83: Several commenters (19536, 19537, 19538) states that the monitoring of operational 

parameters as proposed under some scenarios does not assure continuous compliance with emissions 

limits that are only measured annually or every 5 years. According to the commenter, the amount of 

each HAP that is emitted ultimately depends on the amount in the coal, which is not tested more 

frequently than monthly (or upon a change of fuel type) under any of the compliance scenarios. 

Moreover, the commenter notes that the HAP content of fuel is highly variable even within fuel types.

Response to Comment 83: The final rule provides for two basic approaches to ensure continuous 

compliance: use of CEMS or emissions testing quarterly. One exception is for LEE units because the 

risk of non-compliance from such units is low based on their emissions. Another exception is for a PM 

CPMS. For this operating parameter, the EPA believes that the monitoring can provide documented 

results that control operations remain consistent with the degree of control established during the 

performance test. At this time, direct continuous measurement of compliance with the PM emission 

limits is not required. However, if a source desires to use a PM CEMS for direct compliance with the 

filterable PM standard, the final rule provides for that option. See further discussion in the final 

preamble. Direct measurement of compliance with HAP metals standards is not warranted at this time 

given the lack of performance specifications for multi-metal CEMS. The EPA believes the compliance 

assurance provisions in the final rule are a balanced approach that will enable effective compliance 

oversight for this rule while providing quality data in a cost-effective manner for the affected sources.

Comment 84: Commenter 17795 states that the EPA did not provide an explanation for selection of a 

12-hour block average for operational monitoring. According to the commenter, the EPA should 

maintain consistency among averaging periods for demonstrating compliance with emission standards or 

operating limits; averaging operating parameter data over the same time period when employing direct 
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or surrogate continuous monitoring provides adequate assurance that equipment is operated and 

maintained in compliance with standards or limits. According to the commenter, this also reduces the 

data management and the quality assurance burden currently proposed with 12-hour block averaging 

periods. 

Response to Comment 84: This comment is moot given the changes in the final rule. The PM CPMS 

will use a rolling 30-day average. Site-specific monitoring for liquid oil-fired units, if required, will 

establish the appropriate averaging period based on the parameters being monitored.

Comment 85: Commenter 17740 states that it has significant concerns with the EPA’s proposed testing 

requirements for solid oil-derived fuel and coal-fired EGUs using total PM emissions as a surrogate for 

non-Hg metals (see 40 CFR section 63.10006). The commenter understands that the purpose of this 

testing is to ensure that the surrogate (i.e., PM) emission limit meets the direct HAP emission limits and 

that the EPA reserves the right to adjust the surrogate limit. The commenter asserts that the EPA does 

not have the authority to “adjust” surrogate emissions standards for individual units based on 

performance testing. According to the commenter, if the EPA allows sources to comply with emissions 

standards through surrogates, the surrogate emission standards also are subject to the requirements of the 

CAA and cites National Lime II, 233 F.3d at 639 (holding that the EPA may use PM as a surrogate for 

HAP if the “PM emission standards reflect what the best sources achieve -- complying with CAA

section 7412(d)(3)”). The commenter stats that according to the MACT Floor Memo, the agency set the 

PM MACT floor for existing units consistent with the requirements of the CAA. MACT Floor Memo, at 

3 (“The existing-source MACT floors for PM, HCl, SO2, total non-Hg HAP metals, and individual nonHg HAP metals emissions were based on the top 12 percent of the total number of EGUs...”). 

According to the commenter, nothing in the CAA authorizes the EPA to subsequently review and revise 

these standards on a unit-by-unit basis. 

Comment 86: Commenter 17740 states that Congress specifically limited the EPA’s authority to review 

and revise emissions standards promulgated under section 112. Section 112(d)(6) instructs the 

Administrator to “review, and revise as necessary (taking into account developments in practices, 

processes, and control technologies), emission standards promulgated under this section...” According 

to the commenter, the CAA manifestly does not permit the agency to circumvent the requirements of 

Section 112(d)(3) and set standards for specific units (citing e.g, Chevron U.S.A., Inc. v. Nat. Res. Def. 

Council, 467 U.S. 837, 842-43 (1984) (holding that if Congress has spoken directly to the disputed issue 

of statutory construction, “that is the end of the matter; for the court, as well as the agency, must give 

effect to the unambiguously expressed intent of Congress”). According to the commenter, if, after 

issuing a final rule, the EPA determines that a surrogate emission standard is no longer appropriate, the 

agency must review and revise the standard in accordance with the express requirements of the 

CAA. The commenter notes that the EPA’s position deprives sources of much needed time to plan for 

capital investments in control technology. The commenter states that a source has no way of knowing 

whether its emission control measures are sufficient to comply with the EGU MACT if the EPA can 

review and revise a MACT standard based on performance test results. According to the commenter, 

even if a source makes substantial capital investments and achieves a proposed surrogate emission limit, 

it may be forced to make additional investments in a short timeframe to achieve a new, individual limit 

based on its performance test results. The commenter asserts that this circumstance creates substantial 

regulatory uncertainty for affected sources. 

Response to Comments 85 - 86: The rule does not provide for adjusting the PM emission limit (based 

on filterable PM under the final rule). The PM CPMS and associated operating limit do not require 

reporting in terms of the emission limit but reflect an operating limit based on the raw output of the PM 
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CPMS. This does not adjust the filterable PM emission limit. The unit-specific operating limit proposed 

has been removed from the final rule.

Comment 87: Commenters 17718 and 17881 note that section 63.10005(d)(7) states that initial 

compliance through the use of CPMS can be determined using the average hourly PM, non-Hg HAP

metals, HCl, HF, or Hg concentrations obtained during the first 30-day operating period. In turn, 

commenters note that continuous parameter monitoring systems, or CPMS, are defined at section 63.2 as 

“Continuous parameter monitoring system means the total equipment that may be required to meet the 

data acquisition and availability requirements of this part, used to sample, condition (if applicable), 

analyze, and provide a record of process or control system parameters.” According to the commenters,

they have been unable to identify any other place in the proposed rule where it is stated that CPMS can 

be used for initial compliance, nor does the commenter understand how such monitoring systems could 

be used for purposes of a direct compliance assessment with the emission limits in Tables 1 and 2 of the 

proposed rule. 

Response to Comment 87: The final rule in this section refers to “CMS”, and is referring to continuous 

emission monitoring systems that are used for direct compliance. Section 63.10005(c) discusses that you 

may be required to establish an operating limit using a PM CPMS during an initial compliance 

performance test period.

Comment 88: Commenter 17881 states that under section 63.10011 the concept of selecting the highest 

minimum/maximum values across a series of performance tests is not congruent with multiple operating 

limits for different scenarios. 

Response to Comment 88: Given the simplification of the operating limit and parameter monitoring 

provisions in the final rule, the EPA does not believe this comment remains applicable.

Comment 89: Commenter 17881 states that in section 63.10021(a)(1), there needs to be an allowance 

for operation outside the initial operating limits during subsequent compliance tests for purposes of 

widening the allowed operating limits without having to report a deviation (as long as the compliance 

test results show compliance with the emission limit). 

Response to Comment 89: The EPA disagrees. Given the 30-day averaging period, there is adequate 

flexibility for a short term increase in PM CPMS output during a short term test without this type of 

special allowance.

Comment 90: Commenter 17881 states under Table 4 – Operating Limits for EGUs, for IGCCs the 

combustor temperature would likely be a better measure, as compared to electrical load (as a percent of 

maximum output) which will float with ambient conditions. 

Response to Comment 90: This comment is moot given the changes to the operating limits required 

under the final rule.

Comment 91: Commenter 17881 states under Table 4 – Operating Limits for EGUs, with respect to PM 

CEMS, that for concentration based emission or operating limits, it is normally appropriate to correct the 

concentration back to a reference O2/CO2 level for purposes of consistency (i.e., the diluent gas levels 

will affect the concentration).
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Response to Comment 91: There is no need to report the data from a PM CPMS in PM concentration 

values.

Comment 92: Commenters 18014 and 17716 state that in Table 8, CPMS data is required to be reduced 

to 12-hour block averages. However, the commenters assert that this requirement is not specified in 

section 63.10010(h). 

Response to Comment 92: The final rule has eliminated the parameters measured on a 12-hour block 

average, and now requires only a 30-day rolling average for an operating parameter.

Comment 93: Commenters 18014 and 17716 state the limits for some operating parameters are also 

internally inconsistent. The commenters provide an example that section 63.10042 defines the minimum 

operating parameters limits (minimum scrubber effluent pH, minimum pressure drop, minimum 

scrubber flow rate, minimum sorbent injection rate and minimum voltage or amperage) as 90% of 

average value measured during the most recent performance test, but Table 4 states that the parameters 

must be maintained “at or above the lowest 1-hour average” from the performance test. The commenters

recommend allowing sources greater flexibility in defining representative operating parameters. 

Response to Comment 93: These comments are moot given the changes in the final rule, as discussed 

above.

Comment 94: Commenter 18015 states that facilities should have the flexibility to use other parameters 

than the ones identified in the rule. According to the commenter, for example, some units equipped with 

wet FGD scrubbers have, as the primary parameter for control, density, not pH. The commenter notes 

that the relative importance of various operating parameters can change depending on conditions and 

therefore the rule should be flexible in order to account for other operating parameters and account for 

variability in operating conditions. The commenter recommends that the alternatives should be 

established through submittal of monitoring plans before testing and certifying CEMS. 

Response to Comment 94: These comments are moot given the changes in the final rule, as discussed

above. The one circumstance in which the rule relies on flexible parameter selection is for liquid oilfired units that demonstrate compliance with emission limits for acid gases by conducting quarterly 

performance tests. In that situation, the source must also develop a site-specific monitoring plan to 

ensure that operating conditions remain consistent with conditions during the performance test. See the 

final preamble for further discussion.

Comment 95: Commenter 17925 states that parametric monitoring should be applied as an action 

indicator and not applied as a compliance monitor because they do not give a true indication of 

compliance especially for multi-pollutant control configurations. According to the commenter, for 

example, for PM emissions, the EPA has determined that ESP secondary current and baghouse leak 

detection will be indicative parametrically of PM filterable emissions. However, the commenter states, 

other equipment on units such as FGD systems (wet scrubbers) or DSI for ESP ash resistivity adjustment 

also can serve to reduce filterable and condensable PM emissions. According to the commenter, in such 

cases, a wide range of ESP secondary power rates and baghouse leak rates could be experienced while 

PM emission limits are still achieved due to the impact of the other equipment. The commenter does 

note that if parametric monitoring remains a compliance monitoring method, they agree with the 

approach of providing a variable range within the tested results. However, the commenter asserts that 

some additional flexibility beyond a 10% range should be considered. According to the commenter, the 
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EPA does not explain how the 10% number was obtained and how the range would be used for 

compliance.

Response to Comment 95: These comments are moot given the changes in the final rule, as discussed 

above. See also response to Comment 30 in this section.

Comment 96: Commenter 17923 recommends that the operational limitations of the air pollution 

control systems reference the manufacture recommendations. According to the commenter, the 

methodology required by the proposed rule would significantly limit operational flexibility and 

significantly increase the emissions testing required at affected facilities. 

Response to Comment 96: These comments are moot given the changes in the final rule, as discussed 

above.

Comment 97: Commenter 17718 states that the proposed regulatory language in 40 CFR 63.10006 (a), 

(b), (d), (h) and (i), does not allow for process improvements. The commenter asserts that as written, 

subsequent performance tests must be conducted “during the same compliance test period and under the 

same process (e.g., fuel) and control device operating conditions.” According to the commenter, process 

improvements discovered after initial compliance testing could potentially allow for the same or better 

control of emissions yet move the control device operating conditions outside of what was established as 

the “operating limits” established per Table 4 and 7 of the proposed language. The commenter suggests 

that the “same process and control device operating conditions” language be removed from these 

regulatory sections. According to the commenter, this would be similar to language proposed in 40 CFR

63.10006 (e), (f), (g), (j), (k), (l), and (m) where testing under those “same conditions” is not required. 

Response to Comment 97: These comments are moot given the changes in the final rule, as discussed 

above.

Comment 98: Commenter 19033 states that section 63.10010 (h)(2)(i) is overly prescriptive with 

respect to the minimum acceptable criteria for liquid flow monitoring. The commenter asserts that the 

+/- 2 percent accuracy (section 63.10010 (h)(2)(i)(B)), is excessive, given the purpose for which liquid 

flow monitoring is intended (verification that the scrubber is operating in a manner similar to the level at 

which it operated during the performance test). The commenter points out that in its current Title V 

permit the liquid input in based on supplied pump curves, which indicate flow as a function of pump 

motor amperage. The commenter asserts that the proposed regulation also does not take into account that 

there could be issues with spray patterns as nozzles wear over time. According to the commenter, liquid 

flow measurements would not take that effect into account and would thus not be an accurate indicator 

of pollutant removal. The commenter estimates that $250,000 would be needed to add the liquid flow 

measurement and associated data acquisition systems needed to meet section 63.10010 (h)(2)(i)(B) and 

that such an expenditure is not justified. The commenter agrees with the concept outlined in the July 29, 

2011, comments letter provided with respect this proposed regulatory action by Thomas Easterly, 

Commissioner of the Indiana Department of Environmental Management, i.e.

“Indiana asks that States be allowed maximum flexibility to develop alternate compliance 

plans that afford the regulated community opportunity to assure timely compliance, while 

also assuring that consumers are not adversely affected.”

In concert with the sentiment expressed by Commissioner Easterly, the commenter recommends that 

states be provided the flexibility to approve liquid flow monitoring and other portions of the
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required CPMS monitoring plan. To that end, the commenter recommends that section 63.10010 

(h)(2)(i) be amended as follows: (i) If you have an operating limit that requires the use of a flow 

monitoring system, you must develop a flow monitoring plan in consultation with your state 

regulatory agency. The plan must be approved by the agency in advance of the initial compliance 

demonstration requirements in (A) through (D) of this section. 

Response to Comment 98: As discussed elsewhere, the use of operating parameters is no longer 

required in the rule except for those associated with use of PM CPMS or those associated with use of 

liquid oil-fired units whose owners or operators choose acid gas emissions testing and must provide 

continuous parameter monitoring of their flue gas desulfurization systems. Where operating parameters 

are used, the rule does not prescribe minimum quality assurance or control specifications; in concert 

with the commenter’s suggestion, these specifications are left to the EGU owner or operator to choose 

and follow.

Comment 99: Commenter 19033 states that 63.10010 (h)(2)(ii)(D) is overly prescriptive. According to 

the commenter, EGU operators may have experience that pressure drop sensors may provide reliable 

output at a less frequent cleaning frequency than daily and alternatively, systems equipped with an auto 

purge system would not require the daily operator interaction of manually cleaning the sensors. 

According to the commenter, this parameter is another candidate for negotiation between the state 

regulatory agency and EGU owner. The commenter recommends that section 63.10010 (h)(2)(ii) be 

amended as follows:

(ii) If you have an operating limit that requires the use of a pressure monitoring system, you must 

develop a pressure monitoring plan in consultation with your state regulatory agency. The plan must 

be approved by the agency in advance of the initial compliance demonstration requirements in (A) 

through (F) of this section. The plan must include the recommended accuracy, and include a 

recommended maintenance interval for adequate sensor cleaning if an auto purge system has not 

been installed.

Response to Comment 99: These comments are moot given the changes in the final rule, as discussed 

above.

Comment 100: Commenter 17821 disagrees with the EPA’s unwillingness to delegate some key

responsibilities to state and local agencies. The commenter states that in section 63.10041, the EPA 

defines who is responsible for implementation and enforcement of this subpart: “In delegating 

implementation and enforcement authority of this subpart to a state, local, or tribal agency under 40CFR

part 63, subpart E, the authorities listed in paragraphs (b)(1) through (4) of this section are retained by

the EPA Administrator and are not transferred to the state, local, or tribal agency; however, the U.S. 

EPA retains oversight of this subpart and can take enforcement actions, as appropriate.

1. Approval of alternatives to the non-opacity emission limits and work practice standards in 

§63.9991(a) and (b) under § 63.6(g).

2. Approval of major change to monitoring under § 63.8(f) and as defined in § 63.90, and approval 

of alternative operating parameters under §§ 63.9991(a)(2) and 63.10009(g)(2).

The commenter strongly recommends that approval of alternatives to work practice standards and 

alternative operating parameters be delegated to the state or local agencies for multiple reasons. 

According to the commenter, first, the state and local agencies are in a much better position to review 

and access the merit of changes requested by individual operators; while it can articulate direction for 
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how to approve these requests, the EPA does not have the unit specific knowledge to understand and 

evaluate the rationale for the requested changes. Second, the commenter states, the EPA has in this 

proposal, done an inadequate job in developing operating parameter limits for the wide diversity of 

EGUs. According to the commenter, because of the wide variety in EGU construction, control 

equipment, and operation, it is unlikely that the EPA can develop a one-size-fits all approach that will 

properly apply to the entire industry, and as a result, state and local agencies that are more familiar with 

each source should be allowed to make those decisions. Finally, the commenter anticipates that there 

will be a large number of these requests and that restricting approval to the EPA will create a terrible 

delay in their approval that will put sources at a compliance risk.

Response to Comment 100: The EPA disagrees. Under implementation of the NESHAP program, the 

EPA routinely retains the approval authority over these issues. There is nothing so unique within the 

EGU sector as compared to all other industries to take a different approach under this rule.

Comment 101: Commenter 17752 requests that the EPA provide guidance on how to operate a 

baghouse to obtain the three different PM concentrations.

Response to Comment 101: The comment is moot, as the rule no longer requires control device 

operational parameters to be monitored.
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5A05a - Testing/Monitoring: Operating parameter monitoring (bag leak detection systems)

Commenters: 17704, 17716, 17725, 17737, 17775, 17868, 17871, 18014, 18498

Comment 1: Several commenters (17716, 17725, 17775, 17868, 18014, 18498) recommend that the 

EPA remove the requirement to comply with the procedures in EPA-454/R-98-015. According to the 

commenters, the referenced document is based on operating and maintenance procedures for a specific 

type and model of bag leak detector (BLD) and is inadequate for many BLD systems (BLDS). The 

commenters state that the definition of BLDS clearly allows use of a variety of technologies, including 

electrodynamic, light scattering, and light transmittance. According to the commenters, the required 

guidance document excludes all other technologies (e.g., light scattering, light transmission, optical 

scintillation, and electro-dynamic devices).

Comment 2: Commenters 17775 and 17868 request clarification regarding the applicability of the 

requirements for fabric filters. The commenters state that although several provisions suggests that 

BLDS are only required if an EGU “chooses” to demonstrate compliance using a BLDS and cite, as an 

example, proposed section 63.10011(b), other provisions appear to require any EGU with a fabric filter

to employ a BLDS along with any other applicable operating limits (citing Proposed Tables 4-8). 

According to the commenters, the EPA should issue a proposal that makes clear when a BLDS would be 

required and to justify that requirement.

Comment 3: Commenter 17704 states that if there is any redundancy such as BLDS for units with 

fabric filters choosing to comply with PM CEMS, the requirement for the BLDS should be removed.

Comment 4: Commenter 17775 states that the recording alarm time in 1-hour increments is 

unreasonable. In the case of a broken bag, the most common baghouse failure, alarms can usually be 

cleared in only a few minutes by removing a single compartment from service.

Comment 5: Commenter 17737 strongly objects to any requirement to use BLDS to demonstrate 

compliance. The commenter has been operating these devices on two of its units, and they have proven 

to be extremely susceptible to false alarms. According to the commenters, on numerous occasions 

(sometimes multiple occurrences in one day) the BLDS have indicated an alarm, following which an 

investigation reveals no problems relating to particulate emissions or control equipment, and often, the 

condition is rectified simply by cleaning the probes. According to the commenters, these false alarms 

add to operational costs and keep plant personnel from their regular duties. The commenter suggests the 

use of opacity measurement in place of PM CEMS or BLDS as compliance assurance monitors. The 

commenter notes this would be similar to the requirements of 40 CFR 60.48 Da. According to the 

commenters, opacity monitors have proven to be reliable in detecting changes in PM emission levels 

which could trigger an operator investigation of potential malfunctions and take appropriate corrective 

action. According to the commenter, because there is no reliable numerical correlation between PM 

emissions and opacity, the opacity monitoring (and the same holds for BLDS, should an operator elect to 

use them) should be used solely as an indicator and not for compliance. The commenter provided a 

CAM example using opacity as the indicator and states that such an approach is sufficient to 

demonstrate continuous control of PM emissions and should be suitable for continuous compliance with 

the MACT standard for non-Hg metals especially when a control device with efficiencies above 99.5 

percent is used for PM control, such as a fabric filter.

Comment 6: Commenter 17871 states that nearly all units are required to install a continuous opacity

monitoring system (COMS), either as a result of the NSPS or through the NSR program. According to 
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the commenter, in other rulemakings, the EPA has asserted that while COMS “cannot directly measure 

PM emissions,” a “properly calibrated and maintained COMS is sufficient to demonstrate long-term PM 

control device performance, since the purpose of the monitoring is to demonstrate with reasonable 

certainty that the PM control device is operating as well as it did during the PM emissions test used to 

demonstrate compliance” (In re Newmont Nevada Energy Investment, LLC, PSD Appeal No. 05-04 

(EAB 2005) (citing 70 FR 7905, 7908 (Feb. 16, 2005))). According to the commenter, where each unit 

would be subject to comprehensive and duplicative monitoring schemes, the EPA should refrain from 

requiring installation of an expensive CEMS that does not provide additional compliance certainty.

Response to Comments 1 - 6: The final rule does not require use of a BLDS for EGUs that employ a 

fabric filter control device. We believe that continuous monitoring in the form of CEMS, sorbent traps, 

or CPMS or that frequent emissions testing are appropriate to ensure ongoing compliance with this rule. 

We also agree with commenters that some of the monitoring provisions in the proposal were duplicative 

and unnecessary. In order to simplify and streamline the final rule, we have removed most operating 

parameter monitoring from the final rule. We have retained the owner-defined operating limit 

monitoring using a PM CPMS as an option to periodic emission testing.

The rule establishes the PM CPMS as an operating limit monitor and not a direct filterable PM emission 

monitoring requirement that meets PS11 requirements. While we recognize the importance of continued 

control device performance to ensure emissions minimization, we also are aware that other rules that 

apply to these units - including but not limited to the operating permits rule, the CAM rule, and the 

NSPS – already require continuous monitoring in most cases. Those rules will remain in effect so the 

need to impose additional operating limits monitoring or CEMS on those units is much reduced. For 

these reasons, the final rule includes no requirements applicable to BLDS.
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5A06 - Testing/Monitoring: Application of Hg CEMS

Commenters: 17197, 17383, 17402, 17620, 17621, 17622, 17638, 17675, 17677, 17681, 17690, 17691, 

17704, 17718, 17725, 17728, 17747, 17752, 17757, 17758, 17761, 17775, 17800, 17804, 17805, 17808, 

17843, 17868, 17877, 17881, 17930, 18014, 18025, 18039, 18421, 18428, 18449, 18498, 18023

1. Requested clarifications and corrections.

Comment 1: Commenter 18014 advises that proposed sections 63.10010(f) and 63.10021(h)(ii) have 

contradicting requirements for quarterly accuracy determinations and daily calibration drift tests.

Comment 2: Several commenters (17728, 17758, 17775, 17868) state that all references in the proposal 

to 40 CFR Part 60, Procedure 5 (e.g., section 63.10021(a)(14)(ii)) should be deleted because the 

quarterly and daily requirements in Procedure 5 are duplicative of and conflict with some of the 

proposed requirements in proposed Appendix A, and use of Procedure 5 is inconsistent with the EPA’s 

preamble statement that it considered and rejected using Procedure 5.

Response to Comments 1 - 2: The Procedure 5 references have been removed from the proposal so that 

the Appendix A requirements, based on the CAMR approach, are used for Hg monitoring under this 

rule, as indicated in the preamble to the proposed rule.

Comment 3: Commenter 17775 states that proposed Appendix A contains a number of provisions that 

conflict with and/or duplicate requirements of part 63, subpart A, or with other proposed requirements in 

subpart UUUUU:

1. For example, according to the commenter, proposed section 7.2.2 requires 21 days notice of RATAs, 

whereas 40 CFR section 63.9 requires 60 days notice of performance evaluations (a term that is 

defined in section 63.2 to include RATAs).

2. According to the commenter, proposed section 7.2.3.1 requires submission of a monitoring plan 21 

days prior to initial certification testing or recertification testing, whereas proposed section 

63.10000(d) requires submission of the monitoring plan 60 days before the initial “performance 

evaluation.”

3. According to the commenter, proposed section 7.2.5.5 requires the owner or operator to submit a 

compliance certification in support of each report based on reasonable inquiry, whereas proposed 

section 63.10031(c)(2) requires that the compliance report contain a “statement by a responsible 

official with that official’s name, title, and signature, certifying the truth, accuracy, and completeness 

of the content of the report.”

4. Finally, according to the commenter, the data validation provisions in section 5.1.3 conflict with the 

out-of-control definitions in proposed section 63.10000(d)(6) and Table 9. Specifically, the 

commenter asserts that Appendix A establishes data validation criteria for Hg CEMS in Table A-3, 

which sets the acceptance criteria at ≤5.0 percent of span value or ≤1.0 μg/scm, proposed section 

63.10000(d)(6) requires development and implementation of a site-specific monitoring plan that 

“defines a continuous monitoring system that is out-of-control consistent with section 63.8(c)(7)(i),”

and Table 9 and section 63.10031(c)(9) also require reporting of periods during which a CMS was 

“out-of-control, as specified in section 63.8(c)(7).” The commenter states that the term “out-ofcontrol” also is used to determine what data may be used to report emissions and what constitutes a 

deviation of monitoring requirements under proposed section 63.10020(c) and (d) and that Section 

63.8(c)(7)(i) defines “out of control” with respect to a “calibration drift test” as exceeding “two 

times the applicable CD specification in the applicable performance specification of in the relevant 
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standard.” According to the commenter, this definition is inconsistent with Appendix A. The 

commenter states that EPA must clarify its proposal regarding the definition of “out of control” and 

must resolve these (and any other) duplications and inconsistencies, and where a requirement in 

Appendix A is more detailed or restrictive than a similar requirement in the part 63 general 

provisions or subpart UUUUU, or vice versa, the EPA must explain the need for the more restrictive 

requirement.

Response to Comment 3: The EPA indicated in the preamble to the proposed rule that its intent was to 

adopt the CAMR-based requirements for Hg monitoring because many sources had already installed 

monitors to meet those requirements. Thus, the intent of our proposal was to use these specific 

requirements in place of the general part 63 Hg monitoring requirements. These requirements for Hg 

CEMS went through notice and comment rulemaking for the same set of sources. Although CAMR was 

set aside on other grounds, these technical specifications and QA requirements reflect significant input 

from stakeholders and analysis by the EPA to establish an appropriate foundation for Hg monitoring at 

electric utilities under the CAA. For the final rule, we have made conforming changes to ensure that this 

intent is carried out effectively throughout the rule text and Appendix A, as well as including certain 

additional clarifications based on the input received in response to this proposed rule. 

Comment 4: Commenters 17620 and 17691 state that it is unclear, from the form of the Hg emissions 

limit and the compliance methodology, whether the EPA intends that the Hg limitations include total Hg 

or only vapor-phase Hg. The commenters state that according to the proposal, continuous compliance 

can be demonstrated by the use of Hg CEMS, which measure only vapor-phase Hg and that the EPA 

also mentions of the use of Method 29 or Method 30B for demonstrating compliance. The commenters 

state that Method 29 measures total Hg whereas Method 30B measures only vapor-phase Hg. 

Additionally, the commenters state that in its discussion of allowable certification methods for Hg 

CEMS, the EPA references the use of the Ontario Hydro Method or EPA Method 29, each of which 

measures total Hg.

Comment 5: Several commenters (17804, 17843, 18039) state that it is not appropriate to allow 

compliance demonstrations without accounting for particulate bound Hg which can be a substantial 

fraction of total Hg emissions. The commenters have determined that the filterable portion of total 

particulate emissions for coal-fired EGUs without wet scrubber controls can produce an average of 30 

percent- 40 percent filterable PM. The commenters recommend that the EPA require total Hg emissions 

to be the basis of compliance demonstrations by taking into account the average particulate bound Hg 

measured during the most recent stack test on that unit in combination with the total vapor-phase Hg 

measured by the CEMS until such time as Hg CEMS to measure particulate-bound Hg are installed at a 

unit. Commenter 17853 provides as an example the Massachusetts Department of Environmental 

Protection’s final Hg emissions regulation at 310 CMR 7.29(5)(a)3.g.ii. 

Response to Comments 4 - 5: The Hg emissions limits were established based principally on the results 

from Method 30B emissions tests (vapor phase Hg) coupled with data from some Method 29 test 

programs. Though the Method 29 results would include the particulate fraction, this generally

constitutes less than 5 percent of the total Hg. The final rule then requires continuous monitoring for 

units firing fuels other than liquid oil using either a Hg CEMS or a sorbent trap monitoring system both 

of which measure vapor phase Hg concentration. The final rule allows for the use of Method 29, the 

Ontario Hydro Method, or Method 30B if the source elects to use such methods when emissions testing 

a liquid oil-fired unit. Method 29, Method 30B, or Ontario Hydro Method testing for Hg is not 

applicable for other types of affected units.
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Comment 6: Commenters 17718 and 17781 request clarification with respect to section 63.10005(e). 

The commenters state that under this section there is no mention of beginning to use data obtained 

during the first 30-day operating period “after the monitoring system is certified,” though this language 

does appear in similar monitoring system sections (i.e., 40 CFR 63.10005(d)(4)-(6)). The commenters 

note that there are sorbent trap monitoring system certification requirements (e.g., RATA) mentioned in 

the proposed “Appendix A to subpart UUUUU – Hg Monitoring Provisions.” The commenters question 

whether it was the EPA’s intent that data should not be used until the initial certification is completed. 

Commenters also state that the EPA should clarify whether if sorbent trap monitoring systems are 

certified prior to the compliance date the “30-day operating period” for determining initial compliance 

begins on the compliance date. Commenter 17781 believes that any 30-day period within the first 180 

days following the applicable compliance date should be allowed for the initial compliance 

demonstration.

Response to Comment 6: This concern has been addressed by clarifying the language in the final rule.

2. Technical review of appendix A and incorporation of part 75 provisions.

Comment 7: Several commenters (17752, 17775, 18014) find similarities between Hg CEMS

requirements in Appendix A and the now-vacated CAMR provisions of Part 75. The commenters

generally support attempts to provide consistency between the proposal and Part 75, but Commenter

17775 does not believe all of the Part 75 requirements are necessary in a MACT standard or that the 

proposal established that all requirements can be consistently met. Commenter 17775 incorporates a 

memorandum by McRanie Consulting with the following technical recommendations for proposed 

Appendix A:

1. The consultant recommends adding language that specifically allows for use of backup monitors. 

Commenters 17752 and 18014 also support such a clarification and commenter 17775 states that 

such language should apply to both Hg CEMS and sorbent trap systems. Several commenters

(17752, 17775, 18014) also recommend incorporation of provisions for use of like-kind replacement 

components and backup instruments as provided in sections 75.10(e) and 75.20(d). Commenter

17775 believes these provisions are necessary to minimize data loss during periods when an 

instrument must be returned to the factor for repair. The consultant believes that a 720-hour like-kind 

replacement provision is essential to maintaining acceptable Hg CEMS availability.

2. The consultant and commenters 17752 and 17775 also recommend that more widespread use of 

grace periods should be in the final rule; commenter 17752 believes that a 720-day grace period for 

like-kind replacements should be sufficient for required factory repairs and that a grace period of at 

least 24 hours is needed for weekly system integrity checks. Commenter 17775 believes that the 

system integrity test is likely to be one of the most challenging tests because EGUs subject to the test 

under state programs have reported frequent failures and the need for manual performance so that a 

technician can observe the process and identify problems during the test. According to commenter

17775, these issues led Northeast States for Coordinated Air Use Management, (NESCAUM) to 

conclude:

At this point, it appears that the equipment associated with the system integrity tests may 

not yet be at the point where the test can be performed in an automated fashion with high 

reliability. This affects how the tests can be scheduled because a technician needs to be 

available to monitor them.
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Commenter 17775 states that if the system integrity test cannot be automated, EGUs will need to 

monitor operating hours to determine when a test will be due, and ensure that a qualified technician is 

available because most EGUs do not have technicians available to perform routine tests on nights and 

weekends. According to the commenter, even if the test is scheduled to be performed on time, issues 

with monitoring system breakdowns and the time necessary to complete maintenance could also result in 

late tests. Commenter 17775 states that the proposal provides no basis for specifically excluding the test 

from grace period provisions, and the commenter requests at a minimum that the final rule include an 

operating hour grace period of at least 72 unit operating hours before data are invalidated because that 

would provide an EGU time to schedule and perform a test if one were triggered unexpectedly by a unit 

startup or shutdown, and such a grace period would be consistent with provisions for linearity checks, 3-

level system integrity checks, and RATAs. Commenter 17775 suggests that another possible approach 

would be a calendar day interval for testing combined with an operating hour grace period to provide 

relief if the unit is not operating or the monitoring system is out of service when the test is due. 

According to the commenter, if the EPA does not provide some sort of flexibility, the availability of 

valid Hg CEMS data for compliance calculations may be needlessly limited simply due to late tests that 

do not indicate any actual problem with the monitoring system or data quality.

1. The consultant recommends removing the second sentence of section 3.1.7 because the 

recommended nominal span ratio yields a span that, according to the consultant, “makes it 

impossible to comply with many of the other QA/QC requirements of this appendix because the 

available NIST traceable Hg calibration gas concentrations are not compatible.” The consultant also 

points out that the second sentence of section 3.1.7 is inconsistent with section 3.2.1.4.2, and 

commenter 17775 emphasizes how important these sections are for specifying appropriate rounding 

procedures for establishment of span because of the current unavailability of NIST traceable Hg 

calibration gases at lower spans. Commenter 17775 requests that the final rule include such rounding 

provisions

2. The consultant recommends removal of the “level detectable” and “detectable limit” terms in 

sections 3.1.8 and 3.2.1.2.2.1 because “detection limit” is not defined and the meaning of the rule 

language is unclear.

3. The consultant and several commenters (17752, 17775, 18014) request that the final rule incorporate 

cross-references to Part 75 for measurements required under Appendix A that are already required 

under Part 75. Commenter 17775 believes that cross references are preferable to paraphrasing of the 

Part 75 requirements in the final EGU MACT rule. The consultant presents an example, in proposed 

Appendix A section 3.2.3.3, where the text specifies span requirements for CO2 and O2 monitors 

using terms and concepts that are used under Part 75, but that are not used or defined elsewhere in 

Appendix A. Commenter 17775 refers to the consultants review states that since these provisions are 

incomplete and potentially inconsistent with Part 75 provisions, operators that already are complying 

with Part 75 should have the option of simply meeting the Part 75 requirements. The consultant also 

states that references to MPC should be removed from Appendix A because “MPC has no meaning 

for O2, CO2, or stack flow rate in this proposed rule because there is no data substitution.”

4. The last sentence in section 4.1.1.3 should refer to Table A-1.

5. The consultant believes that the value of “0.03 μg/dscm” in section 4.1.1.5 should be 

“0.02 μg/dscm” to be consistent with both PS-12A and Method 30B, and the consultant recommends 

adding a statement in section 4.1.1.5 invoking the acceptance criteria of PS-12A and Method 30B.

6. The consultant recommends revising section 4.1.1.5.1 to adopt Part 60 and Part 75 language that 

says more than nine runs can be performed but a maximum of 3 can be discarded.

7. The consultant recommends removal of references to PS-6 because he is concerned that references to 

PS-6 in Section 4.1.1.5.2 will lead operators and testing companies to the misconception that all of 
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PS-2 applies to Appendix A procedures. The consultant further recommends that the final rule 

include the relative accuracy calculations in Appendix A.

8. The consultant believes there are problems units of measure and dry and wet bases within section 12 

of PS-2 with respect to proposed Appendix A that are likely to create confusion and recommends 

adding the following sentence to section 4.1.1.5.2, “For purposes of calculating the relative 

accuracy, ensure that the reference method and monitor data are on a consistent basis, either wet or 

dry.” The consultant states that these comments are also relevant to section 4.1.2.3.

9. The consultant relays recent exchanges between the agency’s testing personnel and source testers 

conducting Method 30B and PS-12B at units with very low Hg concentrations. According to the 

consultant, the “breakthrough” specification is not achievable as Hg concentrations approach zero. 

Commenter 17775 states that for concentrations < 0.5μg/m3but > 0.1 μg/m3, the alternative 

breakthrough criteria could be < 50 percent of the section 1 Hg mass. For concentrations < 0.1μg/m3, 

there would be no breakthrough criteria and the validity of the samples would rest on all other 

performance specifications being met. A consistent achievable alternative specification also should 

be provided in Method 30B. Commenter 17775 requests promulgation of revisions concurrent with 

finalization of subpart UUUUU, or complete a rulemaking to revise PS-12B and Method 30B well in 

advance of the subpart UUUUU compliance deadline.

10. The consultant encourages the agency to expedite publication of the “codes” referenced in proposed 

Appendix A for various parameters to facilitate development of reporting software by venders.

11. The consultant believes that references to “...tests described in paragraphs 7.1.10.3 through 7.1.10.6 

...” should be corrected to “...tests described in paragraphs 7.1.10.1 through 7.1.10.6 ...” but 

generally finds section 7.1.10 to be confusing.

12. The consultant states that section 7.2.5.3.3 requires electronic reporting of “The information in 

paragraphs 7.1.2 through 7.1.19 ....” but advises that there are no sections 7.1.11 through 7.1.19.

Several commenters (17752, 17775, 18014) state that the EPA should consider adding provisions for 

conditional data validation in the final rule similar to section 75.20(b)(3)(ii)-(vi); Commenters 17752

and 17775 also state that setting data as conditionally valid following the calibration error test (or other 

maintenance activities that require further QA procedures) is a good provision for improving data 

availability.

Response to Comment 7: The EPA acknowledges commenters’ general support for finding consistency

with Part 75. For the items concerning backup monitoring and conditional data validation, the EPA 

agrees and has made changes to the final rule and Appendix A to provide for backup monitoring and 

conditional data validation similar to part 75 approaches. For the concerns raised with the system 

integrity check requirement, the final rule retains the weekly system integrity check requirement, 

without a grace period. However, to add flexibility, the required frequency of the test has been changed 

from once every 168 operating hours to once every 7 operating days. Operating days are much easier to 

track than operating hours. The test can be done at any time during the 7th operating day, rather than 

requiring it to be done at a certain hour. We believe that this added flexibility will allow utilities to 

schedule the test in accordance with the technician’s work schedule.

For item 1, the EPA has added a cross reference in section 3.1.7 to section 3.2.1.4.2 with respect to 

rounding in order to provide for consistent implementation. For item 2, the EPA notes that the use of 

zero gases for calibration is a well-understood concept within the industry. The rule language has been 

revised slightly to provide for a workable standard that can adjust over time as industry-standard 

detection limits may change. For Item 3, the EPA agrees, and has made a number of changes to provide 

direct references to Part 75 in Appendix A in lieu of specifying comparable provisions in this rule. For 

the specific recommendations in items 4 through 12 above, the EPA has made conforming revisions 
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generally consistent with these clarifying suggestions. In particular, the absolute value relative deviation 

specification for paired Method 29 or Ontario Hydro method sampling in section 4.1.1.5 has been 

changed to 0.2 μg/dscm to be consistent with Method 30B. Section 4.1.1.5.2 has been revised to ensure 

that RATA data are compared on a consistent moisture basis. Regarding the recommendation for an 

alternative “breakthrough” specification for Method 30B and PS-12B, the EPA plans to propose, in 

revisions to Method 30B, the alternative breakthrough specifications suggested by the commenter to be 

applicable to relative accuracy testing. The EPA does not plan to modify the breakthrough specifications 

for compliance testing applications of Method 30B as it is important to maintain tight specifications 

even at low levels; testers will need to use longer sampling times or more low background sorbents if the 

breakthrough criteria cannot be met. We have also modified section 4.1.2.2 of Appendix A to include 

the alternative breakthrough specifications suggested by the commenter for relative accuracy testing of 

sorbent trap monitoring systems; the agency will consider revising PS-12 B at a later time as part of 

ongoing evaluation of that performance specification. The EPA will be proceeding with ECMPS

modifications with appropriate reporting codes as the commenter notes is needed.

Comment 8: Commenter 18449 states that many of the assumptions and regulations regarding “Span”

date back a generation or more when chart recorders and 4-20 mA links were commonly used. 

According to the commenter, in those days, readings exceeding the “Span” value resulted in invalid 

data, and the chart recorder or the 20 mA loop pegged, clamping the data at the maximum span value. 

The commenter notes that much has changed with both instrumentation and data acquisition systems. 

According to the commenter:

1. All of the commercially successful Hg CEMS are atomic fluorescence (AF) based and are linear 

over a very wide range. (e.g., Tekran: 0.01 – 300 μg/m3)

2. The systems operate linearly over this range as one span range. (i.e., There are no range knobs, or 

other adjustments required to obtain this range.)

3. They report digitally, such that the actual concentration value is reported. There is thus no loss of 

accuracy in transmitting this wide range of values.

4. The systems report with an “overload” flag when they finally reach their limits, positively

identifying periods of invalid data.

5. Provided that a CEMS can demonstrate good (i.e., low) zero readings, using a higher concentration 

gas to calibrate a Hg CEMS does not affect its low concentration accuracy. For example, states the 

commenter, calibrating an AF based CEMS using a 9 μg/m3 calibration gas will not cause it to read 

a subsequent stack concentration value of, say 1 μg/m3 any less accurately than having calibrated it 

with a 4.5 μg/m3 calibration gas; in fact, the 9 μg calibration gas would probably yield a more 

accurate number since the uncertainty of the actual cal gas concentration is smaller at higher 

concentrations. (According to the commenter, this is largely a function of the uncertainty that NIST

can provide.)

Commenter 18449 states that, despite the past practice, any requirement to run dual spans is totally

unnecessary for Hg CEMS. The commenter notes:

1. Each span range requires independent QA/QC. This requires three separate concentrations of 

elemental and ionic calibration gases for each span. This would double the QA/QC time required, 

resulting in more periods of missing data.

2. All CEMS use gas generators rather than bottled gases, but these generators operate over a limited 

range limitations. An elemental generator that is designed to produce sub-microgram levels may be 

different than one that produces say 100 ug/m3 for the occasional high peak.
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3. Many systems have separate ionic calibrators. If two ionic calibrators are required, the total could 

become four separate calibrators per system, which is impractical. 

The commenter believes the EPA should take this opportunity to finally address this issue in a rational 

manner. According to the commenter, calibration of Hg CEMS should be at the normal (low level) span 

range to maximize accuracy. Manufacturers should be allowed to demonstrate the dynamic range of 

their instrumentation. The commenter states that if an instrument calibrated at a normal span range was 

shown to be capable of measuring a much higher concentration accurately, (within x percent) the data 

would be deemed valid no matter how much it exceeded the span value. According to the commenter, 

this might take specialized generators capable of producing high output concentrations, and a factory 

“type approval” or one time on-site demonstration would be sufficient.

Response to Comment 8: The EPA agrees that dual range Hg CEMS are not a requirement of this rule. 

Appendix A of this rule provides guidance and requirements for establishing the span value and fullscale range for monitoring with a Hg CEMS. The span value is established based on the Hg 

concentration corresponding to the applicable emission limit. Establishing the range will require 

identifying the Maximum Potential Concentration (MPC) which defines the full-scale range that the Hg 

CEMS being used must be capable of monitoring.

Comment 9: Commenter 17800 states that it is unrealistic to require submittal of hourly Hg data in a 

format that this similar to part 75(see Appendix A section 7.2). The commenter notes that in the Cement 

MACT the EPA has not required the submittal of hourly data for any of the CAA section 112 listed 

pollutants. According to the commenter, the reporting requirements in these rules rely solely on the 

recordkeeping and reporting requirements contained in 40 CFR part 63, subpart A and 40 CFR part 60, 

subpart A. The commenter states that in the proposed Utility MACT rule, compliance with the Hg limit 

is determined on a 30-day rolling average and thus the need for hourly measured Hg concentrations is 

superfluous and the EPA has provided no reason for this treatment. The commenter recommends the 

EPA revise Appendix A to subpart UUUUU and require only semi-annual reporting of what is required 

in 40 CFR part 63, Subpart A. 

Response to Comment 9: The EPA has retained the hourly reporting of CEMS data, using the ECMPS

approach as outlined in the proposed rule. This approach was supported by a number of commenters. 

See further discussion of this decision under responses to comments in 5B03 of this document.

Comment 10: Commenter 17800 states that the EPA’s assumption that there would be little or no cost 

for flow, CO2 or O2, and moisture monitors is invalid (see 86 FR 25033). The commenter notes that its 

part 75 monitors do not have moisture monitors and adding them will be an added expense.

Response to Comment 10: Moisture monitoring is not required but is an option for use in calculating 

emissions in units of the emission limit. The EPA expects that units that currently have moisture 

monitors installed under part 75 may use those under this rule, but that other sources will use one of the 

other options available, such as a moisture default value.

Comment 11: Commenter 17877 states that weekly system integrity checks should be eliminated and 

are unnecessary to demonstrate compliance with a not-to-exceed limit. According to the commenter, the 

existing CAMR performance criteria were created under the auspices of a cap and trade program. The 

commenter states that performing the standard ongoing QA tests that are deemed sufficient for the Acid 

Rain Program (daily calibrations, quarterly linearity checks, and annual RATAs) would be appropriate 

and simplify ongoing QA tests to a consistent set of requirements. Further, according to the commenter, 
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system integrity checks introduce a safety hazard due to the use of chlorine and historically have been 

very difficult to pass with the current maturity level of the monitoring technology. The commenter states 

that at a minimum, a qualified technician would have to be devoted to a full day each week in order to 

try and complete a successful integrity check and that many more man-hours are already going to have 

to be devoted to maintain CEMS for utilities that will also be operating PM and HCL monitors. The 

commenter suggests that as an alternative to a weekly integrity check, a quarterly sorbent trap test (in 

non-RATA quarters) along with the quarterly linearity check.

Response to Comment 11: The EPA disagrees and has retained the proposed requirement for weekly

system integrity tests if the CEMS uses a converter and if daily calibrations are not done with a NISTtraceable source of oxidized Hg. The system integrity test assesses the efficiency with which the 

converter reduces oxidized Hg to elemental Hg; conversion efficiency must be confirmed as poor 

efficiency would result in a low bias in the Hg measurements. The EPA also disagrees with the labor 

hour assumptions for this test. At least one vendor has developed an automated solution to the weekly 

system integrity checks. In addition, to add flexibility, the required frequency of the test has been 

changed from once every 168 operating hours to once every 7 operating days. Operating days are much 

easier to track than operating hours. The test can be done at any time during the 7th operating day, rather 

than requiring it to be done at a certain hour. We believe that this added flexibility will allow utilities to 

schedule the test in accordance with the technician’s work schedule.

3. Achievability of Hg performance specifications.

Comment 12: Commenter 18023 states that Hg CEMS are not capable of achieving the data availability

of CEMS for other pollutants because Hg presents unique problems. According to the commenter, first, 

Hg levels are being measured equivalently in parts per trillion (ppt) whereas other pollutants are 

measured on a parts per million (ppm) basis, Hg has a tendency to adsorb and desorb from the sampling 

system, and the measurement technology requires considerable time to stabilize following maintenance. 

According to the commenter, during that period of stabilization, significant drift (false trending of data) 

can occur making accurate reporting of data nearly impossible. The commenter states that currently, 

Appendix A of the proposed rule contains only the requirement that entities report when data is 

unavailable And Appropriately, the rule does not set a percentage of time for how often data is required 

to be available. According to the commenter, utilities do not have sufficient experience in operating Hg 

CEMS, and with all of the QA requirements expected, it is difficult to estimate what an appropriate 

availability limit would be. Commenter 18023 suggests that therefore the EPA should allow utilities to 

gain several years of experience with these systems and the requirements of the final rule and then 

revisit the availability question through a notice and comment rulemaking after a request for information 

from the industry.

Comment 13: Commenter 17775 recollects previous court challenges to Hg CEMS requirements under 

CAMR in UARG v. EPA, No. 06-1394 (D.C. Cir. 2006) regarding the viability of Hg CEMS technology. 

Commenters (17775, 17728) state that data availability is a concern based on a report in the docket 

(EPA-HQ-OAR-2009-0234-14040) entitled “Technologies for Control and Measurement of Mercury 

Emissions from Coal-Fired Power Plants in the United States: A 2010 Status Report, Northeast States 

for Coordinated Air Use Management, July 2010.” According to the commenter, this report notes the 

existence of reasonable concerns about the reliability of Hg CEMS and that, in general, availability is a 

concern for new technology. The commenters state that the proposal did not provide data to establish 

consistent achievability of all proposed specifications for Hg CEMS.
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Response to Comments 12 - 13: The final rule does not specify a data availability requirement; 

however, the rule does specify that CEMS must be operated at all times that the affected unit is in 

operation (except for CEMS malfunctions and QA checks). The agency believes that the record 

indicates adequate availability of Hg CEMS necessary to comply with the final standards. To the extent 

that a facility does not believe the CEMS can function to provide adequate data availability at a 

particular source, the facility may elect to use a sorbent trap monitoring system and/or a backup 

monitoring system.

Comment 14: Commenters 17677 and 17681 relay experience measuring Hg emissions since 2008 

using a dilution-extractive CEMS and state that the proposed Hg limit is below accurately measureable

concentrations. Through RATA one commenter asserts significantly increased error as the Hg emission 

levels decline to less that 3 ug/m3. The commenter states that as allowed in the Hg CEMS RATA 

regulations, emissions less than 5 ug/m3 are allowed an alternate allowance from relative accuracy and 

given a plus or minus 1.0 ug/m3 difference from the EPA method 30B sorbent trap reference method 

result and that the proposed rule sets the Hg limit well below the accuracy capabilities of Hg CEMS. 

The commenter contends that the proposed limit is fundamentally immeasurable and states that the EPA 

should set a Hg emission level that is measurable and supported by sound scientific data pertaining to 

CEMS technology.

Comment 15: Several commenters (17638, 17681, 17930) state that Hg CEMS are not sufficiently 

accurate or reliable at the EPA’s proposed emission levels to justify their use. Commenter 17930 states 

that the UV lamps in Hg CEMS are particularly troublesome and that problem, along with others, results 

in numerous failures of the CEMS.

Comment 16: Commenter 17675 describes agreements with the state permitting authority to reduce Hg 

emissions and the associated experience with Hg CEMS on coal-fired EGUs. According to the 

commenter, these systems provide accurate and audited continuous monitoring for Hg emissions. Even 

though these CEMS are currently state of the art, the lower limit of quantification for these CEMS and 

other similar technology is very near the Hg level required to be achieved in stack gases by the proposed 

Hg limits as documented in a recent study report by Dennis Laudal of the Energy & Environmental 

Research Center at the University of North Dakota titled “DETERMINING THE VARIABILITY OF 

CMMS AT LOW HG LEVELS”. The commenter states that while it is likely that the quantification 

limits of Hg CEMS will improve as more systems are installed to monitor for compliance with the 

MACT standards, EGUs subject to these proposed standards that prefer to install CEMS early may be 

forced to install sorbent traps to be assured that the systems will meet MACT monitoring 

requirements. Commenter 17675 believes that sources that have already installed Hg CEMS should be 

given an automatic extension of the Hg monitoring requirements if the CEMS that are already installed 

need to be upgraded to meet the EPA’s monitoring requirements.

Comment 17: Commenter 17728 relays experience with Hg CEMS operating on side-by-side sister 

units and states that the instruments do not yield comparable results for unknown reasons.

Response to Comments 14 - 17: If for a particular source, a facility believes that a Hg CEMS cannot 

achieve the performance requirements needed to satisfy the final standards, the facility may elect to 

install and use a sorbent trap monitoring system to monitor for continuous compliance. There are data in 

the draft report cited by one of the commenters, “DETERMINING THE VARIABILITY OF CMMS AT 

LOW HG LEVELS,” that demonstrates reasonable performance of at least one Hg CEMS at Hg levels 

below 1.0 ug/m3 down to approximately 0.1 ug/m3.
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Comment 18: Commenter 17725 states that based on their experience with eight installed Hg CEMS at 

three facilities in New York, the cost to operate and maintain these systems are not warranted given 

obvious compliance. According to the commenter, in general, CMMS are expensive to operate and 

maintain, there is a limited pool of qualified support contractors, they are tricky to install, difficult to 

operate correctly, and, since the installation of baghouses at Dunkirk and Huntley, the concentrations are 

so low that we are not always confident of the results even when the calibration and all requirements are 

met. The commenter states that if the CMMS had been required under CAMR, the commenter suspects 

that resolving the problems would have been very difficult. The commenter recommends a reduced 

monitoring plan if facilities can demonstrate de minimis emissions. 

Response to Comment 18: The LEE provisions in the final rule allow for reduced monitoring for many

facilities with very low emissions. The EPA believes those provisions allow for cost-effective 

monitoring where sources have very low emissions.

Comment 19: Commenter 17761 states that based on their more than 4 years of experience with Hg 

CEMS at its Scott Energy Center Unit 4 Hg CEMS can overstate actual emissions, demonstrates 

significant variability, does not necessarily correlate with stack testing measurements (20-25% higher 

than through stack testing), and will have difficulty meeting the aforementioned 95% availability 

requirements.

Response to Comment 19: See response to Comments 12 and 13 above.

Comment 20: Commenter 17805 states that based on their experience with Hg CEMs they have found 

the system to challenging and the company is still working with the Hg CEMS vendor to resolve 

monitor issues. Based on this, the commenter states that it is still appropriate for the EPA to allow 

alternative methods of demonstrating compliance. The commenter further notes that the EPA should 

confirm with suppliers and vendors that all necessary Hg NIST traceable calibration gases are available. 

The commenter also believes the certification requirement for the monitoring system NIST certified 

calibrator by an offsite third party vendor will create challenges for systems already installed under 

state-specific requirements. The commenter recommends the EPA work with state agencies to 

coordinate these requirements.

Commenter 17805 agrees with the EPA that application of a bias adjustment for Hg emissions is not 

necessary. It is the commenter’s understanding that a bias adjustment, as used for SO2 emissions in the 

Acid Rain Program, was primarily intended to assist with ensuring emissions were adjusted properly for 

cap and trade of emissions. Since Hg will not be traded, the commenter opines that bias adjustment is 

not necessary.

Response to Comment 20: The EPA has developed the approaches to Hg CEMS calibration including 

NIST traceability of elemental and oxidized Hg gas generators based on its work with NIST and 

numerous other stakeholders. To the extent that the commenter or others believe an alternative 

calibration approach can provide equivalent results, then the commenter may apply for an alternative 

method under the provisions of section 63.7(f).

Comment 21: Commenter 17690 states that because New York State requires Hg CEMS they are in a 

unique position to comment on the proposed rule’s continuous compliance requirements. The 

commenter believes that all of the proposed additional monitoring requirements are similar to the New 

York requirements in that they represent the specification of an advanced technology that does not have 

a long and widespread history. The commenter states that while the testing equipment vendors may
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argue that their monitoring systems are fully functional, the commenter’s experience is that for these 

types of applications the vendor infrastructure, industry capabilities, and even regulatory understanding 

and support are inadequate to meet the compliance schedule in the proposed Utility MACT rule. Further 

background information and detail to this comment are provided in Appendix 2 (see EPA-HQ-OAR2009-0234-17690-A1.pdf for Appendix 2 pg 21.) The commenter provides the following observations 

and recommendations:

1. Commenter agrees that it is appropriate to harmonize monitoring and reporting requirements, to the 

extent possible, with those of 40 CFR Part 75.

2. Commenter supports the option to simply integrate air toxic emissions data and QA test results into 

the existing 40 CFR Part 75-compliant data acquisition and handling system computers already in 

place. However, we would prefer to use the 40 CFR Part 60 deviation-based reporting approach 

because acid gas, metal and PM hourly measurements have little value; ultimately, long-term totals 

are of greater value in determining impact.

3. According to the commenter, it is appropriate to use the existing Emissions Collection and 

Monitoring Plan System (ECMPS) infrastructure for reporting air toxics data and QA test results but 

commenter does not believe that is appropriate to develop a different reporting system.

4. Commenter supports disabling the bias adjustment for all air toxics data because bias adjustment is 

only appropriate for emissions trading programs.

5. Commenter agrees that hours when a monitoring system is out of service should simply be counted 

as hours of monitor down time, to be counted against the percent monitor availability.

6. Commenter favors the EPA’s proposed streamlined continuous compliance approach and suggests 

that if this program were to integrate the Clean Air Markets Division (CAMD) staff experience to 

the maximum extent possible that the reporting process will be user friendly and efficient.

7. Commenter recommends adding at least 2 years to the final implementation date for the continuous 

monitoring requirements. During the extended implementation period, affected sources should 

provide documentation of procurement, installation and testing progress. The EPA and NIST should 

develop the necessary traceability protocols and testing programs necessary to support widespread 

air toxic continuous monitoring programs. It would also be appropriate to try to develop sorbent trap 

methodologies for air toxics.

8. Commenter recommends that if continuous monitoring at any affected source finds that the majority 

of observations are less than a certain level then the source should have the option to discontinue 

continuous emission monitoring and replace it with regular stack testing and compliance assurance 

monitoring. For example, for Hg, that certain level should be 2 μg/m3.

Response to Comment 21: The EPA largely agrees with the comments related to the use of ECMPS

and electronic reporting of data. See further discussion under Comment Code 5B04. The EPA disagrees 

with the need for an additional 2 years for compliance with the monitoring requirements. Compliance 

with the final rule is 3 years following promulgation, which should provide sufficient time for continued 

advancement of Hg CEMS monitoring technology, which has already been demonstrated successfully at 

numerous facilities. For the bias adjustment comments, see response to Comments 40 and 41, below. 

Regarding data availability, see response to Comments 12, 13, and 19, above.

Comment 22: Commenter 18014 states that the proposal does not justify the burden of requiring 

ECMPS reporting because the data reporting requirements in Appendix A for Hg go far beyond what is 

necessary. According to the commenter, the EPA portrays this proposed reporting requirement as easy

and that sources would “simply integrate Hg emissions data and QA test results into the existing Part 75-

complianct DAHS.” According to the commenter, the EPA creates a false dichotomy stating that it 

considered two options:
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1. For deviation and data assessment reports, sources would “need to have a data handling 

system(DAHS) that: (1) Is programmed to capture data from the Hg CEMS; (2) uses the criteria in 

Appendix F to Part 60 to validate or invalidate the Hg data; (3) calculates hourly averages for Hg 

concentration and for the auxiliary parameters (e.g., flow rate, O2 or CO2 concentration) that are 

needed to convert Hg concentrations to the units of the emission standard; (4) calculates 30 boiler 

operating day rolling average Hg emission rates; and (5) identifies any deviations that must be 

reported to the agency.”

2. “Simply integrate Hg emissions data and QA test results into the existing Part 75-compliant DAHS”

and submit data through ECMPS. After presenting these two options, the EPA states that it obtained 

“feedback from several DAHS vendors” who suggested the cost of the second option was “similar, 

and some cases, less than the cost of the first option.”

According to the commenter, however, any software under Option 2 would have to do everything the 

EPA described under Option 1. The commenter asserts that sources would likely integrate the new 

requirements within the DAHS that they currently use for Part 60 and Part 75 reporting but this does not 

mean that the proposed reporting scheme would be simple or cheap to implement.

Response to Comment 22: The EPA disagrees. As other commenters have stated generally, the use of a 

unified approach to CEMS reporting under this rule and the Part 75 reporting already conducted by the 

affected EGU population provides a straightforward and consistent reporting method for the industry.

Commenter 17805 supports using a Hg CEMS to demonstrate continuous compliance and has been 

operating and maintaining a Hg CEMS to report emissions at the Lewis & Clark Station to the Montana 

Department of Environmental Quality for about 2 years. However, the system has been challenging and 

the company is still working with the Hg CEMS vendor to resolve monitor issues, and therefore, it is 

still appropriate for the EPA to allow alternative methods of demonstrating compliance.

Comment 23: Commenter 17626 states that Hg limits need to be set to be consistent with the 

technology not only for control but for reliable and accurate measurement. The commenter believes that 

the proposed levels may be theoretically achievable, but current monitoring technology and 

standardization does [not] exist to measure these levels accurately and precisely. According to the 

commenter, this places the supplier in the position of being unable to guarantee such performance. The 

commenter notes it is not a not a measurement supplier but supports the position taken by such 

organizations as the Institute of Clean Air Companies (ICAC) to resolve these issues.

Response to Comment 23: If for a particular source, a facility believes that a Hg CEMS cannot achieve 

the performance requirements needed to satisfy the final standards, the facility may elect to install and 

use a sorbent trap monitoring system technology to monitor for continuous compliance. See section 

5A06 for further discussion of Hg CEMs and sorbent trap monitoring.

Comment 24: Commenter 17637 states that it is not precisely determined whether test methods exist 

that are accurate, reliable and consistent enough to ensure compliance with the stated emission limits. 

Hg stack testing and other on-line measurements have not been fully developed to provide an accurate, 

repeatable and reliable level of Hg emissions. According to the commenter, although a performance 

specification has been proposed by the EPA, the hardware to support such a standard in the day-in-andday-out environment is still unproven.

Response to Comment 24: The EPA disagrees that the test method and monitoring hardware are not 

fully developed to meet the stated emission limits in the final rule. Performance Specification 12B which 
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is required in the rule along with Performance Specification 12A which has similar hardware 

requirements to those in the rule have both been promulgated since September 9, 2010 (75 FR 54970). 

See 5A06 in this document for further discussion of Hg CEMS and sorbent trap monitoring.

4. QA requirements for elemental and HgCl2 generators.

Comment 25: Commenter 17197 has concerns with Appendix A, section 3.2.1.2 Reagent and Standards 

Requirements and sections 3.1.4 and 3.1.5 based on experience with an Hg CEMS since 2007. The 

commenter has concerns with the referenced NIST traceability protocol’s 8-quarter recertification 

interval for HgCl2 “user generators” because these interim protocols will require the “user generators” to 

be removed from the Hg CEMS and sent to the manufacturer for recertification. According to the 

commenter, these calibration gas generators are integral components of the TEKRAN Hg CEMS and are 

not easily removed or reassembled. The commenter states that the TEKRAN Hg CEMS is not designed 

to accept calibration gas from a generic “Field Reference Generator,” or cylinder gas standard (NIST

transfer standards) and that recertification of the “user generators” may require that many of their 

subassemblies (gas and liquid flow meters, temperature controllers) be calibrated to NIST reference 

methods. According to the commenter, this requires specialized equipment and knowledge generally 

available only from the manufacturer and consequently, the “send-to-manufacturer-for-recertification”

prerequisite is the only real option provided under the interim protocols. According to the commenter, 

this option presents significant challenges, costs, and risks because the sequence of removing the user 

generator, installing the temporary user generator, configuring the DAHS for the temporary user 

generators, and then reinstalling the recertified user generator and reconfiguring the DAHS for the 

recertified user generators is very complex. The commenter states that specialized TEKRAN knowledge 

is required for these certification activities. A significant concern for the commenter is the potential for 

generator and Hg analyzer contamination, and equipment damage during disassembly, shipping, and 

reassembly. According to the commenter, the elemental and HgCl2 generators contain very delicate 

subassemblies that can be damaged in shipping, which may affect the recertification. The commenter 

states that to help ensure proper Hg CEMS operation, onsite equipment vendor technical assistance 

would likely be required to install the temporary user generators and to reinstall the recertified user 

generators. The commenter believes that the significant costs, technical challenges, and equipment risks 

associated with the interim NIST traceability protocol’s user generator recertification interval provisions 

are overly restrictive. Consequently, the commenter advocates that the proposed NIST traceability

specifications referenced in Appendix A only become effective when they become final and that the “... 

or an interim version of that protocol” phrase in Appendix A, sections 3.1.4 and 3.1.5 definitions be 

deleted.

Comment 26: Commenter 17197 also recommends that the interim NIST traceability protocols be 

modified to include a recertification interval extension option for the user generators when the Hg 

CEMS meet a RATA incentive specification. The commenter proposes that the final NIST traceability

protocols contain a RATA performance incentive option that extends the user generators’ 8-quarter 

recertification interval another four quarters if the Hg CEMS successfully passes the annual RATA 

testing at the following proposed incentive specification:

 10 percent RA,

 or < 0.8 μg/scm difference, if RM average is ≤ 5.0 μg /scm.

According to the commenter, the proposed <0.8 μg/scm difference is consistent with the linearity and 

integrity check requirements. It is the commenter’s view that the user generators should retain their 

NIST certification as long as the Hg CEMS is able to achieve the alternate RATA incentive performance 
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specification and other periodic QA/QC requirements (i.e., daily calibration, weekly integrity, quarterly 

linearity). The commenter asserts that if the Hg CEMS cannot achieve the RATA incentive 

specification, the owner/operator should have a 60-day grace period to recertify the user generators. The 

commenter supports a 60-day grace period due the complexity of the user generator recertification 

process.

Response to Comments 25 - 26: The EPA disagrees. The interim NIST traceability protocols for 

elemental and oxidized Hg gas generators represent significant effort on the part of the EPA, the CEMS

vendor community, and affected sources to examine the calibration generator traceability issues, and 

devise an agreed upon approach for addressing those issues. In fact, one part of this collaborative effort 

between the EPA and its stakeholders focused on the development of an approach to allow the elemental 

Hg generators to remain ‘in the field’ for recertification and one of the organizations representing 

industry demonstrated how it could be effectively accomplished.

5. Monitoring challenges for new unit Hg limits.

Comment 27: Commenter 17622 believes that Hg CEMS are superior to sorbent traps because 

continuous monitoring is best done with methods that provide “real time” monitoring that can alert 

operators to changes in conditions that affect emission rates. According to the commenter, sorbent traps, 

while a valid continuous measurement method for Hg emissions, do not provide adequate response time 

to be useful for control and achievement of compliance at the new unit limits. The commenter believes 

that operators will likely target lower emissions levels (e.g., ~50 percent of the limit for a new unit) for 

their control set points, in order to have sufficient margin to achieve the proposed 30-day rolling average 

limitation. According to the commenter, as electronic real-time Hg CEMS will likely be used for 

emissions control, monitoring and reporting, there are a number of prospective hurdles for new units 

because commercially-available Hg CEMS have not been fully certified at low levels (<1.0 μg/m3) due 

to the NIST standard at 0.5 μg/m3 only recently being available. Commenter 17622 goes on to state that 

the EPA NIST protocol for traceability of Hg generators has not been implemented at Hg concentrations 

<0.5 μg/m3. According to the commenter, more testing, and possibly development and evaluation of 

commercially-available Hg generators, is needed to ensure that NIST traceability can be demonstrated 

and that the Hg CEMS enable control methods for units to stay in compliance. The commenter is 

concerned that the low Hg emissions level required for new units may be lower than the uncertainty of 

available measurement methods. The commenter states that Sorbent Trap Reference Method 30B

requires a fresh look, particularly relative to sampling protocol and lower limits of detection (LLD) to 

meet and certify the new EGU limits for Hg and that it is unlikely that current electronic Hg CEMS can 

be confidently or reliably employed for monitoring, control and reporting of prospective new EGUs

emissions under the proposed Utility MACT. According to the commenter, there are clearly both 

challenges and concerns about the traceability of commercially - available Hg CEMS required to 

effectively administer the proposed existing unit emission limits. The commenter recommends that the 

EPA develop a strategic initiative with NIST, targeting lower-level Hg (i.e., <0.5 μg/m3) calibration and 

standards traceability and support for Hg CEMS and sorbent trap methods.

Comment 28: Commenter 17758 states that the proposed new source Hg limit cannot be measured by

any current or planned instrument, and even if a new unit could meet the limit, there is no way to assess 

compliance.

Response to Comments 27 - 28: The final rule provides the option for use of either Hg CEMS or 

sorbent trap monitoring systems. The EPA believes the record clearly shows these to be proven 

technologies, each providing certain advantages. For existing and some of the new unit limit standards, 
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the level of the NIST traceable Hg standard is adequate and consistent with existing applications of Hg 

CEMS. For the lowest new unit standard, the affected facilities may opt to use sorbent trap monitoring 

systems to comply. As noted in a previous response, there are data in the recent draft report entitled 

“DETERMINING THE VARIABILITY OF CMMS AT LOW HG LEVELS,” that demonstrate 

reasonable performance of at least one Hg CEMS at Hg levels below 1.0 ug/m3 down to approximately

0.1 ug/m3.

Comment 29: Commenter 17704 supports both the use of Hg CEMS and the alternative use of sorbent

traps as proposed. The commenter also supports the proposed use of 30 days worth of valid Hg CEMS

data as the initial compliance test. 

Response to Comment 29: The EPA acknowledges this support. See further discussion of sorbent trap 

monitoring option, below.

Comment 30: Several commenters (17758, 17868, 18428) state that the Hg monitoring requirements 

should be revised because the accuracy of Hg CEMS near the concentration of the proposed existing 

source limit is questionable, and one commenter states the technology is not viable at the proposed level 

of the new source limit for the following reasons:

 The high relative uncertainty of NIST-traceable calibration gases and the lack of any NISTtraceable calibration gases corresponding to the proposed emissions standard.

 Persistent issues transporting samples from the stack to the measurement cell. 

 The EPA acknowledged unreliability of Hg CEMS at concentrations corresponding to the 

standard when responding to questions on the EGU ICR; see 

https://utilitymacticr.rti.org/FAQ/FAQEmissionsTesting.aspx#TEST-002.

Commenter 17758 states that without further investment in developing Hg CEMS technology to address 

issues with the availability of NIST-traceable calibration gases at the appropriate concentration levels 

and sample transport, the only viable option for electric utilities for meeting the continuous Hg 

measurement requirement is to install, certify and operate a Hg sorbent trap-based monitoring system 

meeting the specifications in PS12B. 

Response to Comment 30: See response to Comments 27 and 28 above.

Comment 31: Commenter 17383 states that they installed CEMS in preparation for the implementation 

of CAMR and discovered that these monitors took significant man-hours to maintain and to insure their

accuracy. According to the commenter, the EPA has left the long-term operational problems, including 

the development of adequate calibrators and calibration gases to industry. The commenter states that 

with respect to standards for new units, the EPA developed standards for which there are not accurate 

and reliable monitoring methodologies for demonstrating compliance. 

Response to Comment 31: The EPA disagrees; see the response to Comments 14-17, above.

6. Sorbent traps.

Comment 32: Commenter 17402 expresses strong support for the use of sorbent traps as the preferred 

method for Hg monitoring because the commenter’s experience has been that CEMS struggle to 

measure low levels of Hg in the range of 0.10 μg/m3 to 0.50 μg/m3. By contrast, according to the 

commenter, sorbent traps are demonstrably capable of measuring Hg in that range, and sorbent traps 
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offer a more consistent and accurate means for monitoring compliance. The commenter states that 

consequently, the EPA should ensure that sorbent traps remain a permissible means of compliance 

monitoring in the final rule. If the EPA decides to allow only one method of monitoring, the commenter

favors the use of sorbent traps because of their heightened accuracy when compared with Hg CEMS. 

The commenter relays specific experience with both CEMS and sorbent traps that indicates monitoring 

results with sorbent traps are more reliable. The commenter believes that it would be far more reliable to 

look to sorbent traps for compliance with the MACT rule for facilities emitting more than 22 pounds per 

year, and the commenter provides a lengthy list of problems encountered with Hg CEMS deployments 

and highlights how sorbent traps do not encounter these problems.

Comment 33: Commenter 18023 states that a sorbent trap-based Hg monitoring system is not a realistic 

option for units using ACI because real-time feedback from the CEMS is needed to adjust the ACI rate, 

but a sorbent based monitor does not provide real-time feedback. According to the commenter, a 

dilemma for new units is that it is quite possible that the only mechanism to detect the new source limit 

will be through sorbent trap systems, but the new source Hg emission limit is so stringent that it will 

require sorbent injection for control, yet sorbent trap based monitors cannot be used to modulate ACI

systems. The commenter states that sorbent trap based Hg monitoring systems would have limited use 

on any unit unless the compliance averaging time is extended to at least a 90-day block average because 

if significant amounts of data are lost over the 30-day compliance period, then demonstrating 

compliance becomes problematic. According to the commenter, sorbent trap based Hg monitoring 

systems have the potential for losing at least seven days’ and as much as fourteen days’ worth of data. 

The commenter states that the potential loss of data out of a 30-day period would be a particular problem 

for units that must meet the new source limit because the Hg compliance limit is so low for those units.

Comment 34: Commenters 17808 and 18025 support the use of sorbent traps and note that the EPA 

should not assume that most EGUS have Hg CEMS.

Comment 35: Commenter 18421 strongly supports the EPA’s proposal to require the use of CEMS or 

sorbent traps for Hg as this will ensure affected sources can demonstrate continuous compliance with the 

proposed Hg emissions standards. According to the commenter, the EPA’s assessment that most, if not 

all, units that would have been subject to the CAMR had purchased an advanced Hg monitoring system 

like CEMS or sorbent traps is supported by evidence in a report by NESCAUM. The commenter states 

that according to NESCAUM, Hg CEMS and sorbent traps are currently in use on over 700 coal-fired 

power plant stacks (over 600 Hg CEMS and nearly 100 sorbent traps) (see NESCAUM, Technologies 

for Control and Measurement of Mercury Emissions from Coal-Fired Power Plants in the United States: 

A 2010 Status Report). According to the commenter, the EPA also correctly points out that many states 

require coal-fired units to install and operate such controls to demonstrate compliance with SIP or 

consent decrees.

Comment 36: Commenter supports the inclusion of sorbent trap monitoring systems as an appropriate 

testing method for continuous Hg monitoring. Commenter installed both CEMS and a sorbent trap on 

Unit 2 at its Spurlock Station in 2008 to compare the operation and maintenance characteristics of the 

two technologies; operation of the Hg CEMS began in October 2008 and sorbent trap monitoring in 

January 2009. The commenter states that it has experienced recurring reliability issues with the Hg 

CEMS including constant calibration drift issues, sample transport issues, probe convertor failures, Hg 

analyzer and Hg lamp failures, design issues that result in a time consuming process to diagnose 

problems, the need for continual recertification of the calibrator and unreliable operation due to 

mechanical breakdowns. The commenter’s experience with a Hg sorbent trap monitoring system has

been positive due to a number of strengths in the system including reliable design with no sample 
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transport issues (the sample is collected at the end of the probe in the traps), the system is simple, 

problems are diagnosed easily and quickly, the system is appropriate for wet stacks and the system 

provides accurate Hg data.

Response to Comments 32 - 36: The final rule includes the option of using sorbent trap technology as 

well as Hg CEMS for monitoring compliance with the Hg standard. For the ACI control rate issue raised 

by one commenter, a source would be free to use a Hg CEMS for control operations and use the sorbent

trap monitoring for compliance if it feels that such operational data is sufficiently critical to its control 

operations. The addition of backup monitoring provides a further option for addressing the concerns 

over data loss mentioned by the commenter. The EPA disagrees that the sorbent trap method cannot 

work on a continuous basis at the emission limit levels in the final rule. While it is true that the potential 

exists for increased capture of other stack gas constituents by the sorbent traps during long-term 

monitoring, PS12B addresses this situation. As a result, achieving the monitoring method’s 

measurement performance requirements ensures data of known and acceptable quality. The EPA 

disagrees that a systematic error exists between the Hg CEMS and sorbent trap technology. In fact, the 

data from the EERC study definitively show that the agreement between the sorbent trap technology and 

Hg CEMS at these low levels is significantly better than that required by the relative accuracy 

specifications in PS 12A, which are consistent with those in the final rule. Also, with respect to PS 12B, 

section 8.3.2, PS 12B is an approved regulatory requirement that has gone through notice and comment 

rulemaking as an appropriate set of requirements for a sorbent trap monitoring system. The EPA is not 

revising PS 12B as part of this rulemaking. The requirement to utilize the same type of sorbent material 

in the sorbent trap monitoring system as will be used in the future for daily operations simply provides 

for an additional check on the overall system and procedures. If Method 30B is employed as the 

reference test method to conduct the relative accuracy testing, the tester may choose to use a different 

sorbent for the Method 30B sampling train to provide additional independence in the measurements. For 

low level concerns, the EPA disagrees that the sorbent trap reference method (Method 30B) is unsuitable 

to reliably perform RATA testing on electronic CEMS at low Hg emissions concentrations. Method 30B

is a performance-based method that is, in effect, self-validating each time it is applied and the methodspecific performance criteria are met. Moreover, recent testing conducted as part of the Utility MACT

ICR demonstrated that Hg concentrations well below 0.1 μg/m3(100 ng/m3) were reliably measured. In

addition, RATA requirements for Hg concentrations less than 0.5 μg/m3are a component of Appendix A 

in the final rule and are known to be consistent with the measurement performance capabilities of 

Method 30B. For NIST capability issues, see earlier response to Comments 27, 28, and 30.

Comment 37: Commenter 17757 suggests that quarterly performance tests and analyses of sorbent trap 

monitoring data would be adequate to determine compliance with an annual emission limit.

Response to Comment 37: The EPA disagrees. Monitoring technology adequate to show continuous 

compliance in accordance with the emission limit exists and is preferable to periodic emissions testing. 

In other circumstances under the rule, the EPA has allowed for periodic testing, but in the case of Hg, 

given the importance of this HAP from this sector and the availability of appropriate monitoring options, 

the EPA reaffirms the proposal and has retained the continuous Hg monitoring provisions in the final 

rule.

Comment 38: Commenter 17775 supports use of sorbent trap monitoring systems and reliance on PS 

12B, subject to the following comments. According to the commenter:
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1. First, the EPA should explicitly provide an option for use of backup monitoring systems to allow 

sources to plan for the possibility of significant monitoring system failures where it is economical to 

do so.

2. Second, the EPA should provide a low emitter “breakthrough” specification in PS 12B and in 40 

CFR Part 60, Appendix A, Method 30B. According to the commenter, the current performance 

specification for Method 30B allows for 10 percent breakthrough for effluent concentrations above 1 

μg/m3 and 20 percent for concentrations below 1 μg/m3, and as the actual effluent Hg concentration 

approaches zero, this specification becomes virtually impossible to meet. The commenter asserts that 

to compound the problem, PS 12B contains a breakthrough specification of 5 percent at all 

concentrations. The commenter states that during testing for the 2010 ICR, RMB Consulting & 

Research, Inc. identified this issue during testing at several plants with very low Hg emissions and 

submitted a proposal to the EPA supporting use of an alternative specification at low concentrations 

(see W. Roberson, RMB Consulting & Research, Inc., “Proposed Alternative Performance 

Specifications for Method 30B” (June 14, 2010) (see (Attachment 10))). According to the 

commenter, in the proposal, RMB illustrates with Method 30B data how failure of the specifications 

is simply a matter of mathematics, because percent-based specifications lose meaning as results 

approach zero, and RMB recommended that the EPA provide the following alternative performance 

specifications for breakthrough: A) For concentrations < 0.5μg/m3 but > 0.1 μg/m3, the alternative 

breakthrough criteria could be < 50 percent of section 1 Hg mass; B) For concentrations < 0.1μg/m3, 

there would be no breakthrough criteria and the validity of the samples would rest on all other 

performance specifications being met.

According to the commenter, in response, the EPA staff indicated that, for the purposes of the 2010 ICR

testing, and for stack concentrations less than or equal to 0.5 μg/m3, EGUs could consider Method 30B

data valid as long as it meets all other QA/QC criteria, even if it does not meet the section 2 

breakthrough criteria of Table 9-1 of Method 30B but that the EPA indicated that approval of the 

exception for the use of Method 30B when conducing RATAs or compliance tests would require 

additional discussion within the agency. Commenter believes that a number of units being retrofitted 

with baghouses and scrubbers may achieve Hg emissions levels below 0.5 μg/m3. According to the 

commenter, in order for sorbent trap monitoring systems to be available as an option, an alternative 

breakthrough specification is needed in PS 12B. The commenter states that a consistent achievable 

alternative specification also should be provided in Method 30B, and commenter requests that the EPA 

promulgate those revisions concurrent with finalization of subpart UUUUU, or complete a rulemaking 

to revise PS 12B and Method 30B well in advance of the subpart UUUUU compliance deadline.

Response to Comment 38: See the responses to Comment 7, above.

Comment 39: Comment 18449 states the continuous sorbent trap method has not been tested or 

validated at the very low levels being proposed. According to the commenter, although they use 

essentially the same method and technology, continuous sorbent tube measurements are even more 

challenging than sorbent tube reference method measurements. The commenter states that cartridges 

will be exposed continuously for (typically) 1 or 2 weeks, resulting in massive buildup of other stack 

contaminants as compared to the short term (2 to 4 hour) exposure period of reference cartridges. 

According to the commenter, the high levels of potential interferents that are co-eluted when the 

cartridge is heated will challenge the performance of the analytical instrumentation.

Commenter 18449 notes that a recent EERC study had what are probably the best possible sorbent trap 

results. The commenter states that EERC took extraordinary care in running the samples, and the 

manufacturer of the analyzer, Ohio Lumex, provided considerable support throughout the study. The 
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commenter states that agreement between the Tekran CEMS and the sorbent traps was very good, with 

virtually no zero offset and a R2 value of 0.990. The commenter states that even under these best 

possible conditions, there was a systematic 11 percent difference in sensitivity between the Tekran CEM

which used a NIST traceable elemental gas generator for calibration, and the sorbent traps, which used a 

NIST traceable liquid solution for calibration. The commenter questions which was correct.

Commenter 18449 states that PS 12B is mentioned as the standard for continuous sorbent Hg monitoring 

systems. The commenter provides that Section 8.3.2 under RATA testing, states that “The type sorbent

material used in the traps must be the same as that used for the daily operation of the monitoring 

system.” According to the commenter, the purpose of a RATA is to provide an independent test of the 

validity of the continuous monitoring system’s results, and if different sorbent types yield different 

results, this is an indication of a severe problem somewhere. According to the commenter, it may be 

desirable, from a user point of view, to use the same sorbent, but the commenter does not believe it 

should be a requirement to do so.

Commenter 18449 provides the following comments with respect to the sorbent tube provisions:

1. If Hg levels in the low ng/m3 range are set as the MACT limits, they would have to be RATA’d on a 

regular basis. Commenter does not believe that the sorbent tube reference method has been 

sufficiently validated at these low levels to establish that it could be used to reliably perform RATA 

testing on electronic CEMS.

2. NIST is incapable of measuring or certifying Hg concentrations in the low ng/m3 range. According 

to the commenter, after 5 years of effort, the lowest point that NIST can certify is 0.5 μg/m3 and 

even this point can only be certified to an uncertainty of 6.1 percent. The commenter notes that this 

level of uncertainty applies to the NIST calibrator only and that vendor and user calibrators would 

have still higher uncertainties. Absent major developments, the commenter does not believe the 

NIST traceable gases be available to validate low ng/m3 measurements.

Response to Comment 39: See response to Comments 32-36 above.

7. Provisions for Hg CEMS on bypass stacks.

Comment 40: Commenter 18023 states that the final rule should clarify the provisions for units with a 

main stack and a bypass stack regarding use of the maximum potential concentration (MPC) for each 

hour in which the bypass stack is used. According to the commenter, if this approach is used, the EPA 

needs to clarify what value is used when Hg CEMS installed on a bypass stack measures a number 

higher than the MPC. The commenter also asserts that the EPA should specify that when multiple units 

are controlled by the same device and less than all of those units are being bypassed only the MPC for 

the units being bypassed, should be reported. According to the commenter, MPC should not be used for 

any of this since the MPC approach is only used for emission trading programs; a lower confidence 

interval type of value should be used instead for conditions where a bypass stack is not monitored.

Comment 41: Commenter 17774 states that one difference between section 63.10010(a) and Appendix 

A section 2 is the provision of an option for use of an assumed value during use of a bypass stack. The 

commenter states that Appendix A section 2.4.2 provides for use of the “maximum potential 

concentration” of Hg in lieu of installing an Hg CEMS or sorbent trap system on a bypass stack. 

According to the commenter, installation of CEMS on a bypass stack can be problematic from a number 

of perspectives. According to the commenter, in addition to the costs of the additional monitoring 

system, bypass stacks will not be used with sufficient frequency to perform those periodic QA tests that 
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require unit operation (e.g., RATAs and linearity checks). The commenter asserts that correlation of a 

PM CEMS on a bypass stack would be nearly impossible to accomplish without significant operation 

with bypass (since PS 11 requires a minimum of 15 runs).

Response to Comments 40 - 41: The EPA agrees with one of the commenters that the MPC approach 

for bypass stacks is more suited to an emissions trading program. Rather than require the use of the 

MPC to estimate emissions from the bypass stack, the final rule now requires use of one of two options: 

(1) direct monitoring of both the main stack and the bypass stack for Hg or (2) counting of bypass hours 

as hours of deviation from the Hg monitoring requirements. The EGU owner or operator remains subject 

to the 30 boiler operating day rolling average during bypass operations. In addition, the final rule no 

longer requires correlation of a PM CEMS according to PS 11. The monitor will be used as a PM 

CPMS, although the final rule does provide for the use of a PM CEMS to determine compliance with the 

filterable PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

8. Provisions for bias adjustments.

Comment 42: Commenter 18023 states that the final rule should not require the bias test and bias 

adjustment for Hg CEMS as proposed in section 4.1.1.5.3 because the Hg CEMS by nature exhibit drift 

in both the positive and negative directions depending on the cause of the drift which is best corrected 

through normal quality assurance activities, and basing adjustment of the hourly averages on a one-time 

per year test would adversely affect data accuracy. According to the commenter, if a bias test were 

required, it should quantify bias in either direction and allow for adjustment in either direction. The 

commenter states that when stack gas flow is used for the mass calculations then non-bias adjusted flow 

values should be used for that purpose.

Comment 43: Commenter 17805 agrees with the EPA that application of a bias adjustment for Hg 

emissions is not necessary. It is the commenter’s understanding that a bias adjustment, as used for SO2

emissions in the Acid Rain Program, was primarily intended to assist with ensuring emissions were 

adjusted properly for cap and trade of emissions. According to the commenter, since Hg will not be 

traded, the bias adjustment is not necessary.

Response to Comments 42 and 43: No bias adjustment or bias test is required under the final rule.

9. General concerns.

Comment 44: Commenter 17621 states that the EERC of North Dakota conducted a study to investigate 

the low-level measurement capabilities and variability of CMMs from Thermo Scientific and Tekran, 

with support from EPRI, DOE, and the Illinois Clean Coal Institute. The commenter states that EPRI

reported that the quantification level of the Tekran system was 0.1 micrograms per normal cubic meter 

(μg/Nm3), compared to 0.4 μg/Nm3 for the Thermo Scientific system (EPRI, 2010b) and that these 

concentrations are equivalent to about 0.1–0.4 lb/TBtu. The commenter states that Method 30B was 

used as the basis for comparison, with extended sampling times used to reach the low levels of Hg. The 

commenter asserts that based on this study, CMMs from both vendors can measure Hg accurately at the 

proposed MACT limit for existing coal-fired EGUs but that CMM would neither be able to measure Hg 

accurately at the revised MACT limit for new coal-fired EGUs greater than or equal to 8,300 Btu/lb or at 

the proposed limits for either existing or new liquid oil-fired EGUs.
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Response to Comment 44: The final rule provides the option for use of either Hg CEMS or sorbent trap 

monitoring systems. The EPA believes the record clearly shows these to be proven technologies, each 

providing certain advantages. For existing and some of the new unit limit standards, the level of the 

NIST traceable Hg standard is adequate and consistent with existing applications of Hg CEMS. For the 

lowest new unit standard, the affected facilities may opt to use sorbent trap monitoring systems to 

comply. As noted in a previous response above, there are data in the recent draft report entitled 

“DETERMINING THE VARIABILITY OF CMMS AT LOW HG LEVELS”, that demonstrate 

reasonable performance of at least one Hg CEMS at Hg levels below 1.0 ug/m3 down to approximately

0.1 ug/m3.

Comment 45: Commenter 17747 states that the cycle time test unfairly excludes monitoring 

technologies that can provide accurate mercury measurement. According to the commenter, Xact (the 

commenter’s proprietary testing technology) has demonstrated its ability to measure Hg accurately on 

several different source types including coal-fired power plants. Commenter provided results of studies 

on 585 MW coal fired electric generating facility equipped with ESP controls and located in the 

northwestern United States. According to the commenter, these results demonstrated the Xact had a 

relative accuracy of 3.53 percent, significantly better than the required 20 percent (figure 1 in comment 

document). According to the commenter, Xact is designed to measure Hg by sampling stack effluent 

nearly continuously, excluding only the time required for the tape to advance from the sampling area to 

the analysis area (~ 20 sec). The sample is typically gathered for 15 minutes and then analyzed for 15 

minutes to achieve detection limits that are appropriate for coal fired power plants, and this means that 

concentration data is reported about 30 minutes after starting to gather the sample. According to the 

commenter, the proposed cycle time would preclude the use of Xact. The commenter states that the key

issues are whether the instrument can measure Hg accurately and precisely and whether emissions are 

nearly constantly monitored and that provided the technology can demonstrate these things, response or 

cycle time is irrelevant.

The commenter notes that the current cycle time requirements are apparently based on what atomic 

fluorescence-based instrumentation can do. Although this technology can deliver mercury concentration 

data more quickly than XRF based technology, it can only measure mercury. The commenter notes that 

the Xact, on the other hand, can measure mercury as well as several other metal hazardous air pollutants 

(HAP) including (antimony, arsenic, cadmium, chromium, cobalt, lead, manganese, nickel, and 

selenium). According to the commenter, this type of data is currently not available using any other 

instrument, and it is unlikely that it could ever be obtained from any atomic fluorescence based 

instrument.

The commenter notes that the proposed Hg monitoring performance specifications are inconsistent with 

those already promulgated under PS 12A. According to the commenter, this performance specification 

does not require a cycle time test, which indicates that EPA does not view a cycle time test as critical to 

the performance requirements of a Hg CEMS. The commenter notes that the reason the EPA did give for 

not using the PS 12A requirements is to “simplify compliance with the proposed rule by harmonizing its 

monitoring and reporting requirements, to the extent possible with 40 CFR Part 75.” According to the 

commenter, this would include eliminating semiannual hard copy reporting of deviations along with data 

assessment reports required by 40 CFR Part 60, where PS 12A resides, and cycle time does not play any

role in these more onerous reporting requirements. The commenter notes that the proposed EGU MACT

does allow for the use of PS 12B (sorbent trap monitoring) and that in this case facilities may sample for 

up to 14 days before ending the traps to a lab for Hg analysis. According to the commenter, this would 

potentially allow 4-6 weeks to elapse before Hg data would be generated and reported, and it clearly 

does not make any sense to allow up to 6 weeks or more for data to be reported under one method of 
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monitoring (sorbent traps) but require data every 15 minutes under another method (CEMS). Finally, the 

commenter notes that because Hg health effects are chronic there is no health benefit associated with 15-

minute cycle times.

Response to Comment 45: The EPA agrees that the cycle time test requirements may be overly rigid 

for integrated batch sampling-based Hg monitoring technologies, and we have made revisions to the 

final rule to accommodate these technologies while still acquiring monitoring data at least once every

15-minutes consistent with our practice for CEMS.

Comment 46: Commenter 18428 states that an alternative to using CEMS for compliance, the EPA 

should allow fuel sampling and analysis for Hg determining Hg emissions from coal-fired units, 

particularly those with low coal Hg content. According to the commenter, this would be consistent with 

the fuel sampling option for oil-fired units under the proposed rule, as well as the similar option 

contained in the Industrial Boiler MACT rule.

Response to Comment 46: The fuel sampling option discussed in the proposed rule is no longer part of 

the final rule because of technical issues with those proposed requirements. The final rule retains the 

proposed approach for Hg monitoring, requiring either a CEMS or sorbent trap monitoring system, or 

LEE testing for existing units with very low emissions.

Comment 47: Commenters 17724 and 17876 state that the CEMS the facility installed in preparation to 

CAMR have significant reliability and operational issues (Hg, PM, HCl). Commenters 17724 and 17876

state that the EPA has left the long-term operational problems such as calibration gases to industry and 

there are not accurate and reliable monitoring methodologies for demonstrating. Commenters 17724 and

17876 state the EPA purports to provide compliance flexibility while in reality there is very little 

flexibility in light of the problematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not 

commercially available to measure HCl emissions from coal-fired EGUs, and no HCl CEMS were used 

to collect the data the EPA used to establish the HCl standard.

Response to Comment 47: The agency disagrees with the commenters. As mentioned elsewhere, the 

agency finds that the operation and maintenance issues for the CEMS mentioned are no different than 

for other CEMS now in wide use and acceptance by the industry. The agency is aware that the 

calibration gas issue is to be rectified well in advance of the rule’s compliance date. The agency notes 

that the rule is quite flexible with respect to compliance demonstration, containing numerous choices for 

compliance, including the use of emissions testing alternatives for those EGU owners or operators who 

remain concerned over use of CEMS or PM CPMS. The agency notes that FTIR CEMS exist now and 

can be used to measure HCl emissions continuously, that the HCl emissions limit was developed from 

emissions testing and has been adjusted to be appropriate for measurement with HCl CEMS, and that 

emissions testing options to demonstrate compliance exist for those EGU owners or operators who 

choose not to use CEMS.
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5A06a - Testing/Monitoring: Application of Hg CEMS (Appendix A)

Commenters: 17725, 17770, 17795, 17796, 17800, 17820, 17821, 17881, 17886, 18449, 19114, 19121, 

19122, 18023

1. Rounding issues.

Comment 1: Commenter 17881 states that section 7.1.8.2 requires Hg mass emissions be reported as 

pounds, to three decimal places. According to the commenter, this is not sufficient precision to allow a 

meaningful comparison to the Hg emission limit for new coal-fired units (coal > 8,300 Btu/lb). The 

commenter states that the Hg emission limit for such units is 0.0002 lb/GWh based upon the EPA’s 

05/18/2011 revised MACT floor analysis memorandum and that units as small as 25 MWe are affected 

by the proposed EGU MACT, so compliance with the aforementioned new unit Hg limit would equate 

to a mass emission rate of 0.000005 lb/hr. The commenter asserts that after rounding the preceding mass 

emission rate, as pounds, to three decimal places, it will become zero, and that \anything as high as 

0.0004 lb/hr will round to zero. Thus, according to the commenter, a unit as small as 25 MWe could 

emit up to approximately 80 times the allowed Hg emission rate and yet still show compliance due to the 

specified rounding precision in Appendix A. 

Comment 2: Commenter 17881 states that section 7.1.9 indiscriminately requires that the Hg emission 

rate records, in units of lb/TBtu or lb/GWh, be rounded to three decimal places. According to the 

commenter, this requirement makes little sense, as all lb/TBtu emission limits in the proposed rule are 

expressed to one decimal place, and several of the lb/GWh Hg emission limits are expressed to beyond 

three decimal places. The commenter states that as noted in relation to section 7.1.8.2, the Hg emission 

limit for new coal (> 8,300 Btu/lb) fired units is 0.0002 lb/GWh. According to the commenter, rounding 

all calculated Hg emission rates to three decimal places would prohibit a meaningful compliance 

determination with the preceding emission limit (i.e., an actual emission rate of 0.0004 lb/GWh, which 

is twice the emission limit, would round to 0.000 lb/GWh, which is compliance with the emission limit). 

Comment 3: Commenter 18449 states that under “Calculation of Mercury Mass Emissions” on page 

25145 the rule requires that reported concentration averages for both CEMS and sorbent methods be 

rounded, to the nearest tenth but that it is not clear how this would work with proposed MACT limits of 

0.02 μg/m3, or how accurate 30-day rolling averages could be calculated with sources in the submicrogram range. The commenter states that it has existing customers that have short term 

concentrations of 0.03 to 0.5 μg/m3, which have been verified by RATA testing. According to the 

commenter, hourly averages should be rounded to two or three significant figures, not tenths. The 

commenter believes that reporting to more decimal points has no downside provided that violations are 

defined as significant exceedances of the limit and that more accurate reporting would also give 

customers due credit if they had low level emissions and had invested in the technology able to report 

them. 

Response to Comments 1 - 3: The EPA agrees with the commenters regarding the precision of the Hg 

concentration values and the Hg emission rates. The final rule requires the hourly Hg concentrations and 

emission rates to be reported to three significant figures, rather than specifying a particular number of 

decimal places. The 30-day average Hg emission rates are to be rounded to two significant figures (i.e., 

the same precision as all of the Hg emission limits). We believe that these changes address the concerns 

of the commenters. 

2. Calculating Hg emission rate.
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Comment 4: Commenter 17881 recommends the following items related to calculating the Hg emission 

rate:

1. Section 6.2.1.1 should be revised to explicitly note that fuel factors from 40 CFR Part 75, App. F, 

section 3.3.5 or those derived consistent with the procedures in section 3.3.6 may also be used for 

these calculations for calculating the Hg emission rate in units of lb/TBtu, According to the 

commenter, this change is necessary due to the fact that Method 19 does not contain fuel factors for 

subbituminous coals, petroleum coke or tire-derived fuels, and the provisions of section 12.3.2 of 

Method 19 would therefore require fuel sampling and analysis in order to determine site-specific fuel 

factors. The commenter states that the preceding would represent an unnecessary burden in light of 

the EPA having already established fuel factors for these fuels under 40 CFR Part 75. 

2. Sections 6.2.1.2 and 6.2.2.2 of Appendix A relate to the calculation of Hg emission rates in units of 

the applicable standard (i.e., lb/TBtu of lb/GWh). According to the commenter, , this section should 

also describe the diluent capping procedure for start-up and shutdown, as allowed in section 

63.10005(l). The commenter states that without reference to the preceding diluent capping 

provisions, these sections would appear to always require the use of the actual measured diluent gas 

concentration (in the context of section 6.2.1.2) or measured electrical load for the hour (in the 

context of section 6.2.2.2). 

3. Section 6.2.2.2 should specify the use of the gross electrical output (consistent with the gross output 

definition in section 63.10042) in order to eliminate any possible confusion as to the basis of the 

MWh values to be used in the calculations (i.e., gross or net). 

4. The formulas for calculation of the lb/GWh Hg emission rate (i.e., A-2, A-3 and A-4) all include an 

operating time component (th). It is not necessary to convert the Hg mass emission rate or the 

average electrical load to a total integrated pound or load value for each clock hour. Rather, the Hg 

mass emission rate and average electrical load can be used to directly calculate the Hg emission rate 

in units of lb/GWh. (commenter references a formula “Consider the following substitution of 

Equation A-2 into the term Mh in Equation A-4, and note that the term th cancels out, as it appears 

in both the numerator and denominator:”)

Response to Comment 4: The EPA agrees with items 1 through 4 in this comment and has made 

corresponding changes in the final rule. 

3. Grace period.

Comment 5: Several commenters (17770, 17820, 17886) note that part 75 has a grace period for system 

integrity checks and recommend the same. Commenter 17820 states that the system integrity test is 

likely to be one of the most challenging tests and if the test cannot be automated EGUs will need to 

monitor operating hours to determine when a test will be due, and ensure that a qualified technician is 

available to generate the oxidized Hg and ensure that the test is conducted properly. According to the 

commenter, if the unit is not fully base-loaded, this will be difficult; most EGUs do not have technicians 

available to perform routine tests on nights and weekends, and even if the test is scheduled to be 

performed on time, issues with monitoring system breakdowns and the time necessary to complete 

maintenance could also result in late tests. Commenter 17820 recommends an operating hour grace 

period of at least 72 unit operating hours before data are invalidated, which would provide an EGU time 

to schedule and perform a test if one were triggered. 

Response to Comment 5: For concerns raised with the system integrity check requirement, the final 

rule retains the weekly system integrity check requirement, without a grace period. However, to add 

flexibility, the required frequency of the test has been changed from once every 168 operating hours to 
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once every 7 operating days. Operating days are much easier to track than operating hours. The test can 

be done at any time during the 7th operating day, rather than requiring it to be done at a certain hour. We 

believe that this added flexibility will allow utilities to schedule the test in accordance with the 

technician’s work schedule. 

4. Recordkeeping and reporting under Section 7 of Appendix A.

Comment 6: Commenter 17881 requests clarification of the recordkeeping and reporting provisions 

contained in appendix A, section 7:

1. The commenter states that it is unclear whether the requirements are meant to apply to the Hg CEMS

and sorbent trap monitoring systems, or all monitoring systems used to demonstrate compliance

2. The commenter states that Section 7.1 requires that all measurements, data, et cetera, must be 

maintained for a period of 5 years from the date of the record. According to the commenter, since 

many of the auxiliary monitoring systems employed under Appendix A will also likely be subject to 

40 CFR Part 75, the EPA should harmonize the data retention requirements with those found in 40 

CFR 75.57(a), which requires that data be maintained for a period of at least 3 years from the date of 

each record. According to the commenter, having two different retention schedules for the same data 

elements (i.e., flow rate data, diluent data, etc.) will simply lead to confusion and potential noncompliance, especially in cases where a facility currently has well established procedures to purge 

various Part 75 data elements after the required 3 year period.

3. The commenter states that the EPA should clarify that none of the provisions in section 7.1.1 and 

related sub-sections apply to those auxiliary monitoring systems which are subject to 40 CFR Part 

75, as many (if not all) of these requirements are duplicative of those that already exist within 40 

CFR Part 75.

4. The commenter questions the rationale for some of the requirements to be reported in the context of 

Hg emissions monitoring. The commenter provides an example of megawatt ratings under section 

7.1.1.2.1; according to the commenter, the EPA makes the presumption that all individual units have 

a defined megawatt output, which is not correct. According to the commenter, In those cases where 

multiple units share a common steam extraction turbine and electrical generator, steam output is 

often the basis for the individual unit ratings, and this approach is clearly allowed under 40 CFR Part 

75 (refer to section 75.53(e)(1)(i)(I)). The commenter also states that the basis for any load rating 

must be specified (i.e., net or gross).

5. The commenter notes that under section 7.1.1.2.1 the identification of controls should be specific to 

those types of controls which have relevance under 40 CFR part 63, subpart UUUUU and that these 

would include acid gas controls, PM controls and Hg specific controls. Thecommetner questions 

how the collection of information on NOX controls, for example, would be relevant under the 

proposed EGU MACT.

6. According to the commenter, formulas used to calculate emissions and heat input under section 

7.1.1.2.1 only need formulas which are specific to the determination of the Hg emission rate in units 

of the applicable standard. The commenter also states that the calculation of heat input is not 

required to support the Hg emission rate determination, and this reference should be removed from 

the rule. 

7. The commenter states that Section 7.1.2 relates to various operating parameter records which must 

be maintained “to the extent that these data are needed to convert Hg concentration data to the units 

of the emission standard”. According to the commenter, rather than leaving it to the discretion of the 

regulated entity to determine whether certain data elements are needed, the EPA should clearly 

specify which data elements are necessary for each of the Hg emission limit forms (i.e., lb/TBtu and 

lb/GWhr). 
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8. The commenter states that Section 7.1.5.2.5 also requires the reporting of hourly PMA, which is not

appropriate when missing data substitution is being prohibited. 

Response to Comment 6: For item 1, appendix A applies to any Hg CEMS or sorbent trap monitoring 

system, as well as any other auxiliary monitoring required to report emissions in terms of the standard. 

As suggested in item 3 of this comment, the final rule clarifies that where such auxiliary systems are 

used, the recordkeeping provisions of part 75 generally apply to those systems. As in the proposal, one 

exception to that rule is that, consistent with the general recordkeeping provisions under the Part 63 

NESHAP program, records used to demonstrate compliance with this rule must be kept for 5 years. For 

items 4 through 6, revisions in the final rule directly address these concerns and streamline the specific 

records that apply. For Item 7, the EPA has left the “as applicable” language as proposed; the reporting 

system will provide for capturing the correct information based on each emission limit. For item 8, just 

because the rule does not specify a minimum data availability requirement, does not mean that 

information on percent monitor availability is unnecessary. This information will be used to ensure that 

sources continue to operate and maintain their monitoring systems in accordance with the requirements 

of section 63.10020(b) and the general monitoring operation provisions that apply across part 63. 

5. Recommendations - Appendix A.

Comment 7: Commenter 17725 recommends that the EPA add a subsection to Appendix A section 

7.1.5.2.3 that clearly states that 40 CFR Part 75 data substitution procedures and bias adjustment factors 

are not to be used with the hourly average volumetric flow rate used by a sorbent trap monitoring 

system.

Commenter 17795 recommends the following changes to Appendix A:

1. The commenter states that Section 3.1.12 should be rewritten to allow the use of the closest upscale 

gas from actual stack concentrations and that currently, the proposal suggests implementing a Hg 

monitor span of 0-10 ug/m3. According to the commenter, for existing units > 8300 Btu/lb to 

demonstrate compliance with the proposed limits, Hg concentrations would need to be less than 1.2 

ug/m3, and therefore the low level calibration gas would be closer to actual emissions and should be 

used as the daily calibration standard (20–30 percent of span value).

2. The commenter recommends quarterly, instead of weekly, oxidized Hg (Hg+2) converter checks. 

According to the commenter, NIST-traceable Hg+2 in the Tekran Hg monitoring systems is 

currently limited to ~2.5 ug/m3, but Hg+2 will be < 0.5 ug/m3 after controls to achieve compliance 

with the proposed standards. According to the commenter, quarterly checks will be more than 

sufficient at these levels. The commenter states that a weekly requirement was understandable for 

the trading program that would have been adopted for the CAMR where Hg+2 could exist in the gas 

stream of units purchasing of Hg allowances, but for this program Hg+2 won’t be quantifiable for 

units in the > 8300 Btu/lb category. According to the commenter, calibrating a system at more than 5 

times the measurable concentration would produce accuracy problems and filter contamination if 

conducted weekly at these levels.

Response to Comment 7: The EPA sees no need to add a subsection to section 7.1.5.2.3 of Appendix A 

as section 4.1.2.4 of Appendix A clearly states that bias adjustment is not required for sorbent trap 

monitoring system data. The EPA does not believe that allowing a low-level gas to be used for daily

calibrations is necessary. Appendix A provides sufficient flexibility in setting the Hg CEMS span value 

and selecting calibration gases. The span value is set starting with the Hg concentration (μg/m3) 

corresponding to twice the level of the standard. This value is then rounded upward, either to the next 
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highest integer, the next highest multiple of 5 μg/m3, or to the next highest multiple of 10 μg/m3. For 

instance, if the level of the standard corresponds to a concentration of 1.2 μg/m3, as suggested by the 

commenter, the span value could either be set at either 3 μg/m3, 5 μg/m3, or 10 μg/m3. If it is set at 3 

μg/m3, a mid-level calibration gas with a concentration of 50 to 60% of the span value (i.e., 1.5 to 1.8 

μg/m3-- which is in close proximity to the level of the standard) could be used for daily calibrations. We 

believe this addresses the commenter’s concerns. 

Regarding the system integrity check, the EPA does not agree with the commenter that a quarterly test 

frequency is sufficient. To obtain accurate data with a Hg CEMS that has a converter, you must ensure 

that the converter is working properly. The system integrity check provides that assurance. Therefore, it 

is not appropriate to allow long time intervals between converter checks. If a quarterly test frequency 

were implemented, there could be more than five months between successive system integrity checks, 

e.g., if the test is done in early January (1st quarter) and the next one is not done until late June (2nd

quarter). This level of quality-assurance for monitoring a HAP such as Hg is unacceptable. 

Comment 8: Commenter 17796 states that the QA procedures for Hg CEMS outlined in CAMR and 

duplicated in Appendix A of the proposal are appropriate for determining that the unit is providing 

accurate results and should not be changed because now compliance is based upon an emission limit and 

not a yearly mass for trading purposes in CAMR.

Response to Comment 8: While the EPA agrees in many respects, we have made certain changes to the 

CAMR-based Hg monitoring procedures as appropriate, such as not using bias adjustment factors and 

not relying on data substitution practices.

Comment 9: Commenter 18023 states that under section 3.2.3.3, to provide for efficiency, the option 

should be provided to allow the use of monitors already installed and certified under part 60 or 75 

without any additional requirements. 

Response to Comment 9: The commenter is referring to the additional monitoring systems described in 

sections 3.2.3.1 and 3.2.3.2 (not section 3.2.3.3, which addresses monitor span and range). These 

additional monitors (i.e., diluent gas, flow rate, and moisture) are needed to convert Hg concentrations to 

the units of the emission standards. The final rule mandates that all of these monitoring systems be 

installed, certified, operated, and maintained according to 40 CFR Part 75 (see §§63.10010(b) through 

(d)), and that the data from these monitoring systems be reported using the ECMPS Client Tool. Nearly

all coal-fired utilities already have these monitors in place to meet Acid Rain Program requirements. The 

final rule makes it clear that no additional certification testing is required under Subpart UUUUU for 

previously-certified Part 75 systems that are continuing to meet Part 75 QA requirements (see 

§63.10005(d)). Note, however, that the use of Part 60 monitors is not allowed---these monitors must 

either be replaced or upgraded to meet Part 75 requirements. 

Comment 10: Commenter 17820 generally supports the EPA’s attempt to provide consistency between 

this proposal and Part 75 but notes that not all of the part 75 requirements are necessary in this context. 

Some of these concerns include:

1. Commenters 17820 and 17800 note that while the EPA proposes ongoing QA requirements for Hg 

CEMS in Appendix A, the rule proposes in section 63.10021(1)(14) to require compliance with 

quarterly accuracy determinations and calibration drift tests in accordance with Part 60, Appendix F, 

Procedure 5. According to the commenters, the quarterly and daily requirements in Procedure 5 are 

duplicative of and conflict with some of the proposed requirements in Appendix A, and use of 
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Procedure 5 is inconsistent with the EPA’s preamble statement that it considered and rejected using 

Procedure 5.

2. The commenter opines that two provisions from Part 75 that could help improve data availability are 

the provisions for use of back up monitoring systems and the provisions for use of conditional data 

validation. According to the commenter, these options have been used under Part 75 for years 

without any reduction in data quality, and the EPA should include provisions in Appendix A to 

allow use of similar procedures.

3. The commenter opines that the EPA should include back up and like-kind replacement monitoring 

system options similar to Part 75 in Appendix A. According to the commenter, including specific 

provisions will avoid the need for future guidance and/or unit-specific petitions if cases arise where a 

backup or replacement is needed.

4. The commenter states that Section 75.20(b)(3)(ii) allows sources that have made a change to a 

monitoring system that requires additional testing (e.g., repairs, replacements, adjustments, 

linearization, reprogramming, relocation, etc.) to conditionally validate data prior to completion of 

all required tests by performing a successful “probationary calibration error test.” According to the 

commenter, this provision has been crucial to maintaining good data availability under Part 75, by

avoiding invalidating data after a monitoring system has been confirmed to be operating properly but 

before all of the required confirming tests can be scheduling and completed.

Response to Comment 10: The final rule removes the references to Procedure 5 and adopts the part 75 

options discussed in items 2 through 4 of this comment.

Comment 11: Commenters 19121 and 19122 support the monitoring requirements for Hg outside of 

part 75. However, the commenters recommend the following changes to Appendix A:

1. Commenters recommend amending the minimum requirement in section 3.1.16 (RATA) of nine valid 

test runs be reduced to a minimum of three runs (six samples) to show compliance. Commenters also 

recommend that a similar reduction in paired runs apply to certification and recertification events in 

other applicable Part 60 rules. 

2. With respect to alternative 2 for accounting for gas moisture content under section 3.2.3.1 

commenters believe that the moisture value need not be limited to the most recent Hg emissions test. 

Commenters recommend that any test event that requires a Method 4 analysis to be performed such as a 

CEMS RATA or Method 4 particulate test result be a valid representation of the stack moisture 

condition.

3. Commenters recommend that “significant percentage” language in section 5.1.5 be more clearly 

defined. The commenters believe that it is likely infeasible to perform a diagnostic linearity check within 

168 hours of a span change as it would require that the Hg calibration gas generators’ output values be 

adjusted by the manufacturer to the new linearity requirements which require new NIST certification of 

the generators. Thus, according to the commenters, the time needed to ship the calibration gas generators 

to the manufacturer, modify and recertify the generators can take longer than 168 hours. Commenter 

19121 recommends that owners/operators have 30 operating days to perform a diagnostic linearity check 

after change of span value.

4. Commenters recommend that if CO2 and flow data is available, the procedures in 40 CFR Part 75 be 

used to calculate the Hg emission rate instead of the current section 6.1.3 that states “for any operating 

hour in which valid data are not obtained, either for Hg concentration or for a parameter used, in the 

emissions calculation, or moisture, as applicable, do not calculate the Hg emission rate for that hour.”
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5. Commenters recommend the EPA incorporate by reference parts of Part 75 that are used to determine 

Hg emission rate calculations in section 7.

Response to Comment 11: Regarding changes 1) through 5) suggested by the commenters:

1. At this time, the EPA has no intention of reducing the minimum number of test runs for the RATA of 

a Hg CEMS from nine to three, as recommended by the commenters. The nine run RATA is a wellestablished procedure that provides a robust statistical basis for determining the accuracy of a CEMS, 

and is familiar to, and widely accepted by, the regulated community and source testers. The commenters 

provided no data to support their claim that three runs (as opposed to nine) are sufficient to assess 

relative accuracy. Without such demonstration data, a change in the RATA procedures is unwarranted. 

Further, the commenters’ broad recommendation to extend the proposed reduction in the number of 

paired runs to “certification and recertification events in other applicable Part 60 rules” is beyond the 

scope of this rulemaking. 

2. Sections 63.10010(b) through (d) of the final rule specifies that all of the additional monitors needed 

to convert Hg concentrations to units of the emission standard must meet the requirements of 40 CFR 

Part 75. To account for stack gas moisture content, Part 75 provides three possible compliance options: 

(a) install and certify a continuous moisture monitoring system; (b) use a fuel-specific default moisture 

value from §75.11(b); or (c) petition the Administrator under §75.66 for a site-specific default moisture 

value. Under option (c), the proposed default value could be based on Method 4 data collected either 

during historical stack tests or CEMS RATAs.

3. Proposed section 5.1.5 of Appendix A has been renumbered as section 5.1.6 in the final rule, and has 

been made consistent with sections 2.1.1.5 and 2.1.2.5 of 40 CFR Part 75, Appendix A, regarding span 

adjustments. The proposed requirement to perform a diagnostic linearity check within 168 operating 

hours after changing the span of a Hg analyzer has been retained, but a clearly defined window of time 

in which the span change must be implemented has been added. The owner or operator has up to 90 days 

after the end of the calendar quarter in which the need for a span change is identified to implement the 

span adjustment.

4. The EPA has not incorporated the commenter’s recommendation. The final rule retains the statement 

in section 6.1.3 of Appendix A prohibiting calculation of Hg emission rates when valid data for one or 

more parameters are not available. This is consistent with a long-standing position that compliance with 

emission rate limits must be based exclusively on actual, measured data---i.e., the use of substitute data 

is not appropriate for Part 60 programs (for example, see statements to this effect in NSPS Subpart Da). 

This is in contrast to emissions accounting programs such as the Acid Rain Program, which require 

pollutant mass emissions to be reported for every unit operating hour, in accordance with 40 CFR Part 

75. During monitor outages, Part 75 requires substitute data values to be used in the calculations. Note 

that even if EPA had decided to allow the use of substitute data during Hg monitor outages, the 

commenter’s suggested calculation approach could not have been implemented, because all of the Hg 

monitoring provisions of Part 75 have been removed from the rule in response to the vacature of the 

Clean Air Mercury Rule (CAMR) (see 76 FR 17301, March 28, 2011). 

5. The EPA has incorporated the commenter’s suggestion to simplify section 7 of Appendix A by

referencing relevant sections of Part 75, but only for the additional monitoring systems that are needed 

to convert Hg concentration to units of the standard (i.e., diluent gas, flow rate, and moisture systems). 

Similar cross-referencing of Part 75 is not possible for Hg emission rate calculations because, as 

explained in the previous paragraph, Part 75 no longer includes Hg monitoring provisions. 
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Comment 12: Commenter 17800 states that the EPA needs to remove the requirement for a NIST

traceable oxidized Hg standard from the certification tests (see 86 FR 25034). The commenter is not 

aware of any oxidized standard for Hg, let alone a “NIST-traceable oxidized Hg standard”.

Response to Comment 12: The definition of a “NIST-Traceable Source of Oxidized Hg” in section 

3.1.5 of Appendix A refers to a generator that: (a) is capable of providing known concentrations of 

vapor phase mercuric chloride and (b) meets the performance requirements of the interim version of the 

“EPA Traceability Protocol for Qualification and Certification of Mercuric Chloride Gas Generators”. 

That traceability protocol was developed with significant input from industry, consultants, and vendors 

of Hg CEMS. The protocol does not provide NIST traceability through an unbroken chain of 

comparisons for the oxidized Hg calibration gas, but rather establishes NIST traceability for chemical 

reagents used to produce the calibration gas (such as HgCl2 solutions or chlorine gas cylinders), and for 

individual components of the gas generator which measure these reagents in the process of producing 

the gas, e.g., weighing and mass flow meters. This approach represents the current “state of the art” and 

has been agreed upon by EPA and industry as an interim methodology. Further research is needed to 

develop direct NIST traceability for oxidized Hg calibration gas standards. 

Comment 13: Commenter 17821 states that section 3.2.1.4.3 proposes to require that the full “range” of 

the Hg analyzer be capable of measuring the MPC values that are defined in section 3.2.1.4.1. 

Commenter encourages the EPA to define the MPC value as the “span” and “range” of the Hg CEMS

and suggests that this value be used as the basis for determining calibration and linearity gas values and 

calibration errors. According to the commenter, modern Hg CEMS are based on digital technology and 

do not have “span ranges” built into the technology like the older analog analyzers of the past. The 

commenter states that they do have analog outputs that can be scaled such that a zero and full scale 

value can be defined to match with the 4-20 mA output signal used for data recording, but that this 

setting is not a span range setting in the analyzer. According to the commenter, modern Hg analyzers 

have a measurement range that is limited only by the lower and upper detection limits of the 

measurement sensors within the analyzer. Commenter understands the need to determine the accuracy of 

an Hg analyzer and the need to determine calibration and linearity errors. However, according to the 

commenter, defining an arbitrary value for “span” is meaningless to a modern Hg analyzer, and a better 

method would be to utilize a standard “span” value for all Hg CEMS used in compliance with these 

proposed rules. (Commenter provides an example.)

Comment 14: Commenter 17821 recommends that the EPA define the “range” of the Hg CEMS as a 

range from zero to the appropriate MPC (see section 3.1.13). According to the commenter, a source 

would then perform linearity checks “across the range as determined by these rules” instead of across 

the analyzer’s entire measurement capability. The commenter states that modern Hg analyzers have a 

large measurement range, and the commenter does not believe that EPA intended for sources to test the 

analyzer across its entire range of measurement but rather across the “span” or full “range” defined for 

use with compliance of these proposed rules. 

Response to Comments 13 - 14: The commenter appears to misunderstand the terms “span” and 

“range” as they are presented in Appendix A. The purpose of the span value is to determine the 

appropriate calibration gas concentrations for daily calibrations and linearity checks---these 

concentrations are all expressed as percentages of the span value. To comply with the stringent Hg 

emission limits in subpart UUUUU, Hg concentrations must be reduced to very low levels. Section 

3.2.1.4.2 of Appendix A requires the span value to be set by multiplying the Hg concentration 

corresponding to the standard by two, and then rounding off the result appropriately. Flexibility is 

provided; the span value (in units of μg/m3) may be rounded to either the next highest integer, the next 
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highest multiple of 5 μg/m3, or the next highest multiple of 10 μg/m3. If better accuracy at the lower end 

of the scale is desired, rounding off the span value to the next highest integer or multiple of 5 μg/m3 may

be preferable to rounding to the next highest multiple of 10 μg/m3, because calibration gases closer to 

the level of the emission standard will be used for daily calibrations and linearity checks (see the 

response to Comment 7, above). The EPA recognizes that low Hg concentrations are often attainable 

only by operating wet scrubbers and/or carbon injection systems, and that it is possible for these 

emission controls to malfunction. During control device malfunctions, Hg concentrations may approach 

the level of the maximum potential concentration (MPC). Therefore, section 3.2.1.4.3 of Appendix A 

also requires the Hg analyzer to be capable of reading Hg concentrations as high as the MPC.

Comment 15: Commenter 18023 states that section 3.1.7 requires the span value to be set to 

approximately twice the concentration corresponding to the emission standard and alternatively 

rounding the span value to the next highest interval of 10. According to the commenter, based on the 

emission limit stated in the current draft rule, this would restrict the span value to either 2 μg/m3 or 10 

μg/m3. Commenter recommends that they should be allowed to set the span value anywhere between 2 

and 10 μg/m3 as long as that range falls within acceptable limitations of the NIST traceable calibrator. 

The commenter states that the EPA also proposes that the full-scale range should be set to include the 

MPC. According to the commenter, the EPA should allow the full-scale range to be set at one number 

(10), and perform quality assurance testing over a lower portion of that range (0- 5). The commenter 

also states that 40 CFR part 75 has an annual requirement for the majority of analyzer readings to be 

between 20 and 80 percent of full-scale, which should not apply to Hg. 

Response to Comment 15: In the final rule, greater flexibility in setting the span value is provided; the 

span value (μg/m3) is twice the Hg concentration corresponding to the emissions standard, rounded to 

either the next highest integer, the next highest multiple of 5 μg/m3, or the next highest multiple of 10 

μg/m3. For certain existing units, the estimated Hg concentration corresponding to the standard is about 

1.5 μg/m3. Therefore, the span value could be set to either 2.0, 5.0, or 10.0 μg/m3. If the span value is set 

at 5.0 μg/m3, the required QA tests (i.e., daily calibrations, linearity checks and system integrity checks) 

will be performed in the 0-5 μg/m3portion of the measurement scale (as suggested by the commenter). 

Then, provided that the analyzer is capable of reading Hg concentrations as high as the MPC, the span 

and range requirements of sections 3.2.1.4.1 through 3.2.1.4.3 of Appendix A will be satisfied. The final 

rule does not require the majority of the Hg concentration data to be within 20 to 80% of the analyzer’s 

full-scale range.

Comment 16: Commenter 17821 opposes the requirement under section 3.2.3.3. to set the span for a 

CO2 monitor at a value of 1.25 times the maximum potential value for these flue gas components. 

According to the commenter, typically, a coal-fired source has a maximum potential CO2 concentration 

of approximately 14 percent in the flue gas, and 1.25 times 14 is only 17.5%. The commenter states that 

other regulations, such as 40 CFR 60 and 40 CFR 75, require the span of a CO2 monitor to be set at 20 

percent. According to the commenter, the difference between these established rules and this proposal 

results in a conflict of span settings which would require sources to either install and operate a separate 

CO2 monitor for compliance with these proposed rules, or conduct a separate span calibration check on 

an existing CO2 monitor in order to comply with all applicable requirements. Commenter encourages the 

EPA to define a span of 20 percent for CO2 monitors used for compliance with these proposed rules. 

Response to Comment 16: The final rule does not include the requirement to set the CO2 monitor span 

at 1.25 times the MPC. Section 63.10010(b) requires that all diluent gas monitors used to provide data 

under Subpart UUUUU must meet the requirements of 40 CFR part 75. Part 75 span values for CO2 or 

O2 monitors are therefore acceptable for Subpart UUUUU and there is no conflict between the 
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regulations. Essentially all coal-fired utility units already have certified part 75 CO2 or O2 monitors in 

place to meet Acid Rain Program requirements. 

Comment 17: Commenters 17821 and 17881 object to the requirement at section 7.2.5.1 to submit 

quarterly Hg monitoring data. According to the commenters, this rule is not based on a cap-and-trade 

program but on compliance with emission limitations and structured around excess emissions and 

deviation reporting. The commenters opine that under those types of compliance programs, there is no 

need for sources to submit hourly monitoring data, along with the other data that is required by this 

section and later subsections. Commenter 17881 states that the EPA does not justify the requirement to 

electronically submit data under section 7.2.4. 

Response to Comment 17: The EPA disagrees. These provisions provide extremely useful compliance 

oversight information regardless of whether compliance is market-based or emission limit based. With 

the existing structures built around Part 75 reporting for these sources, reporting these data through the 

ECMPS mechanism is an efficient means of ensuring these records are maintained and available for 

review. Having an hourly record of unit operating time, measured emissions, and monitor outages 

provides added assurance the emission limits are being met. Electronic audits can be performed to verify

that the 30-day rolling average emission rates are being calculated correctly nationwide.

Comment 18: Commenter 18449 states that the Appendix A Performance Specification appears to 

replace PS-12A in this MACT but not in the other recently prepared MACT rules. According to the 

commenter, the previous PS-12A document had been created with considerable input from many

sources and had undergone several revisions, has worked well for the last 6 years, and required only

minor corrections. The commenter states that this new document is an attempt to reconcile some old Part 

60 concepts with the second generation CEMS performance specs of the PS series, and in particular 

combines PS-12A, PS-12B and Procedure 5. According to the commenter, Appendix A mingles Hg 

monitor performance requirements, which are a function of the continuous Hg monitor, with higher level 

Hg reporting requirements, which are implemented as higher level functions of the DAS. 

Response to Comment 18: The commenter is correct that Appendix A of this rule contains the Hg 

CEMS and sorbent trap system requirements for Hg monitoring for this rule; the rule does not reference 

or rely on PS-12A. In addition, Appendix A contains specific recordkeeping and reporting requirements 

for Hg monitoring data to support entry of the data into ECMPS. 

In particular, the final rule requires all CEMS data to be submitted to EPA using the ECMPS Client 

Tool. The Hg monitoring requirements in Appendix A, which closely resemble the provisions of the 

vacated CAMR regulation, have been retained in the final rule. Certification and on-going QA 

provisions like those in Appendix A went through public comment during the CAMR rule making, were 

published in Part 75 (but have since been removed), and were designed to be implemented through 

ECMPS. PS 12B is referenced as it is essentially identical to the former Appendix K of Part 75, which 

was to be implemented through ECMPS under CAMR. 

Comment 19: Commenter 18449 states that the requirement to report readings of either CO2 of O2, on 

any constant basis is unnecessary. The commenter states that Hg monitors (or any other pollutant 

monitor) always report concentrations, either volumetrically (ppm, ppb) or m/v basis (ug/m3). Most 

CEMS are diluting and report on a wet basis. According to the commenter, the emission limits are given 

as a mass emission limit per unit of plant activity, and the correction of the pollutant output 

concentration to a specific CO2 or O2 concentration does not in any way facilitate this calculation but

adds unnecessary variables that will increase the uncertainty and calculation error. The commenter states 
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that corrected (CO2 or O2) pollutant concentrations are not used in any of the subsequent mass emissions 

calculations being proposed by the EPA for concentration based Hg analyzers.

The commenter states that stack velocities determined using pitot tubes or other measurement devices 

are not measured on a constant O2 basis. Thus, according to the commenter, the stack volumes would 

need to be recalculated on a 7 percent O2 basis in order to allow calculation of the mass emission rate. 

The commenter states that the sorbent trap reference method does not report concentrations on a 7 

percent O2 basis and that thus both the reference and CEMS values would have to be corrected to 7 

percent O2. According to the commenter, if the Hg CEMS intrinsically produces a concentration 

corrected to 7 percent CO2, these results must be back corrected to yield an as-is value to allow 

comparison. This is a needless step that complicates matters and introduces errors. The commenter states 

that most existing CEMS do not have an O2 monitor. According to the commenter, it is unnecessary and 

punitive to require the addition of an O2 monitor to a Hg CEM, which will reduce reliability and 

accuracy of the overall system. According to the commenter, all commercially available dilution-based 

Hg CEMS analyzers are capable of directly determining their own dilution ratio by injecting Hg 

calibration gas at various points within the system, which means that the use of CO2 or O2 as a dilution 

ratio check is not required. 

Response to Comment 19: The commenter appears to be objecting to the use of diluent gas, flow rate, 

and other parametric measurements to convert Hg concentrations to the units of the emission standards. 

If so, his comments are misdirected. He purports to be commenting on Appendix A, but is actually

objecting to the units of the emission standards, which EPA has no intention of revising at this time. In 

order to express a measured Hg concentration in units of lb/TBtu, an equation from EPA Method 19 is 

used. The Method 19 equations all contain a diluent gas concentration term and some of them require 

corrections for the stack gas moisture content. The commenter’s assertion that an O2 monitor is required 

in incorrect; the final rule allows the diluent monitor to measure either O2 or CO2. Finally, if you elect to 

(or are required to) demonstrate compliance with an electrical output-based Hg limit, a diluent monitor 

is not required at all---only a flow monitor is needed in that case.

Comment 20: Commenter 18449 states that under the RATA testing section 4.1.1.5 the procedure 

should require only that the CEMS and reference results be converted and compared to each other on a 

consistent basis. According to the commenter, the reference method does not report on a diluents basis 

and Hg analyzers will not report on this basis, and thus any requirement to correct to some reference 

CO2 (or O2) basis needlessly complicates the RA testing. 

Response to Comment 20: The EPA agrees with the commenter that for the purposes of this rule, the 

Hg monitor should be assessed on the basis of how accurately it measures Hg concentrations. Therefore 

the RATAs must be done on a concentration basis, comparing the μg/m3readings from the reference 

method to the μg/m3readings from the monitor. This is clearly stated in sections 4.1.1.5.2 and 4.1.2.4 of 

Appendix A.

Comment 21: Commenter 19114 states that the EPA appears to have overlooked many of the issues that 

were resolved in the earlier CAMR rulemaking process. The commenter attached its 2005 CAMR 

comments to further address issues that had previously been addressed in the previous CAMR 

rulemaking. Some issues identified by the commenter include:

 According to the commenter, the proposed rule does not address the handling of negative values. 

The commenter recommends that negative values be rounded to zero and use an associated code 

to indicate the change, which the commenter states is similar to how Part 75 handles negative 
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data. According to the commenter, if instrument drift and allowable calibration error tolerances 

are included, it is possible to be within the analysis tolerance and read a legitimate negative 

value.

 Commenter recommends the use of part 72 definitions for CO2 and flow range determination and 

the definition for zero gas because, according to the commenter, part 72 is more accurate and 

provides harmonization between the two rules.

 Commenter recommends an additional option be available for measuring moisture. According to 

the commenter, if the stack is saturated, a source should be able to use temperature, absolute 

pressure, and a psychrometric chart to measure moisture. The commenter states that temperature 

and pressure transmitters can be calibrated with NIST traceable equipment, and a RATA could 

be performed but would be unnecessary. According to the commenter, during periods when the 

stack is not saturated, default factors listed in the rule could be used.

Response to Comment 21: Regarding the three issues raised by the commenter: 

1. This issue can be handled through the ECMPS Reporting Instructions. There is a Method of 

Determination Code (MODC) in Part 75 (i.e., MODC “21”in §75.57, Table 4a) that addresses the 

handling of negative values. The EPA will instruct sources to use MODC 21 and report zero Hg 

concentration when a negative value is read by a CEMS that is not out-of-control.

2. There are no definitions for “CO2 and flow range determination” or for “zero gas” in 40 CFR Part 72. 

The closest thing to either of these terms is the definition of “zero air material” in section 72.2 In view 

of the confusion of terms and incorrect rule citations, EPA is unable to provide a meaningful response to 

this comment.

3. The final rule allows the “additional option” for measuring moisture described by the commenter. In 

cases where the Hg emissions calculations require corrections for moisture, affected sources must 

account for the stack gas moisture content in accordance with 40 CFR 75.11. The affected source may

either: (a) install and certify a continuous moisture monitoring system; (b) use an applicable fuelspecific default moisture value provided in §75.11(b); or (c) petition the Administrator for permission to 

use a site-specific default moisture value. One of the allowable Part 75 continuous moisture monitoring 

systems under option “(a)” consists of a temperature sensor and a psychrometric chart, and applies only

to saturated gas streams. 

Comment 22: Commenter 18023 states that with respect to section 3.2.3.1 Heat Input-Based Emission 

Limits, when Hg and the diluents (CO2 or O2) are measured on different bases (i.e., one wet and the 

other dry), stack moisture would need to be accounted for. If, however, they are measured on the same 

basis, asserts the commenter, a stack moisture monitoring system would not be required. 

Response to Comment 22: The commenter’s statement is true, but the EPA sees no need to make any

changes to the rule text. Section 3.2.3.1 of Appendix A clearly states that “in some cases” stack gas 

moisture content must be considered. The need for moisture correction (or lack thereof) depends entirely

on which Method 19 equation is used to calculate the Hg emission rate. The selected Method 19 

equation, in turn, depends upon the measurement basis (wet or dry) of the pollutant and diluent gas 

species. Therefore, it will be obvious to the affected sources if and when moisture corrections are 

needed.

Comment 23: Commenter 17881 states that the requirements of section 63.10010 for main and bypass 

stacks conflict directly with those in Appendix A (section 2.4.2 of Appendix A allows installation of a 
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CEMS on the main stack and the use of maximum potential Hg concentration whenever the bypass stack 

is utilized). The commenter states that EGUs with multiple stack or duct configurations are addressed in 

section 63.10010(a)(5). The commenter appreciates the flexibility afforded in this paragraph but opines 

that the EPA should specify the method used to merge the multiple stacks or duct values into a single 

value which could then be compared to the emission limit. According to the commenter, in the absence 

of such guidance, it could be construed that each monitoring location must independently show 

compliance with the applicable EGU emission limits, and this could result in situations of seeming noncompliance. The commenter questions whether, for example, if Hg monitoring is conducted in A and B 

ducts associated with a single EGU and one duct monitor shows a compliance value (75% of the limit) 

while the other duct monitor does not (105% of the limit), compliance actually would be assessed and 

whether the two duct values should simply be averaged arithmetically, in a flow weighted manner, etc.

Response to Comment 23: For a unit with multiple parallel control devices with multiple stacks or 

ducts where all stacks or ducts are monitored, section 63.10010(a)(6) of the final rule states that the 

pollutant emission rate for the unit must be calculated, weighted by stack gas volumetric flow rate, 

where the weighted average emission rate is calculated according to section 63.10010(a)(6). 

Comment 24: Commenter 17881 states that span values for auxiliary measurement systems (i.e., flow 

rate, diluent gas and moisture monitors) in section 3.2.3.3 contain undefined terms such as maximum 

potential flow rate and maximum potential concentration. The commenter notes that these provisions are 

on the surface similar to those found in 40 CFR part 75, albeit without much of the detail necessary to 

implement the provisions (i.e., how is the maximum potential flow rate or maximum potential 

concentration determined). questions the commenter, at a minimum, the span, range and maximum 

potential flow rate/concentration provisions of 40 CFR part 75, Appendix A should be allowed, and it 

may be prudent to abandon the details contained in section 3.2.3.3 and simply refer to the associated 40 

CFR part 75 provisions. 

Response to Comment 24: The EPA agrees with the commenter’s recommendation to dispense with the 

details in section 3.2.3. The final rule simply requires all of the additional monitoring systems needed to 

convert Hg concentrations to the units of the standards to meet the requirements of 40 CFR part 75. This 

approach is appropriate, since ECMPS will be used to receive and process the CEMS data that are used 

to assess compliance with the Hg emission limits under subpart UUUUU. 

Comment 25: Commenter 17881 states that the cycle time test provisions of part 75, Appendix A, 

section 6.4 allow a change of < 6% of the average reading over a 6-minute period to define a stable 

reading when conducting the cycle time test and that this provision should also be allowed in section 

4.1.1.4 of Appendix A. 

Response to Comment 25: In the final rule, the additional text suggested by the commenter has been 

added to the cycle time test procedure in section 4.1.1.4 of Appendix A.

Comment 26: Commenter 18449 states that span ranges will be difficult since pollutants are not 

expected to vary over a wide concentration (during normal operation as compared to startup). 

Commenter 18449 suggests the EPA update the span wording in PS-12A and Appendix A, where it 

allows 10 ug and multiples of 10 ug; commenter 18449 states that multiples of 10 ug doesn’t work for 

very low Hg values as in Utility MACT, where a span range of 5 ug/m3 might be more appropriate. 

Commenter 18449 states that each defined span range requires a set of two different gases (Hg- and 

Hg2+), each at three different concentrations (20-30 percent, 50-60 percent, and 80-100 percent of 

span), which is a problem for both suppliers and NIST, and suggests the number of spans be minimized. 
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Commenter 18449 states that utility MACT spans should be fixed at 5, 10, 20, and 40 ug/m3. 

(Commenter 18449 states that Cement MACT spans should not be available in increments of 10 ug but 

should be spaced much farther apart, such as 100, 180, 260, etc. Commenter 18449 states the wording 

should be clarified so that users can choose such ranges, rather than forced to nearest multiple of 10.)

Commenter 18449 states that CAMR also required Hg calibration gases be traceable to NIST, however, 

NIST at that time had no idea how to certify Hg generators or calibration gases and had to develop the 

methodology, procedure, and processes, with no protocols in place until well after the start of the 

program, so that the EPA was forced to defer the NIST traceability requirement for a year. Commenter 

18449 notes that the EPA and NIST still have a number of current issues, for which NIST will require 

external funding, and identified these issues as follows:

1. Measure and certify lower level elemental concentrations. According to the commenter, currently

NIST can only certify concentrations down to 0.5 μg/m3, and this value has a very high uncertainty of 

6.1 percent (Prob_95 percent). The commenter states that NIST will have to be able to certify points at 

20-30 percent of the lowest span value that the EPA envisions; for example, a 0.25 μg/m3 certified 

concentration would be needed for lower span ranges.

2. Measure and certify high elemental concentrations (100 to 260 μg/m3). The commenter states that this 

is required for the Cement MACT rather than this rule, but it’s included here since it has to be done.

3. Measure mercury chloride generators. According to the commenter, currently there is a 9 percent 

discrepancy between NIST traceable elemental calibrators and NIST traceable ionic evaporative 

calibrators, and the reason for this is unknown. The commenter states that if NIST could accurately 

measure the output of evaporative calibrators, this difference could be explained. According to the 

commenter, the current Interim Oxidized Protocol deems a generator to be certified if all inputs are 

NIST traceable. The commenter states that this approach can remain, but the ability of NIST to confirm 

the output of even a single test ionic generator would increase confidence that the various types of 

generators all yield identical output concentrations.

4. Improve “routine” elemental certifications. The commenter states that certifications of elemental 

calibrators by NIST over the range 0.5 to 38 μg/m3 have been “routine” for several years, but it recently

took three separate attempts with NIST and over one year for the commenter to have a pair of calibrators 

correctly certified over this range. The commenter states that the high levels were correct, but the low 

concentrations were off by up to 12 percent, and if legislation been in place, this delay would have 

caused enormous problems.

5. The EPA Interim Traceability Protocols currently state: “For CEMS applications, this protocol applies 

only to Hg monitoring system span values greater than or equal to 5.0 micrograms per cubic meter 

(μg/m3)” According to the commenter, this must be changed if the EPA envisions span values of less 

than 5 μg/m3 will be required under the new legislation. The commenter states that rovided that NIST 

can provide lower uncertainties for lower concentrations for elemental generators, the commenter does 

not see any reason why the interim protocols will not work at the lower concentrations needed for a 2 

μg/m3 span range.

6. Vapor pressure of mercury. The commenter states that there is a 7 – 9 percent difference between two 

proposed mercury vapor equations. According to the commenter, these equations are used to predict the 

output concentration of saturated vapor elemental mercury generators running at a specific temperature; 

one equation has been in use for decades and been experimentally verified on an ongoing basis, even by
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the NIST Gas Metrology Group, and the other, recently proposed by another group within NIST 

(Boulder Colorado) predicts a mercury concentration in saturated vapor 7 to 9 percent higher but as 

viewed as “theoretically correct”. The commenter states that although the EPA’s Interim Elemental 

Mercury Traceability Protocol neatly sidesteps this issue, it has worldwide implications for the accuracy

of all measurements of mercury in air or other gases.

Response to Comment 26: The EPA disagrees that fixed span values should be specified in PS-12A or 

Appendix A; however, in the final rule, the EPA has revised Appendix A, which includes the Hg 

monitoring requirements specific to this rule, to enable greater flexibility when identifying an 

appropriate span value. The Appendix A requirements provide for identifying a potential span value 

(based on a level two times the Hg concentration equivalent to the emission limit), but also provides 

options for rounding the span value to either the next highest integer, the next highest multiple of 5, or 

the next highest multiple of 10. In regard to Item 1, the EPA disagrees that NIST will have to be able to 

certify elemental Hg concentrations less than 0.5 μg/m3at this time. No span values (i.e., a span value 

less than 5 μg/m3) that would require certified elemental Hg concentrations less than 0.5 μg/m3 are 

required by the final rule. The EPA does, however, encourage the development and use of lower span 

ranges (that meet Appendix A), where appropriate. If a span value is chosen that requires the use of 

certified elemental Hg concentrations less than 0.5 μg/m3, NIST would be capable of conducting 

certifications at this level, though as far as the EPA is aware NIST has not yet conducted certifications at 

these low levels. Regarding Item 2, the EPA agrees that higher level elemental Hg calibration gas 

concentrations are needed for potential future regulatory requirements independent of this rule. The EPA 

has worked with NIST to expand the range of NIST elemental Hg reference concentrations that can be 

certified and certified elemental Hg concentrations ranging from 0.5 μg/m3to 300 μg/m3are now 

available. Concerning Item 3, the EPA agrees that NIST possessing an ability to accurately measure the 

output of evaporative mercuric chloride generators is desired; however, in the absence of this capability, 

the current Interim Traceability Protocol for certifying oxidized Hg gas generators is accepted as the 

appropriate methodology for establishing NIST traceability for mercuric chloride. Moreover, this 

approach reflects significant effort on the part of the EPA, the CEMS vendor community, and affected 

sources to examine the calibration generator traceability issues, and devise an agreed upon approach for 

addressing those issues. For Item 4, it is the EPA’s understanding that NIST currently performs 

elemental Hg gas generator certifications on a routine basis and the EPA is unaware of any problems in 

this regard. The EPA disagrees with the assertion in Item 5 that the EPA must revise the Interim 

Traceability Protocol; span values less than 5 μg/m3are not required by this rule and as a result, changes 

to the Interim Traceability Protocols are not necessary for implementation of the rule. The EPA does 

agree with the commenter that the EPA Interim Traceability Protocols are suitable for lower elemental 

Hg concentrations such as those associated with a 2 μg/m3 span range. In fact, NIST and at least one 

vendor are capable of certifying elemental Hg generators at concentrations as low as 0.5 μg/m

3

, so the 

EPA will consider modifying the protocol at a later time. Finally, regarding Item 6, while the EPA is 

aware that there is a 7 to 9% difference between two Hg vapor equations used by the scientific 

community, the EPA’s application of NIST traceability for elemental Hg is empirically based upon an 

unbroken chain of comparisons anchored to an accepted, NIST elemental reference gas which is 

independent of these theoretical Hg vapor equations.

Comment 27: Commenter 18449 states that span ranges will be difficult since pollutants are not 

expected to vary over a wide concentration (during normal operation as compared to startup). 

Commenter 18449 suggests the EPA update the span wording in PS-12A and Appendix A, where it 

allows 10 ug and multiples of 10 ug; commenter 18449 states that multiples of 10 ug doesn’t work for 

very low Hg values as in Utility MACT, where a span range of 5 ug/m3 might be more appropriate. 

Commenter 18449 states that each defined span range requires a set of two different gases (Hg- and 
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Hg2+), each at three different concentrations (20-30%, 50-60%, and 80-100% of span), which is a 

problem for both suppliers and NIST, and suggests the number of spans be minimized. Commenter 

18449 states that utility MACT spans should be fixed at 5, 10, 20, and 40 ug/m3. (Commenter 18449 

states that Cement MACT spans should not be available in increments of 10 ug but should be spaced 

much farther apart, such as 100, 180, 260, etc. Commenter 18449 states the wording should be clarified 

so that users can choose such ranges, rather than forced to nearest multiple of 10.)

Commenter 18449 states that CAMR also required Hg calibration gases be traceable to NIST, however, 

NIST at that time had no idea how to certify Hg generators or calibration gases and had to develop the 

methodology, procedure, and processes, with no protocols in place until well after the start of the 

program, so that the EPA was forced to defer the NIST traceability requirement for a year. Commenter 

18449 notes that the EPA and NIST still have a number of current issues, for which NIST will require 

external funding, and identified these issues as follows:

1. Measure and certify lower level elemental concentrations. Currently NIST can only certify

concentrations down to 0.5 μg/m3, and this value has a very high uncertainty of 6.1 percent (Prob_95 

percent). NIST will have to be able to certify points at 20-30 percent of the lowest span value that the 

EPA envisions. For example, a 0.25 μg/m3 certified concentration would be needed for lower span 

ranges.

2. Measure and certify high elemental concentrations (100 to 260 μg/m3). This is required for the 

Cement MACT rather than this rule, but it’s included here since it has to be done.

3. Measure mercury chloride generators. Currently there is a 9 percent discrepancy between NIST 

traceable elemental calibrators and NIST traceable ionic evaporative calibrators. The reason for this is 

unknown. If NIST could accurately measure the output of evaporative calibrators, this difference could 

be explained. The current Interim Oxidized Protocol deems a generator to be certified if all inputs are 

NIST traceable. This approach can remain, but the ability of NIST to confirm the output of even a single 

test ionic generator would increase confidence that the various types of generators all yield identical 

output concentrations.

4. Improve “routine” elemental certifications. Certifications of elemental calibrators by NIST over the 

range 0.5 to 38 μg/m3 have been “routine” for several years. However, it recently took three separate 

attempts with NIST and over one year for the commenter to have a pair of calibrators correctly certified 

over this range. The high levels were correct, but the low concentrations were off by up to 12 percent. 

Had legislation been in place, this delay would have caused enormous problems.

5. The EPA Interim Traceability Protocols currently state: “For CEMS applications, this protocol applies 

only to Hg monitoring system span values greater than or equal to 5.0 micrograms per cubic meter 

(μg/m3)” This must be changed if the EPA envisions span values of less than 5 μg/m3 will be required 

under the new legislation. Provided that NIST can provide lower uncertainties for lower concentrations 

for elemental generators, the commenter does not see any reason why the interim protocols will not 

work at the lower concentrations needed for a 2 μg/m3 span range.

6. Vapor pressure of mercury. There is a 7 – 9 percent difference between two proposed mercury vapor 

equations. These equations are used to predict the output concentration of saturated vapor elemental 

mercury generators running at a specific temperature. One equation has been in use for decades and 

been experimentally verified on an ongoing basis, even by the NIST Gas Metrology Group. The other, 

recently proposed by another group within NIST (Boulder Colorado) predicts a mercury concentration 
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in saturated vapor 7 to 9 percent higher but as viewed as “theoretically correct”. Although the EPA’s 

Interim Elemental Mercury Traceability Protocol neatly sidesteps this issue, it has worldwide 

implications for the accuracy of all measurements of mercury in air or other gases.

Response to Comment 27: The EPA disagrees that fixed span values should be specified in PS-12A or 

Appendix A; however, in the final rule, the EPA has revised Appendix A, which includes the Hg 

monitoring requirements specific to this rule, to enable greater flexibility when identifying an 

appropriate span value. The Appendix A requirements provide for identifying a potential span value 

(based on a level two times the Hg concentration equivalent to the emission limit), but also provides 

options for rounding the span value to either the next highest integer, the next highest multiple of 5, or 

the next highest multiple of 10. In regard to Item 1, the EPA disagrees that NIST will have to be able to 

certify elemental Hg concentrations less than 0.5 μg/m3at this time. No span values (i.e., a span value 

less than 5 μg/m3) that would require certified elemental Hg concentrations less than 0.5 μg/m3 are 

required by the final rule. The EPA does, however, encourage the development and use of lower span 

ranges (that meet Appendix A), where appropriate. If a span value is chosen that requires the use of 

certified elemental Hg concentrations less than 0.5 μg/m3, NIST would be capable of conducting 

certifications at this level, though as far as EPA is aware NIST has not yet conducted certifications at 

these low levels. Regarding Item 2, the EPA agrees that higher level elemental Hg calibration gas 

concentrations are needed for potential future regulatory requirements independent of this rule. The EPA 

has worked with NIST to expand the range of NIST elemental Hg reference concentrations that can be 

certified and certified elemental Hg concentrations ranging from 0.5 μg/m3to 300 μg/m3are now 

available. Concerning Item 3, the EPA agrees that NIST possessing an ability to accurately measure the 

output of evaporative mercuric chloride generators is desired; however, in the absence of this capability, 

the current Interim Traceability Protocol for certifying oxidized mercury gas generators is accepted as 

the appropriate methodology for establishing NIST traceability for mercuric chloride. Moreover, this 

approach reflects significant effort on the part of the EPA, the CEMS vendor community, and affected 

sources to examine the calibration generator traceability issues, and devise an agreed upon approach for 

addressing those issues. For Item 4, it is the EPA’s understanding that NIST currently performs 

elemental Hg gas generator certifications on a routine basis and the EPA is unaware of any problems in 

this regard. The EPA disagrees with the assertion in Item 5 that the EPA must revise the Interim 

Traceability Protocol; span values less than 5 μg/m3are not required by this rule and as a result, changes 

to the Interim Traceability Protocols are not necessary for implementation of the rule. The EPA does 

agree with the commenter that the EPA Interim Traceability Protocols are suitable for lower elemental 

Hg concentrations such as those associated with a 2 μg/m3 span range. In fact, NIST and at least one 

vendor are capable of certifying elemental Hg generators at concentrations as low as 0.5 μg/m3, so the 

EPA will consider modifying the protocol at a later time. Finally, regarding Item 6, while the EPA is 

aware that there is a 7 to 9% difference between two mercury vapor equations used by the scientific 

community, the EPA’s application of NIST traceability for elemental Hg is empirically based upon an 

unbroken chain of comparisons anchored to an accepted, NIST elemental reference gas which is 

independent of these theoretical mercury vapor equations.
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5A07a - Testing/Monitoring: Application of PM CEMS

Commenters: 17197, 17383, 17402, 17621, 17623, 17638, 17655, 17675, 17677, 17681, 17689, 17696, 

17702, 17704, 17705, 17711, 17714, 17716, 17725, 17728, 17729, 17730, 17737, 17740, 17747, 17752, 

17754, 17756, 17758, 17761, 17774, 17775, 17790, 17795, 17796, 17798, 17800, 17801, 17808, 17812, 

17813, 17818, 17820, 17821, 17868, 17871, 17881, 17886, 17912, 17913, 17914, 17975, 18014, 18428, 

18443, 18447, 18498, 18831, 18935, 18963, 19033, 19114, 19120, 19121, 19536, 19537, 19538, 18023

1. Support of use of PM CEMS during startup and shutdown.

Comment 1: Commenter 17975 supports the proposed requirement to use PM CEMS on EGUs that 

elect to comply with the PM filterable limit as a surrogate for non-Hg metals because PM CEMS are an 

EPA approved monitoring method, and in use at an increasing number of plants. The commenter

believes that the EPA needs to make the final rule clear that PM CEMS must be operated around the 

clock, including during startup, shutdown, maintenance, and malfunctions, when PM emissions may be 

at their peak. The commenter refers to an “expert’s” conversations with several PM CEMS vendors that 

indicate these monitors can be calibrated to accurately measure PM at very high concentrations that 

occur during startup and shutdown. 

Response to Comment 1: The final rule clarifies that the operating limit monitoring for the PM and 

HAP metals emission limits requires use of a PM CPMS, not PM CEMS, and work practice standards 

that include operation of monitoring, not emissions limits, during periods of startup or shutdown. The 

final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM 

emission limit if the source elects to use this approach (see the final preamble for further discussion).

2. Recommendations to use PM CEMS as indicator/CAM.

Comment 2: Multiple commenters (17705, 17725, 17716, 17820, 17886, 18014, 18498) suggest that 

the final rule use PM CEMS data as an indicator of PM control performance, but not to enforce a 

numeric PM limit, and that alternatively, sources could also demonstrate a reasonable assurance of 

compliance based on opacity or parametric monitoring as the EPA has already proposed under other 

rules. 

Comment 3: Several commenters (17623, 17638, 17681, 17676, 17775, 17886) suggest using PM 

CEMS within a MACT monitoring program modeled after the part 64 CAM program. 

Comment 4: Several commenters (17402, 17716, 17737, 17775, 17886) believe current PM CEMS

technology is useful as a compliance assurance monitoring tool that can trigger requirements for 

investigation and corrective action. 

Comment 5: Several commenters (17402, 17681, 17716, 17737, 17775) note successful implementation 

the CAM rule under 40 CFR part 64 and request that the final rule adopt this approach for continuous 

monitoring. Commenter 17402 suggests that CAM plans could include opacity monitoring, a sitespecific utility MACT compliance plan, and periodic stack testing. 

Response to Comments 2 - 5: The final rule requires the use of a PM CPMS for an operational limit 

and does not enforce a numeric PM limit when this monitoring approach is used. In the final rule 

facilities would be allowed to petition the Administrator under section 63.8(f) of subpart A of part 63 for 

an alternative to use opacity or parametric monitoring at a specific site in lieu of required monitoring in 
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the final rule. The final rule also does provide for the use of a PM CEMS to determine compliance with 

the filterable PM emission limit if the source elects to use this approach (see the final preamble for 

further discussion).

3. Requests for clarification on establishment of PM CEMS operating limits.

Comment 6: Commenter 17729 requests clarification that the rule requires using the filterable PM 

measurement to set an ongoing 30-day rolling average operational limit with compliance based on a 

filterable PM CEMS. 

Response to Comment 6: The final rule requires the use of a PM CPMS for an operational limit and 

does not enforce a numeric PM limit. The PM CPMS is required to report measurements in raw data 

output from the monitor and not a correlation to manual filterable PM measurements. The final rule also 

does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit 

if the source elects to use this approach (see the final preamble for further discussion).

Comment 7: Commenter 17881 states that it is not clear if section 63.10011(b)(3) applies to units with 

PM CEMS. Commenter notes that for a unit complying via the use of PM CEMS, it is not clear if “nonHg HAP metals” refers to the aggregate of all regulated HAP metals or each of the individual HAP

metals. According to the commenter, it seems like this provision must be based on all metals in 

aggregate, or it would be impractical to implement. 

Response to Comment 7: The final rule requires the use of a PM CPMS for an operational limit and 

does not enforce a numeric PM limit. The final rule also does provide for the use of a PM CEMS to 

determine compliance with the filterable PM emission limit if the source elects to use this approach (see 

the final preamble for further discussion). The source has the option to measure non-Hg HAP metals 

with a reference method each quarter. The monitoring and testing that is required will depend on which 

emission limit the source elects.

Comment 8: Several commenters (17730, 17868, 18023) state that proposed reliance on total PM as a 

surrogate for the non-Hg HAP metals, and the use of the PM CEMS to conduct performance testing and 

measure ongoing compliance is poorly defined. Commenters (17800, 18023) state that the provisions in 

Table 4 (“highest 1-hour average”) are inconsistent with the provisions in proposed section 63.10011(d) 

for determining the filterable PM operating limit. According to commenter 17730, the proposal requires 

that when sources conduct the initial performance test, they must develop a filterable PM emission limit 

based on a compliant stack test using Method 5 and Method 202, but the proposal fails to provide any

further explanation of how sources are supposed to derive the filterable PM limit, or whether or not 

sources are also required to comply with the individual HAP metals emission standards. The commenter

believes that there are several calculations that could be used to determine a filterable PM limit based on 

stack test results but that the exact calculation is not specified in the proposal. The commenter

characterizes this portion of the proposal as “essentially establishing a surrogate for measuring a 

surrogate” and “simply nonsensical.” The commenter believes it is unreasonable for the EPA to seek 

comment on such a poorly defined proposal, and the commenter believes that if the agency continues to 

pursue the total PM standard as a surrogate for non-Hg HAP metals, the agency should make clear the 

methodology for establishing the filterable PM limit and re-propose the rule for public comment because 

the commenter cannot effectively provide comment without further definition. 

Response to Comment 8: We are no longer requiring use of a PM CEMS for a PM limit. We are 

requiring the use of a PM CPMS for an established operational limit. The source has the option to 
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measure non-Hg HAP metals with a reference method each quarter. The final rule also does provide for 

the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source 

elects to use this approach (see the final preamble for further discussion).

Comment 9: Several commenters (17754, 17800,18963, 18023) state that the owner/operator must 

“[m]aintain the PM concentration (mg/dscm) at or below the highest 1-hour average measured during 

the most recent performance test demonstrating compliance with the total PM emissions limitation,”. 

and that proposed section 63.10011 directs that the operating limit for PM should be based on the 

average of the PM filterable results of the three Method 5 performance test runs, whereas Table 4 

provides that the PM limit shall be the highest 1-hour average measured during the most recent 

performance test. According to the commenters, these two relevant provisions appear to reflect 

inconsistent analyses and compliance demonstration periods and therefore should be clarified in order to 

avoid potential confusion, misinterpretation, and/or inconsistent application. The commenters request 

that the proposed rule be clarified to expressly provide that the operating limit for demonstrating 

continuous compliance with the emission standard for total PM shall be based on the highest 1-

hour average measured during the most recent performance test, in accordance with Table 4 of the 

proposed rule. The commenters state that consistent with this approach, if the total PM emissions from 

an affected EGU exceed the previously-established operating limit during any period, the 

owner/operator of such unit would have the option of conducting another performance test, and the 

highest average value measured during such test would become the new applicable operating limit for 

the relevant unit. 

Response to Comment 9: Under the final rule, you may elect to comply with an optional operating 

limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM 

CPMS and establish the operating limit during the initial compliance test for filterable PM, total nonmercury HAP metals, or individual non-mercury HAP metals (or HAP metals inclusive of mercury for 

liquid oil-fired units). The operating limit for demonstrating continuous shall be based on the highest 1-

hour average measured during the most recent performance test. If you use a PM CPMS and associated 

operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and reestablish the operating limit during each performance test. A PM CPMS does not need to meet the 

requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS 

to determine compliance with the filterable PM emission limit if the source elects to use this approach 

(see the final preamble for further discussion).

Comment 10: Commenter 17871 states that the EPA has failed to demonstrate that a functional 

relationship between filterable particulates and condensable particulates in EGU’s. According to the 

commenter, this approach becomes unworkable when one considers the rule requires annual testing 

resulting in new standard for non-Hg metallic HAP every year. The commenter notes that under the 

proposed rule, the use of SO2 as a surrogate for acid gas HAP is appropriate because the EPA has 

correctly noted that “the technologies used for removal of acid gases are primarily those that are also 

used for FGD” (76 FR 25023). The commenter states that SO2 would be measured with a CEMS 

certified and operated in accordance with part 75. According to the commenter, even though proven 

technology and quality assured emission data is used to demonstrate compliance with the standard, a 

“second MACT standard” has been created that requires that the sorbent injection rate be maintained at 

or above the lowest 1-hour average sorbent flow rate measured during the most recent performance test. 

Commenters 17871 and 17740 state that by setting up compliance in this manner, the emission standard 

becomes the basis for an operating limit, which in turn becomes another, far more stringent, standard of 

compliance that a facility would be required to meet on a continuous basis. According to the 
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commenters, this is inconsistent with the purpose of an emission standard, which allows for fluctuations 

in emissions over a 30-day period and improperly imposes two MACT standards on sources. 

Response to Comment 10: The comments are inapplicable, as the final rule no longer contains a 

condensable PM emissions limit and, for those source owners or operators who choose to use SO2

CEMS, no operating limit exists and no parameter monitoring is required.

Comment 11: Commenter 17623 states that the total PM standard is unclear and impracticable because 

it will be difficult for sources to plan for changes to the limits resulting from performance testing. 

According to the commenter, the PM limit of 0.030 lb/MMBtu for existing sources would be adjusted 

downward based on the PM emission rate measured by the reference method during each periodic 

performance test. The commenter believes that there are two possible interpretations of the proposed 

rule that would result in this downward adjustment.

1. According to the commenter, one interpretation would require the PM limit to be adjusted down 

based on the proportion of Total PM emissions that are condensable. The commenter states that if, 

for example, 50 percent of the total PM emissions are condensable at a particular unit, then the 

applicable PM CEMS limit for that unit would be reduced to 0.015 lb/MMBtu.

2. According to the commenter, the other interpretation would require the PM limit to be set at the 

actual filterable PM emissions rate measured during the initial and subsequent PM performance tests 

conducted for the unit. The commenter states that under either approach, the conversion of the total 

PM numeric rate limit into a filterable PM standard that a PM CEMS can monitor will require 

sources to readjust their compliance level after each performance test.

Response to Comment 11: Under the final rule, you may elect to comply with an optional operating 

limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM 

CPMS and establish the operating limit during the initial compliance test for filterable PM, total nonmercury HAP metals, or individual non-mercury HAP metals (or HAP metals inclusive of mercury for 

liquid oil-fired units). The operating limit for demonstrating continuous shall be based on the highest 1-

hour average measured during the most recent performance test. If you use a PM CPMS and associated 

operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and reestablish the operating limit during each performance test. A PM CPMS does not need to meet the 

requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS 

to determine compliance with the filterable PM emission limit if the source elects to use this approach 

(see the final preamble for further discussion).

Comment 12: Commenter 17795 states that there is conflicting language in the proposal. According to 

the commenter, pages 25029-25030 indicate that ESP and fabric filter parameter monitoring is required 

for all units not using HCl CEMS, but the language from page 25031 states that parameter monitoring is 

required only if units are not using PM CEMS. According to the commenter, fabric filter BLDS and ESP 

voltage limit monitoring requirements should apply only to units that do not use PM CEMS as stated on 

page 25031. The commenter believes this was the EPA’s intent, as there is no justification or further 

assurance of compliance for the monitoring of particulate control equipment operational parameters 

when direct continuous monitoring of filterable PM is implemented. According to the commenter, the 

EPA should clarify that it did not intend to make ESP voltage and fabric filter BLDS readings an 

operational limit if a unit uses a PM CEMS to demonstrate compliance. 

Response to Comment 12: Control equipment parameters are not monitored under the final rule, so this 

concern is moot.
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4. Concerns with using PM CEMS data to determine compliance with non-Hg metals standard.

Comment 13: Commenter 17621 states that the merits of including condensable PM in the total PM

limit are difficult to evaluate, as no test data are available for the exact condensable PM method that is 

required for compliance with the proposed MACT limits. The commenter states that the ICR required 

condensable PM to be measured using OTM-28, which method was changed significantly before it was 

promulgated in 2010 as revised Method 202. According to the commenter, most ICR test contractors 

used OTM-28, a few used the original Method 202, and because none of the ICR tests used revised 

Method 202, the conclusions of EPRI’s evaluation of condensable PM method usefulness are uncertain. 

According to the commenter, adding a condensable PM measurement to the filterable PM sampling train 

increases the total variability and reduces the sensitivity of the combined measurement system. The 

commenter states that a recent field study conducted by American Electric Power (AEP) and EPRI

found that Method 202 (condensable PM) had much higher variability than Method 5 (filterable PM) for 

replicate test runs (EPRI, 2011) and that in the ICR Part III tests at coal-fired EGUs, the relative 

standard deviations (RSDs) of condensable PM test series averaged slightly higher than the RSDs of 

filterable PM test series (24 percent compared to 20 percent). According to the commenter, the detection 

limit of a combined Method 5/Method 202 sampling train is twice as high as that of a Method 5 train 

alone, as each gravimetric measurement adds uncertainty to the total.

Moreover, according to the commenter, the accuracy of the new Method 202 has not been demonstrated 

adequately and requires additional research. The commenter states that laboratory studies conducted by

EPRI pointed to a potential negative bias in OTM-28, which did not effectively capture SO3 (EPRI, 

2009)., and that only about half of the SO3 introduced into the sampling train was captured. According 

to the commenter, this finding indicates that Method 202 may not be accurate under flue gas conditions 

that are expected to be increasingly prevalent in power plants as wet FGD systems (which tend to 

produce SO3) are added. 

The commenter states that a total PM limit is problematic for compliance monitoring, as continuous PM 

monitors measure only filterable PM. According to the commenter, since condensable PM emissions are 

a product of the coal sulfur content and other factors (e.g., ash properties, SCR SO2 oxidation rate), it is 

not clear how a power plant would determine compliance with the total PM limit without being able to 

monitor both filterable PM and condensable PM on a continuous basis. The commenter asserts that the 

difficulty of demonstrating and achieving compliance with total PM limits will depend on the percentage 

of total PM that is condensable PM and how variable the ratio of filterable PM to condensable PM is 

over time. Commenter states that (in document; Figure 2-2 is histogram of condensable PM as a 

percentage of total PM: Part III ICR Coal-fired EGUs) the fraction of total PM that is condensable PM

varies from under 1 percent to over 99 percent across the coal-fired EGUs tested in the ICR. According 

to the commenter, the ICR database does not contain sufficient historical condensable PM data to 

determine how much condensable PM emissions will change at a unit over time. 

Finally, the commenter states that EPRI’s study has implications for how representative the ICR data are 

of industry emissions, as well as for future performance testing. The commenter states that the EPA 

based the MACT floor for total PM on the lowest test series for each EGU, regardless of the method 

used to measure filterable PM (Method 5, Method 29, or OTM-27). According to the commenter, as 

many of the lowest ICR emissions are from Method 29 tests run at 320 °F, those results will not be 

representative of tests made using Method 5 at 250 °F, and as a result, there is considerable uncertainty 

regarding the true emissions of filterable PM from the power industry. The commenter states that the 

compliance method for filterable PM specified in the proposed rule is Method 5, while the ICR test data 

include filterable PM results from Methods 5, 29, and OTM-27. According to the commenter, to 
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eliminate the various method biases identified in the EPRI/AEP study, the requirement to run Method 5 

tests at 320 °F should also apply to Method 29 metals tests, and there should be a requirement to use 

nonreactive filters.

Comment 14: Commenter 18429 states that the unit-by-unit, single test approach in setting a MACT

limit proposed by the EPA is inappropriate. The commenter notes that an example of the difficulty in 

meeting a PM operational limit is one of the commenter’s units equipped with a wet scrubber, SCR, and 

ESP for emissions controls. According to the commenter, when following the stack test that would 

establish the filterable PM operational limit, the unit’s PM CEMS consistently recorded 30-day averages 

above that level, because the initial filterable PM level was measured while the boiler was operating in a 

steady-state, full load condition over a brief period of only hours, and the PM CEMS then measures 

filterable PM levels continuously during all load and operating conditions. According to the commenter, 

the EPA’s proposed approach punishes good behavior and is a setup for failure. The commenter

encourages the EPA to replace a total PM with a category-wide, filterable PM limit that is achievable 

under the variety of conditions that utility units experience. The commenter further notes the comments 

submitted by EPRI in this docket provide detailed analysis justifying the use of filterable PM as an 

adequate surrogate for all non-Hg metals. The commenter states that among the key conclusions are that 

filterable PM is correlated to emissions of particulate-phase metals (e.g., chromium) and there is a 

statistically significant correlation with metals that are volatile at stack gas temperature, particularly Hg 

and selenium. 

Comment 15: Commenter 17197 believes the proposed PM CEMS operating limit determination 

method is unworkable, arbitrary, likely overly restrictive, and non-representative. The commenter

believes the better solution is replacing the proposed total PM limit with a filterable-only PM limit for 

non-Hg HAP metals using PM CEMS, however the commenter offers an alternative. Commenter

recommends instead that the surrogate PM CEMS operating limit (filterable PM) be established by using 

the simultaneous EPA Method 5 and Method 202 stack testing results to establish the EGU’s filterableto-total PM ratio. According to the commenter, the PM CEMS operating limit (filterable PM) would be 

appropriately set by adjusting the total PM limits (0.030 lb/MMBtu or 0.30 lb/MWh) using the 

filterable-to-total PM percentage established during the three 1-hour test run performance testing. The 

commenter states that for example, if the measured filterable-to-total PM factor was 0.5, the PM CEMS

operating limits (filterable PM) would be set at 50 percent of the total PM Limits (0.015 lb/MMBtu or 

0.15 lb/MWh). According to the commenter, setting the PM CEMS operating limit using this alternate 

methodology is more representative because it utilizes all three performance test runs and not just the 

highest 1-hour average measured EPA Method 5 rate. The commenter asserts that this methodology is 

less dependent on short-term PM control system performance, since it is based on the established 

filterable-to-total PM ratio, and is less arbitrary since the resulting PM CEMS operating limits have 

some equivalence to the underlying total PM limit. 

Comment 16: Several commenters (17623, 17677, 17681, 17730, 17775, 18023) believe that it is 

problematic to use PM CEMS data to determine compliance with a total PM limit because PM CEMS

only measure filterable particulate. Commenters (17623, 17775) states that the technology used to 

establish the total PM limit and to perform periodic stack tests that re-set the “floating” PM CEMS

operating limit use significantly different technology. Commenter 17775 states that the proposal does 

not indicate that the agency considered how the permissible PS-11 measurement error might impact 

compliance determinations. Commenter 17677 is concerned that the PM CEMS operating limit appears 

to be an enforceable requirement treated as equivalent to the total PM limit despite the fact that the PM 

CEMS limit reflects only a fraction of the total non-Hg metals being emitted during the performance 

test. Commenter 17677 believes that setting an enforceable limit on a surrogate seems refutable during 
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enforcement proceedings. Several commenters (17623, 17677, 17681) suggest requiring another stack 

test for total PM within 60 days of exceeding the PM CEMS operating limit rather than deeming the 

source out of compliance with the HAP emissions limit. Commenters (17676, 18023) believe that annual 

compliance tests are sufficient to ensure compliance. 

Comment 17: Several commenters (17689, 17704, 17813, 18014) state that the proposed PM total 

approach is unworkable for several reasons. According to the commenters, Methods 5 and 202 would be 

utilized to determine the condensable and filterable portions of PM total, with PM CEMS measurements 

used to set unit operating limits afterwards, but Method 5 does not and cannot account for variations in 

PM filterable actual levels over a range of unit operating levels, including startup and shutdown, that a 

PM CEMS would measure, so, in effect, Method 5 measurements when compared to PM CEMS

measurements over full unit operating conditions is not appropriate. Several commenters (17689, 17702, 

17704, 17813) state that the PM standard should be based on a PM filterable limit only.

Comment 18: Commenter 17737 states that PM CEMS provide an indirect measure by “correlating” the 

monitor’s response to short term stack tests (e.g., Method 5 tests) conducted over a range of 

concentrations that must be sufficient to include the level of the applicable emission standard. 

Commenter provides an analysis by UARG that indicates that a PM CEMS meeting the criteria in PS 11 

can produce responses that differ significantly (on the order of 25 percent) from what would be obtained 

with Method 5. (See, e.g., UARG Comments, EPA-HQ-OAR-2002-0058-2880 at 51-54; EPA-HQOAR- 2005-0031-0246, at 3-10). According to the commenter, for example, if the filterable PM limit is 

set at 0.030 lb/MMBtu and the Method 5 test result is 0.028 lb/MMBtu, emissions would be compliant 

with the filterable PM limit, but with the allowed measurement error of 25%, the PM CEMS could 

present a PM level of 0.035 lb/MMBtu and thus demonstrated false exceedance of the PM limit where 

the true PM level should have be in compliance. 

Response to Comments 13 - 18: The final rule no longer requires monitoring with a PM CEMS. Under 

the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to 

demonstrate continuous compliance, you must install a PM CPMS and establish the operating limit 

during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Comment 19: Commenter 17737 states that they conduct Method 5 performance tests each year, and 

the results of those tests have varied as much as 80 percent for a given unit. According to the 

commenter, the EPA provides no data or explanation as to how this operating limit might address this 

variability in operating conditions that are certain to occur. According to the commenter, this is likely

because the three-run average of a stack test conducted during 1 day at constant operating conditions, 

essentially represents a single point measurement, which by its very nature cannot provide any 

indication of variability. Several commenters (17737, 17790, 18014) state that use of the EPA’s 

proposed method of setting the operating limit would leave compliance with that limit completely to 

chance (i.e., dependant on the performance test results), and utilities would not know what their 
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operating limit was until compliance with that standard was in effect, leaving no opportunity to prepare 

for the standard. The commenters note that the EPA must modify its standard to allow units to comply. 

Response to Comment 19: Under the final rule sources are allowed to establish different operating 

limits monitored with a PM CPMS if they believe there is variability due to varying load conditions. The 

final rule no longer requires monitoring with a PM CEMS. The final rule also does provide for the use of 

a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use 

this approach (see the final preamble for further discussion).

Comment 20: Commenter 17711 states that PM CEMS measure only filterable PM yet the EPA 

proposes that the operating limit for facilities using PM CEMS is the highest 1-hour average 

concentration in mg/dscm measured during the most recent performance test. According to the 

commenter, the EPA is setting an artificially low PM standard for units using PM CEMS. The 

commenter states that the compliance method should match the standard; the EPA should either set 

filterable PM emission limits or establish more appropriate operating limits for sources using PM CEMS

(e.g., the total PM limit minus the amount of condensable PM measured during the last performance 

test). 

Response to Comment 20: Under the final rule, you may elect to comply with an optional operating 

limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM 

CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg

HAP metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg for liquid oil-fired 

units). The operating limit for demonstrating continuous shall be based on the highest 1-hour average 

measured during the most recent performance test. If you use a PM CPMS and associated operating 

limit, you must conduct the applicable Method 5 or Method 29 test once annually and re-establish the 

operating limit during each performance test. A PM CPMS does not need to meet the requirements for a 

PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit if the source elects to use this approach (see the final 

preamble for further discussion).

Comment 21: Commenter 19120 states that the establishment of an operating limit makes the 0.030 

lb/MMBtu limit on total PM arbitrary. According to the commenter, for example, if the emissions rate 

during stack testing for total PM is well below 0.030, exceedance of the filterable PM operating limit 

would not be an indication that the actual emissions limit of 0.030 lb/MMBtu was exceeded or even 

approached. The commenter recommends that the EPA base the operating limit on a more representative 

value than simply basing it on the value achieved during the stack test and notes that while section 

63.10011(d) indicates that the operating limit will be based on the average of the PM filterable results of 

the three Method 5 performance test results, Table 4 indicates that the operating limit will be based on 

the highest 1-hr average measured during the test.

Response to Comment 21: Under the final rule, you may elect to comply with an optional operating 

limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM

CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg

HAP metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg for liquid oil-fired 

units). Under the final rule sources are allowed to establish different operating limits monitored with a 

PM CPMS if they believe there is variability due to varying load conditions. The final rule no longer 

requires monitoring with a PM CEMS. The final rule also does provide for the use of a PM CEMS to 

determine compliance with the filterable PM emission limit if the source elects to use this approach (see 

the final preamble for further discussion).
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Comment 22: Several commenters (17402, 17775, 17790) support use of PM as a surrogate for non-Hg 

HAP metals. Other commenters (17402, 17675, 17716) request that the agency not require regulated 

units to install and use PM CEMS as the continuous compliance determination method. Several 

commenters (17402, 17716, 17775) support inclusion of PM CEMS as one option among others for an 

appropriate filterable PM limit, provided the EPA has considered and addressed all of the issues 

associated with use of PM CEMS for that purpose. Commenter 17402 states that including PM CEMS

as an option would be consistent with recent revisions to NSPS Subpart Da. However, the following 

commenters do not believe that the proposal accounts for the following issues relevant to the use of PM 

CEMS as a direct indicator of compliance following periodic performance tests:

1. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17737, 17752, 17775, 17790,

17868, 18023) note the inaccuracy of PM CEMS at low concentrations;

2. Multiple commenters (17402, 17716, 17728, 17737, 17752, 17775, 17790, 17868, 17886, 18014, 

18023) state there is a lack of data correlating PM CEMS response with actual emissions during 

startup and shutdown and across load ranges. Commenters (17775, 17737) state that the proposal’s 

explanations (that the proposed limits were achievable during periods of startup and shutdown based 

on use of a 30-day averaging period and assumptions regarding the use of cleaner fuels) were not 

substantiated with data;

3. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17775, 17868, 18023) are 

concerned about the PM CEMS allowed measurement error (i.e., high degree of uncertainty within 

PS-11 tolerance interval);

4. Multiple commenters (17402, 17716, 17728, 17737, 17752, 17775, 18023) note the differences in 

measurement methods or conditions that can affect monitor calibration;

5. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17775, 17790, 17868, 18023) 

question the achievability of PS 11 performance criteria at the low emission limits proposed. In

particular, commenter 17775 provides an analysis by a consultant that indicates the PM CEMS are 

not a viable compliance option and alleges that proposed PM limits are so low that existing PM 

CEMS technologies cannot pass PS-11 criteria;

6. Commenters 17737 and 17775 claim there is a lack of compliance provisions allowing the 

operational flexibility necessary to develop strong PM CEMS correlations to the reference method

7. Several commenters (17696, 17737, 17752, 17775, 18023) question the long-term reliability of PM 

CEMS and long-term stability of measurement responses of current PM CEMS technologies

8. Commenter 17868 notes the lack of alternate limits for PM, SO2, HCl, and Hg during periods of PS11 testing;

9. Commenter 18023 states there is a lack of NIST traceable PM daily calibration standards:

10. Commenters 18023 and 17790 state the use of PM CEMS is cumbersome, expensive, and includes 

highly variable calibration procedures.

Response to Comment 22: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). The operating limit for demonstrating continuous shall be 

based on the highest 1-hour average measured during the most recent performance test. If you use a PM 

CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once 

annually and re-establish the operating limit during each performance test. A PM CPMS does not need 

to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion).
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Comment 23: Commenter 17737 states that the EPA should establish a separate standard for periods of 

startup and shutdown. According to the commenter, however, if the EPA promulgates a rule that 

requires use of PM CEMS as a compliance method during periods of startup and shutdown, the EPA 

cannot simply assume that averaging time or differences in fuel will compensate for these period. 

Response to Comment 23: The comment is moot, as the rule no longer has emissions limits applicable 

during periods of startup or shutdown.

Comment 24: Commenter 17800 states that the EPA should revise the compliance procedures for the 

non-Hg metals standard. Commenter believes that the EPA’s proposed compliance procedures for the 

total PM standard are not workable because the EPA does not clearly describe how compliance would 

be determined or how the proposed site-specific limit would be established or how the limit would 

apply. Commenter is opposed to a site-specific limit. The commenter states that a PM standard should 

apply consistently for all affected sources and compliance must be established that accurately represents 

the actual emissions from the source and test methods should be clarified and not combine different 

testing and measurement components. 

Response to Comment 24: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). The operating limit for demonstrating continuous shall be 

based on the highest 1-hour average measured during the most recent performance test. If you use a PM 

CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once 

annually and re-establish the operating limit during each performance test. A PM CPMS does not need 

to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion).

The establishment of an operational limit is described in the final rule and is applied the same for all 

sources, thus representing the operation of control equipment for all affected sources.

Comment 25: Commenter 17820 states that the EPA should designate filterable PM and not total PM as 

a surrogate for the non-Hg metals standards. According to the commenter, however, if total PM is 

retained the EPA should allow an alternative option to determine a unit-specific filterable PM limit and 

the EPA should extend the option to use filterable PM as a surrogate for metals to oil units and to allow 

compliance demonstrations through the use of CEMS. 

Response to Comment 25: The rule has a filterable, not total, PM emissions limit.

Comment 26: Commenters 17812 and 17821 state that given the variability in testing and coal 

properties, the requirement to maintain PM concentration at or below the highest 1-hour average 

measured during the most recent performance test as proposed imposes a de facto unjustified reduction 

in emission limit on those units using a PM CEMS. Commenter 17821 recommends deleting the 

requirement in its entirety. 

Response to Comment 26: Under the final rule sources are allowed to establish different operating 

limits monitored with a PM CPMS if they believe there is variability due to varying load conditions. The 

final rule no longer requires monitoring with a PM CEMS. The final rule also does provide for the use of 
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a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use 

this approach (see the final preamble for further discussion).

5. Compliance costs if PM CEMS are not appropriate monitors for non-Hg HAP metals.

Comment 27: Commenters 17728 and 17775 state that if PM CEMS are not a realistic option for 

monitoring PM as a surrogate, then the EPA must reconsider its assumptions that most sources will opt 

to use PM as a surrogate, and should seriously consider the reasonableness and cost of the non-Hg HAP

metals testing option, including the impact of control device parametric monitoring options. 

Response to Comment 27: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). If the PM CPMS option is not chosen, then sources are 

required to perform quarterly testing to show compliance. The final rule also does provide for the use of 

a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use 

this approach (see the final preamble for further discussion).

6. Concerns about the commercial readiness of PM CEMS.

Comment 28: Commenter 17818 states that it is their understanding that continuous PM monitoring 

systems (PM CEMS) have been in operation for a number of years in other countries, and that a number 

of PM monitors have been in operation in the U.S. for several years as a result of applicable state 

requirements. According to the commenter, there are a number of commercially available continuous 

PM monitoring technologies that are capable of meeting the EPA requirements. The commenter states 

that information from the ICAC indicates that they have prepared a guidance document to help potential 

purchasers of PM CEMS to prepare a bid specification for the solicitation of bids from particulate 

monitor suppliers. Commenter agrees with the EPA that PM CEMS are commercially available and are 

reasonable monitoring options for coal- and oil-fired units. It is the commenter’s opinion that PM CEMS

are appropriate systems for monitoring compliance with the applicable provisions of the proposed rule. 

Response to Comment 28: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). If the PM CPMS option is not chosen, then sources are 

required to perform quarterly testing to show compliance. The final rule also does provide for the use of 

a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use 

this approach (see the final preamble for further discussion).

Comment 29: Commenter 17796 supports the use of Hg CEMS but does not believe the use of PM 

CEMS is supportable. According to the commenter, the EPA supports the “feasibility” of the PM CEMS

by pointing to few facilities which have installed CEMS and to the Performance Specifications for 

evaluating compliance under 40 CFR Part 60. According to the commenter, there is no rigorous 

demonstration that PM CEMs are feasible for general application, such as the process it went through to 

finalize the Method 201/202 filterable and condensable particulate forms which it finalized in January of 

2011. The commenter reviewed the Supporting & Related Material portion of the Docket for the PM 

CEMS program and in over 3000 documents only found four that clearly dealt with PM CEMS, from 
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two facilities in Ohio and that simply reported the hourly measurements. The docket should show more 

examples of facilities using PM CEMS and also the QA steps necessary for good data. According to the 

commenter, the docket also needs to show that the PM CEMS equipment will be readily available and 

also be able to be installed and troubleshot in a timely manner. The commenter states that a similar 

process with public input must be followed by the EPA to assure that information gathered from the 

CEMS is valid and, more important to state agencies, that such information can be relied upon to 

enforce in case of non-compliance.

Commenter 17796 also notes that the EPA’s proposal to use CEMS as an option for PM compliance 

only affects the filterable portion of the PM and relies on the concept that the condensable portion will 

be addressed though the demonstration of “equivalency” between the CEMS and the stack testing during 

the initial compliance tests. According to the commenter this is a very tenuous position to rely upon to 

assure compliance with the total PM limits. The commenter notes that the New York SDEC has a 

longstanding policy of requiring that the condensable portion of PM emissions be addressed in the 

permitting process since this portion of the PM emissions are critical for the mitigation of health effects 

associated with PM2.5. Thus, the commenter believes the PM CEMS approach is not adequately rigorous 

to assure enforceability of the limits, nor allows for the necessary assurance of reducing PM levels to 

address PM2.5 emissions. Finally, the commenter still has many questions as to reliability of PM CEMS

and how much experience with this equipment exists. The commenter states that the preamble stated 

“several electric utility companies in the U.S. have now installed or are planning to install PM CEMs. 

The commenter questions how many different types of EGUs have PM CEMS (broken down by unit 

configuration and fuel type). Finally the commenter notes that the costs of PM CEMS are equivalent to 

installing a Hg CEMS which is also required unless the source owner goes with sorbent traps which are 

estimated to have less upfront costs but higher annualized costs. 

Response to Comment 29: Under the final rule, you may elect to comply with an optional operating 

limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM 

CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg 

HAP metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg for liquid oil-fired 

units). The operating limit for demonstrating continuous shall be based on the highest 1-hour average 

measured during the most recent performance test. If you use a PM CPMS and associated operating 

limit, you must conduct the applicable Method 5 or Method 29 test once annually and re-establish the 

operating limit during each performance test. A PM CPMS does not need to meet the requirements for a 

PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit if the source elects to use this approach (see the final 

preamble for further discussion).

Although PM CEMS is not required for compliance in the final rule, some of these comments indicate a 

general concern that PM CEMS are not an adequately demonstrated technology. The EPA disagrees. PM 

CEMS have been demonstrated for a variety of applications. PM CEMS performance specifications and 

QA procedures have been around quite a while with PS-11 and Procedure 2 promulgated January 2004. 

There have been at least 65 successful installations in the United States and in other countries. A 

successful installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby 

demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in obtaining a 

reliable successful correlation with reference methods, thereby ensuring compliance data that is 

sufficient to determine compliance with PM emission limits. Procedure 2 describes the required audits to 

insure that subsequent measurements are stable and within acceptable limits, thereby ensuring reliable 

compliance data.
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Comment 30: Commenter 17621 notes that there are almost 70 PM CEMS operating on EGUs in the 

U.S. Over 40 are installed on wet stacks (following FGD systems). According to the commenter, PS-11 

requires a minimum of 15 Method 5 test runs to develop a calibration curve for the CEMS and as a 

practical matter, the lowest point on the calibration curve is the normal operating point of the CEMS. 

According to the commenter, the only way to expand the operating range is to de-tune the power plant 

control equipment to provide up-scale readings to the instrument while conducting the Method 5 manual 

testing. The commenter states that while this approach has been demonstrated with some success on dry

stacks by de-tuning the ESP, it has not been attempted on units equipped with fabric filters. The 

commenter asserts that wet stack applications present further challenges, since de-tuning an ESP 

upstream of a wet FGD has less effect on the outlet emissions and increases the risk of producing offspecification gypsum. According to the commenter, in these cases, the calibration curve for the PM 

CEMS consists of the normal operating point and an artificial zero.

According to the commenter there is not a lot of documentation available on the installed PM CEMS

equipment; however, all of the systems now installed on wet stacks have indicated some plugging 

problems. The commenter asserts that usually this has been handled by frequent cleaning of the probes. 

The commenter states that the experience at an EPRI demonstration project has shown similar issues, 

with some systems working better than others. According to the commenter, all of the vendors continue 

to make improvements and try alternatives. The commenter states that dry stack systems fare better, 

especially where cross-stack installations are possible, though one particular model had problems with 

data loss due to sunlight interference at the height of the day.

According to the commenter, the sensitivity of the PM CEMS is limited by the lowest filterable PM 

emission that can be accurately and precisely measured by Method 5. The commenter states that in EPRI

sponsored PS-11 testing, the lowest range of PM emissions used for calibration was 2 to 5 milligrams 

per cubic meter (mg/m3), approximately 0.002 to 0.005 lb/MMBtu. According to the commenter, this 

level of sensitivity is adequate to measure filterable PM at the proposed total PM limits for existing coalfired EGUs (0.03 lb/MMBtu), but may not be sensitive enough to measure at the proposed total PM

limit for new coal-fired EGUs (approximately 0.005 lb/MMBtu). Commenter notes that while a lower 

detection limit for Method 5 can be obtained by extending the sampling time, longer sampling times will 

increase the time required to conduct the full 15 runs required by PS-11. 

Response to Comment 30: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Comment 31: Commenter 19033 is unaware of any PM CEMS that can measure both filterable and 

condensable PM. The commenter has PM CEMS on three industrial boilers that it owns and operates 

and they operate at a temperature of approximately 320 oF, in order to prevent water droplet 

interference. According to the commenter, if the EPA intends that a PM CEMS be used to assure 
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compliance with the PM limit in Table 2, it needs to amend Table 2 to specify that the PM limit is 

filterable PM, not total. The commenter states that in that manner, output from a PM CEMS, coupled 

with the required part 75 flow and diluent monitors, can be used to provide PM emissions on a lb/mm 

Btu basis. According to the commenter the EPA seems to be trying to control condensable PM by

specifying that the PM emission limit be on a total, rather than-filterable basis. The commenter states 

that wet scrubber technology will provide condensable PM removal, in addition to acid gas removal, and 

there is thus no need for the EPA to regulate condensable PM as part of this regulation with a specific 

emission limit. 

Response to Comment 31: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Comment 32: Commenter 17790 states that the accuracy of a PM CEMS should be considered when 

setting an emission limit. The commenter states that establishing the “accuracy” of the PM CEMS is 

accomplished by conducting a three-level Method 5 test but that unlike gaseous monitors (e.g., SO2 or 

NOX CEMS), PM CEMS are not capable of routine calibration checks using calibration gases. 

According to the commenter, the variability at low PM levels and insufficiency of frequent accuracy

checks may impact the reliability and accuracy of the PM monitors reading over time and provide a false 

indication of compliance or non-compliance with a PM emission limit. Also according to the 

commenter, PS- 11 certification requirements require de-tuning of PM control devices, without a 

corresponding relief from current emission limitations and reporting requirements.

Response to Comment 32: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Although PM CEMS are not required under the final rule, we believe that PM CEMS with a successful 

correlation using PS-11, with the 95% confidence levels, will assure that the PM CEMS would have the 

necessary certainty as a compliance monitor. Most all successful correlations achieve much tighter 

statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 describes the 
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required audits to insure that subsequent measurements are stable and within acceptable limits, thereby

ensuring reliable compliance data.

Comment 33: Commenter 17790 states that the EPA must allow the use of Method 5B to demonstrate 

compliance with PM limits. The commenter states that Method 5B is allowed for sources calibrating PM 

CEMs under PS-11. According to the commenter, the method was developed for sources using wet 

scrubbers and is routinely allowed for compliance stack tests. The commenter states that the EPA did 

modify some of the requirements in Method 5 (filter temperature) which are consistent with Method 5B

objectives and thus should allow the complete use of the method. 

Response to Comment 33: PM CEMS are no longer required under the final rule. Method 5 is the 

reference compliance method in the final rule for the annual PM compliance test. The final rule also 

does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit 

if the source elects to use this approach (see the final preamble for further discussion).

Comment 34: Commenter 17790 states that there is insufficient reliability in PM CEMS to give 

accurate data for EGUs with low PM emissions (i.e., EGUs with FGD). The commenter states that its 

Monroe Power Plant is currently hosting an EPRI PM CEMS Demonstration Project. According to the 

commenter, the commenter’s experience so far suggests that PM CEMS may not be reliable and 

accurate monitors of stack gas particulates; the project has accumulated limited run time, with substandard performance such as plugged monitors and extended down time.

Response to Comment 34: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Although PM CEMS are no longer required under the final rule, section 2.4 of PS-11 stresses the 

importance of planning for the specific effluent matrix and/or PM that might influence the correlation 

and describes the process required to enhance the probability of obtaining a successful correlation and 

the selection of the most appropriate CEMS for the installation. We believe that PM CEMS with a 

successful correlation using PS-11, with the 95% confidence levels, will assure that the PM CEMS 

would have the necessary certainty as a compliance monitor. Most all successful correlations achieve 

much tighter statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 

describes the required audits to insure that subsequent measurements are stable and within acceptable 

limits, thereby ensuring reliable compliance data.

Comment 35: Several commenters (17681, 17638, 18831) disagree with using PM CEMS for 

compliance for the following reasons. According to the commenters:

1. The commenters believe PM CEMS have not proven to be reliable for the electric utility industry,
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2. The instruments are very expensive,

3. The instruments measure only filterable PM, and

4. The proposal to use a short-term total PM stack test to establish a continuous 30-day filterable limit 

does not take into consideration any variability of the reference test method, fuel supply, the CEMS

itself or unit operations.

For these reasons, commenters request that the EPA require compliance for metals based on an annual 

filterable PM test because EGUs are accustomed to conducting annual PM stack tests for SIP and NSPS

compliance. 

Response to Comment 35: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Although PM CEMS are no longer required under the final rule, the EPA disagrees with the commenters 

that indicate a general concern that PM CEMS are not an adequately reliable technology. PM CEMS 

have been demonstrated for a variety of applications. PM CEMS performance specifications and QA 

procedures have been around quite a while with PS-11 and Procedure 2 promulgated January 2004. 

There have been at least 65 successful installations in the United States and in other countries. A 

successful installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby 

demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in obtaining a 

reliable successful correlation with reference methods, thereby ensuring compliance data that is 

sufficient to determine compliance with PM emission limits. Most all successful correlations achieve 

much tighter statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 

describes the required audits to insure that subsequent measurements are stable and within acceptable 

limits, thereby ensuring reliable compliance data.

Comment 36: Commenter 19197 states that the PM CEMS operating limit is proposed to be set at the 

highest 1-hour average measured rate from the most recent performance test used to demonstrate 

compliance with the total PM emissions limits. According to the commenter, the proposed methodology

is likely non-representative because the time period necessary to perform the total PM performance test 

is relatively short, consisting of three 1- to 2-hour long simultaneous EPA Method 5 and Method 202 

stack tests. According to the commenter, the resultant operating limit is only representative of the 3 to 6 

hour PM control system operating period and consequently, the performance testing time period may not 

represent typical PM control efficiencies. The commenter states that the testing might occur during a 

highly controlled period, resulting in an overly restrictive filterable PM emissions operating limit. The 

commenter offers an example of the potential subjectivity of the proposal. The commenter states that 

during performance testing, hypothetical “Facility A’s” baghouse particulate control system’s 

effectiveness might be very effective and the EPA Method 5 and Method 202 testing show very low 

filterable and total PM emission rates while conversely, hypothetical “Facility B’s” baghouse particulate 
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control effectiveness might be compromised during the EPA Method 5 and Method 202 performance 

testing, barely showing compliance with the total PM limit. According to the commenter, consequently, 

setting the filterable PM CEMS limit as proposed by using the highest 1-hour average measured Method 

5 rate during the performance test will penalize the better performing “Facility A.” The commenter 

states that the PM CEMS limit determination methodology should not encourage operating with 

marginal baghouse control effectiveness during performance testing.

Response to Comment 36: Under the final rule sources are allowed to establish different operating 

limits monitored with a PM CPMS if they believe there is variability due to varying load conditions. The 

final rule no longer requires monitoring with a PM CEMS. The final rule does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion). Sources also may opt for quarterly testing with 

reference methods to determine compliance.

Comment 37: Commenter 17975 states that they have discussed with vendors, the ability of the two 

primary types of PM CEMS (light scattering or beta measurement) to measure high concentrations of 

PM, such as are and would be emitted during SSM events, especially for units with non-energized ESPs

during such events. The commenter states that vendors have assured the commenter that if the 

specifications call for measurements of high concentrations of PM then they can supply the appropriate 

instrument packages. Commenter notes that there is nothing inherently limiting for either of these 

technologies that would preclude their ability to measure high concentrations of PM and the fact that 

reputable vendors confirm this makes it imperative that PM CEMS be required at all times, including 

SSM time periods, when emissions are at their highest, especially for units with ESPs. Commenter

provides a short explanation of both types of CEMS.

Response to Comment 37: As mentioned elsewhere, the comment is moot, for the final rule no longer 

contains emissions limits applicable during startup or shutdown periods. 

Comment 38: Commenter 17696 states that because of bad performance of PM CEMS on two of their 

coal-fired units, they believe it is inappropriate for the EPA to require the use of PM CEMS for 

compliance determinations without a reasonable alternative until reliable PM CEMS are commercially

available. The commenter believes that a reasonable alternative is to require periodic PM emission tests 

when fuels change or when PM CEMS indicate, similar to a part 64 CAM approach. The commenter

believes it is not necessary to require fuel analyses or bimonthly Method 29 stack tests. 

Response to Comment 38: Under the final rule sources are allowed to establish different operating 

limits monitored with a PM CPMS if they believe there is variability due to varying load conditions. The 

final rule no longer requires monitoring with a PM CEMS. The final rule does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion). Sources also may opt for quarterly testing with 

reference methods to determine compliance.

Comment 39: Commenter 17705 states that the agency must address issues with PM CEMS technology

before mandating its use as a compliance methodology because PM CEMS are not yet widely deployed 

across the utility industry and because the agency has made use of PM CEMS optional under 40 CFR

part 60, subparts D and Da. The commenter has no direct experience with PM CEMS but is aware that 

the industry has ongoing concerns and states that the EPA shares at least some of these concerns based 

on text included by the agency in a consent decree that requires a 2-year demonstration period for PM 

CEMS. According to the commenter the language in the consent decree acknowledges that PM CEMS
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technology is still in development. The commenter states that the EPA must also commit to providing a 

simpler and more reliable way to calibrate PM CEMS because PS-11 can be difficult for sources with 

highly efficient PM controls. The commenter states that the PS-11 procedures place source operators at 

risk of exceeding permit limits, and the commenter requests that the EPA provide guidance to permitting 

authorities that it is inappropriate to subject sources to enforcement proceedings when trying to achieve 

the high dust loads required by PS-11. The commenter does not support the proposed alternative to PM 

CEMS of conducting bimonthly Method 29 tests. 

Response to Comment 39: The final rule no longer requires a PM CEMS for compliance monitoring.

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Although PM CEMS are no longer required under the final rule, the EPA disagrees with the commenters 

that indicate a general concern that PM CEMS are not an adequately reliable technology. PM CEMS 

have been demonstrated for a variety of applications. PM CEMS performance specifications and QA 

procedures have been around quite a while with PS-11 and Procedure 2 promulgated January 2004. 

There have been at least 65 successful installations in the United States and in other countries. A 

successful installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby 

demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in obtaining a 

reliable successful correlation with reference methods, thereby ensuring compliance data that is 

sufficient to determine compliance with PM emission limits. Most all successful correlations achieve 

much tighter statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 

describes the required audits to insure that subsequent measurements are stable and within acceptable 

limits, thereby ensuring reliable compliance data.

Comment 40: Multiple commenters (17402, 17681, 17716, 17737, 17758, 17820, 18014) characterize 

PM CEMS as not measuring PM directly, and several commenters (17402, 17758, 18014) state that PM 

CEMS calculate PM emissions based on reference method measurements that depend on the calibration 

procedures and the inherent limitations of the measurement technology. 

Response to Comment 40: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg 

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 
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PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Although PM CEMS are no longer required under the final rule, the EPA disagrees with the commenters 

that indicate a general concern that PM CEMS are not an adequately reliable technology. PM CEMS 

have been demonstrated for a variety of applications. PM CEMS performance specifications and QA 

procedures have been around quite a while with PS-11 and Procedure 2 promulgated January 2004. 

There have been at least 65 successful installations in the United States and in other countries. A 

successful installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby 

demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in obtaining a 

reliable successful correlation with reference methods, thereby ensuring compliance data that is 

sufficient to determine compliance with PM emission limits. Most all successful correlations achieve 

much tighter statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 

describes the required audits to insure that subsequent measurements are stable and within acceptable 

limits, thereby ensuring reliable compliance data.

Comment 41: Multiple commenters (17402, 17716, 17725, 17758, 17790, 17820, 18014, 18498, 

18023) believe that PS-11 creates a significant risk of “false positives” due to instrument error because 

of PS-11’s generous statistical performance criteria. These commenters also express doubts that PM 

CEMS can produce representative measurements over the entire range of boiler operations because 

calibration of the instrument does not occur across all load ranges. According to commenters, these 

periods of operation result in transient flue gas conditions causing changes in particle density, 

morphology, size distribution or stratification of PM within the flue that are not reflected in the 

correlation of the instrument. The commenters believe some of the preceding issues can be addressed in 

the final rule, but the commenters do not think the technology is usable as a direct indicator of 

compliance as proposed. 

Response to Comment 41: Although PM CEMS are no longer required under the final rule, section 2.4 

of PS-11 stresses the importance of planning for the specific effluent matrix and/or PM that might 

influence the correlation and describes the process required to enhance the probability of obtaining a 

successful correlation and the selection of the most appropriate CEMS for the installation. We believe 

that PM CEMS with a successful correlation using PS-11, with the 95% confidence levels, will assure 

that the PM CEMS would have the necessary certainty as a compliance monitor. Most all successful 

correlations achieve much tighter statistical criteria than the minimum allowed under PS-11 and 

Procedure 2. Procedure 2 describes the required audits to insure that subsequent measurements are stable 

and within acceptable limits, thereby ensuring reliable compliance data. Applying a technology suitable 

for a particular application would naturally take some planning. Section 2.4(1) of PS-11 states that you 

should select a PM CEMS that is appropriate for your source. Manufacturers of beta gauge instruments 

have demonstrated that the calibration curve does not change as the fuel mix changes or load changes. 

Vendors have guaranteed that their PM CEMS will meet the PS-11 criteria for multi-fuel boilers. PS-11 

provides for situations where multiple correlations may be needed for a PM CEMS technology (see 

Section 2.3 of PS-11). Based on this information, the final rule does provide for the use of a PM CEMS 

to determine compliance with the filterable PM emission limit if the source elects to use this approach 

(see the final preamble for further discussion).

Comment 42: Several commenters (17402, 17681, 17716, 17740) state that treating PM CEMS as a 

direct indicator of compliance is inappropriate because the EPA’s floor analysis is based on reference 

method data, and the proposed limits do not reflect the underlying uncertainty of the PM CEMS. 
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Response to Comment 42: The final rule no longer requires a PM CEMS for compliance monitoring. 

Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this 

method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating 

limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-Hg

HAP metals (or HAP metals inclusive of Hg for liquid oil-fired units). The operating limit for 

demonstrating continuous shall be based on the highest 1-hour average measured during the most recent 

performance test. If you use a PM CPMS and associated operating limit, you must conduct the 

applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 

The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable 

PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion).

Comment 43: Commenter 17761 states that if emission reductions are mandated, it must be recognized 

that PM CEMS have not been widely deployed and their utilization has been largely limited to 

requirements imposed by the EPA in NSR consent decrees with escape clauses in place. The commenter

submits that there is insufficient experience with PM CEMS being utilized for compliance purposes to 

make them a viable tool to judge compliance with these standards. To the extent that stack testing is an 

alternative, the commenter submits that there is currently a shortage of qualified stack testers. Due to the 

level of precision required when conducting such important compliance tests, the commenter has 

consistently had to waive its procurement guidelines (and pay additional costs) in an effort to obtain 

quality firms that follow proper procedures after having experiences with failed PM stack test results 

that are due to human error. 

Response to Comment 43: Although PM CEMS are no longer required under the final rule, the EPA 

disagrees with the commenters that indicate a general concern that PM CEMS are not an adequately 

reliable technology and are have not been widely deployed. PM CEMS have been demonstrated for a 

variety of applications. PM CEMS performance specifications and QA procedures have been around 

quite a while with PS-11 and Procedure 2 promulgated January 2004. There have been at least 65 

successful installations in the United States and in other countries. A successful installation is obtained 

when a PM CEMS passes the PS-11 statistical criteria, thereby demonstrating that an acceptable level of 

accuracy is achieved. PS-11 provides the steps in obtaining a reliable successful correlation with 

reference methods, thereby ensuring compliance data that is sufficient to determine compliance with PM 

emission limits. Most all successful correlations achieve much tighter statistical criteria than the 

minimum allowed under PS-11 and Procedure 2. Procedure 2 describes the required audits to insure that 

subsequent measurements are stable and within acceptable limits, thereby ensuring reliable compliance 

data.

Comment 44: Commenter 17871 states that PM CEMS are not yet advanced enough to provide reliable 

and accurate data at a reasonable cost. The commenter states that state agencies regularly determine that 

PM CEMS are not reasonably cost-effective monitoring devices-a point with which the EPA has agreed. 

See 70 FR 7908 (Feb. 16, 2005) (justifying the use of COMS because CEMS are “significantly more 

expensive to purchase and maintain than COM ...”). The commenter states that the requirement for PM 

CEMS is particularly problematic for EGUs with very low mass emissions of filterable PM. The 

commenter states that the MACT requires developing a correlation between the PM CEMS and a 

reference method (Method 5) using the PS-11, and this involves conducting 15 correlation runs between 

Method 5 and the PM CEMS over a range of PM concentrations. The commenter asserts that 

considering the inherent lack of precision of Method 5 at low PM concentrations, it will be very difficult 

to demonstrate the correlation coefficient (>0.85) required for the initial site specific certification of the 
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PM CEMS. The commenter also asserts that it is also unclear how a range of PM concentrations can be 

created during performance testing when a fabric filter baghouse is used for particulate control.

Response to Comment 44: Although PM CEMS are no longer required under the final rule, section 2.4 

of PS-11 stresses the importance of planning for the specific effluent matrix and/or PM that might 

influence the correlation and describes the process required to enhance the probability of obtaining a 

successful correlation and the selection of the most appropriate CEMS for the installation. We believe 

that PM CEMS with a successful correlation using PS-11, with the 95% confidence levels, will assure 

that the PM CEMS would have the necessary certainty as a compliance monitor. Most all successful 

correlations achieve much tighter statistical criteria than the minimum allowed under PS-11 and 

Procedure 2. Procedure 2 describes the required audits to insure that subsequent measurements are stable 

and within acceptable limits, thereby ensuring reliable compliance data. Precision of the Method 5 tests 

may be improved by employing paired trains for each run to sort out the imprecise test runs. PS-11 has a 

special correlation coefficient of >0.75 for low-emitting sources and section 8.6 of PS-11 allows sources 

to obtain zero point data to aid in achieving correlation criteria.

Comment 45: Commenter 18447 is concerned about the accuracy and reliability of a PM CEMS and 

under the proposed rule their units would require monthly stack tests that are excessive and expensive. 

Response to Comment 45: Although PM CEMS are no longer required under the final rule, EPA 

disagrees with the commenters who indicate a general concern that PM CEMS are not an adequately 

reliable technology. PM CEMS have been demonstrated for a variety of applications. PM CEMS 

performance specifications and QA procedures have been around quite a while with PS-11 and 

Procedure 2 promulgated January 2004. There have been at least 65 successful installations in the 

United States and in other countries. A successful installation is obtained when a PM CEMS passes the 

PS-11 statistical criteria, thereby demonstrating that an acceptable level of accuracy is achieved. PS-11 

provides the steps in obtaining a reliable successful correlation with reference methods, thereby ensuring 

compliance data that is sufficient to determine compliance with PM emission limits. Most all successful 

correlations achieve much tighter statistical criteria than the minimum allowed under PS-11 and 

Procedure 2. Procedure 2 describes the required audits to insure that subsequent measurements are stable 

and within acceptable limits, thereby ensuring reliable compliance data. Under the final rule we have 

dropped the requirement for monthly stack tests.

Comment 46: Commenter 18935 recommends that the EPA develop a guidance document for 

performance specification testing of PM CEMS that reflects recent experience with current control 

technologies and emission levels. The commenter also suggests that sources be allowed a phase in 

period for PM CEMS, perhaps allowing sources to conduct frequent periodic monitoring by 

conventional reference methods until a PM CEMS is installed. According to the commenter, it has 

assisted clients with the performance specification testing of particulate CEMS and found that many

sources have concerns about varying the process or control equipment conditions to produce three 

varying loads of particulate emissions. The commenter states that sophisticated particulate emission 

control systems perform consistently and reliably when matched to source characteristics – changing 

operations to produce alternate emission levels is not an easy matter. According to the commenter, while 

PS-11 allows for the generation of low level emission data by removing the probe, it is not clear if 

reference method testing using a Method 5, 5I, or 17 sampling train needs to be conducted during the 

same time (if so, these methods are not really designed for ambient particulate monitoring).

Response to Comment 46: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 
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compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-mercury HAP metals, or individual non-Hg HAP metals. The operating 

limit for demonstrating continuous shall be based on the highest 1-hour average measured during the 

most recent performance test. If you use a PM CPMS and associated operating limit, you must conduct 

the applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11.

6. PM CEMS certification issues.

Comment 47: Commenters 17800 and 17914 request clarification on the procedures to be used for 

certification of PM CEMS. In order to certify a PM CEMS using PS-11 procedures, the PM CEMS must 

be correlated using a three point curve with the reference method data. According to the commenters, in 

order to generate the three PM loads required by PS-11 (section 8.6) it is necessary to partially disable 

the particulate control device to increase/decrease the PM mass loading to establish a valid correlation 

curve, but this may not be practical or possible for certain particulate control technologies, as there is no 

way to temporarily, partially disable fabric filters not equipped with flue gas bypass dampers to generate 

higher PM emissions. In addition, state the commenters, state or local regulatory permits may preclude a 

source from operating at PM levels in excess of the permitted levels, and without an exemption, it would 

not be possible to pass the correlation tests in PS-11. Commenter 17914 states that in addition, for IGCC

there is no PM control device since the combustion turbine is burning synthetic gas fuel, and it may not 

be possible to establish an adequate correlation of PM as per PS-11 requirements for certain control 

devices/plant configurations.

Comment 48: Commenter 17801 states that PS-11 requires a correlation with reference method tests 

performed over the full range of the PM CEMS responses that corresponds to the normal operating 

conditions of the source and control device and that due to a lack of post combustion emissions control, 

IGCC syngas-fueled turbines are not able to vary PM emissions to achieve a valid correlation. The 

commenter states that PM spiking is an option (though it hasn’t yet been demonstrated and not 

recommended by GE on a combustion turbine), but these systems are still in development, and may not 

even be appropriate, safe or possible to inject PM into a combustion turbine. Commenter further notes 

that PS-11 requires that the confidence interval (CI) and the Tolerance Interval half range (TI) are both 

calculated as a percent of the emission limit; according to the proposed EGU MACT, the limit would be 

set by the performance testing for initial compliance and filterable PM is a surrogate for non-Hg metal 

HAP, and the particulate limit (which includes condensables) would not apply to the correlation; and 

depending on the results, it may be impossible to meet the specifications using a limit set in this manner. 

Therefore, states the commenter, compliance with the PM limits should be demonstrated via the 

standard PM emissions stack testing methodologies (Methods 5/202). The commenter suggests that 

opacity monitors can be used on a continuous basis as a compliance indicator.

Response to Comments 47 - 48: PM CEMS are no longer required under the final rule. You may elect 

to comply with an optional operating limit for PM. If you use this method to demonstrate continuous

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-mercury HAP metals. The operating 

limit for demonstrating continuous shall be based on the highest 1-hour average measured during the 

most recent performance test. If you use a PM CPMS and associated operating limit, you must conduct 

the applicable Method 5 or Method 29 test once annually and re-establish the operating limit during each 

performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. 
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Although PM CEMS are no longer required under the final rule, there are several things that help with 

obtaining a correlation for a low-emitting source. Precision of the Method 5 tests may be improved by

employing paired trains for each run to sort out the imprecise test runs. PS-11 has a special correlation 

coefficient of >0.75 for low-emitting sources and section 8.6 of PS-11 allows sources to obtain zero 

point data to aid in achieving correlation criteria. We recommend that sources operate their PM CEMS 

over a correlation test planning period of sufficient duration to identify the full range of operating 

conditions and PM emissions to be used in your PM CEMS correlation test to avoid operation in excess 

of the permitted levels. Based on this information, the final rule does provide for the use of a PM CEMS 

to determine compliance with the filterable PM emission limit if the source elects to use this approach 

(see the final preamble for further discussion).

7. Problems with “floating limits.”

Comment 49: Commenters 17623 and 17774 conclude that the operating limits for PM CEMS will be 

“floating limits” in which a facility will be measuring filterable particles with its CEMS, but its actual 

limit is based on the performance testing which measures total PM. According to commenters, as 

proposed, the “floating limits” will create uncertainty in the regulated community and will be 

detrimental to the application of the Utility MACT. In light of the measurement problems caused by a 

total PM limit, one commenter requests that the EPA change the PM surrogate standard from a total PM 

standard to one based only on filterable PM because the commenter believes it will allow for a clearer 

target that will not change as operating conditions change.

Response to Comment 49: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals (or HAP 

metals inclusive of mercury for liquid oil-fired units). The operating limit for demonstrating continuous 

shall be based on the highest 1-hour average measured during the most recent performance test. If you 

use a PM CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 

29 test once annually and re-establish the operating limit during each performance test. A PM CPMS 

does not need to meet the requirements for a PM CEMS under PS 11. The final rule also does provide 

for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source 

elects to use this approach (see the final preamble for further discussion).

Comment 50: Commenters 17714 and 17756 state that under the proposed rule each unit’s operating 

limit is confirmed or reestablished during subsequent performance tests and this could result in 

progressively tighter limits over time based on the unit’s most recent test. Commenters believe it is 

inappropriate and inconsistent with the CAA to tighten a limit based on test results that show lower 

emissions from a previous test. Commenter 17756 states that their experience with PM CEMS data from 

well-controlled units show that compliance with a limit established in this way cannot be maintained on 

a continuous, 30-day rolling average basis and that the proposed total PM limit is unworkable because it 

fails to provide a single, known standard to be met. 

Response to Comment 50: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. If you use this method to demonstrate continuous 

compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). The operating limit for demonstrating continuous shall be 

based on the highest 1-hour average measured during the most recent performance test. If you use a PM 
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CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once 

annually and re-establish the operating limit during each performance test. A PM CPMS does not need 

to meet the requirements for a PM CEMS under PS 11. The establishment of an operational limit is 

described in the final rule and is applied the same for all sources, thus representing the operation of 

control equipment for all affected sources. The final rule also does provide for the use of a PM CEMS to 

determine compliance with the filterable PM emission limit if the source elects to use this approach (see 

the final preamble for further discussion).

Comment 51: Several commenters (17655, 17752, 18023) state that PM CEMS operating limits 

established by unit testing would be unwise and unwarranted because such operating limits could be far 

below the regulatory limit. According to the commenters it is conceivable that an EGU could meet the 

total PM performance test standard by a wide margin (e.g., actual Method 5 results during performance 

test < 0.010 lb PM/MMBtu) but no matter how well the unit performs during performance tests, the 

proposal stipulates that the unit must continue to operate at the same filterable PM emissions rate (as 

determined by PM CEMS) indefinitely. The commenters state that the “operating limit” for filterable 

PM reflects a limit on the only fraction of total PM removed by standard air emission control equipment. 

Commenter 17655 believes that this is a radical departure from past agency standard-setting, which has 

consistently recognized that control equipment performance varies over time, especially in units like 

power generation equipment that must operate for extended periods between maintenance outages. The 

commenter conjectures that the “EPA apparently assumes that condensable PM is both an indeterminate 

and widely varying quantity that has the capability of throwing an affected EGU out of compliance....”

The commenter contends that the agency offers no evidence that the condensable PM fraction can be 

determinative of compliance with the non-Hg metals standard, and the commenter believes that 

condensable PM is instead a relatively fixed increment during normal operation. Based on the 

commenter’s assumption that the condensable PM rate is relatively constant, the commenter

recommends that the condensable PM emission rate (lb condensable PM/MMBtu) measured by the 

reference method in the most recent performance test should be utilized as a constant value in the 

following equation to determine the hourly emission rate in compliance calculations for the 0.03 lb

PM/MMBtu MACT limit for existing sources:

Calculated tPM for comparison to standard= (cPM from most recent performance test) + (fPMfrom PM CEMS or CAM)

Commenter 17655 concludes that the “operating limit” should not be expressed as being equal to the 

filterable PM measured during performance tests, but rather the operating limit for sources subject to the 

total PM limit of 0.03 lb PM/MMBtu should be calculated as follows after each performance test:

Operating Limit = 0.03 lb tPM/MMBtu - cPM from most recent performance test

Comment 52: Commenter 17716 acknowledges that their recommended methodology of determining a 

filterable operating limit (by subtracting the condensable PM measured during the performance test from 

the total PM MACT limit) is not without its own flaws, given the bias and uncertainty associated with 

formation of sulfate and nitrate artifacts in Method 202 (that have nothing to do with metals); however, 

it does introduce a margin for variability into the compliance process that better reflects normal 

operating conditions. Commenters 17716 and 17758 also state that establishing a fixed filterable PM 

operating limit value is necessary for determining the acceptability of the tolerance interval and 

confidence interval results for PS-11. 

Response to Comments 51 - 52: PM CEMS are no longer required under the final rule. You may elect 

to comply with an optional operating limit for PM. If you use this method to demonstrate continuous 
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compliance, you must install a PM CPMS and establish the operating limit during the initial compliance 

test for filterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals 

inclusive of Hg for liquid oil-fired units). The operating limit for demonstrating continuous shall be 

based on the highest 1-hour average measured during the most recent performance test. If you use a PM 

CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once 

annually and re-establish the operating limit during each performance test. A PM CPMS does not need 

to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion).

Comment 53: Commenter 17758 believes without a filterable PM emissions limit in the final rule, the 

PM CEMS compliance approach is unworkable and inconsistent with the performance criteria of PS-11. 

Commenter 17716 believes that allowing sources to substitute a total PM limit for a filterable PM limit 

for PS-11 purposes is appropriate because the total PM limit would effectively represent the highest 

potential filterable PM limit where condensable emissions are reduced to zero. 

Response to Comment 53: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM, using the PM monitoring as a PM CPMS. The final rule 

also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission 

limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 54: Commenters 17912 and 17798 state that the proposed rule that establishes a long-term 

compliance limitation based upon only a few hours of test results fails to take into account the court’s 

holdings that the EPA must establish MACT standards which include all operating scenarios including 

variability which always occurs.

Response to Comment 54: The agency disagrees with the commenters, for the PM emissions limit 

includes a variability component determined using ICR Part II data and the UPL calculation. 

Comment 55: Commenters 17913 and 19114 state that the proposed approach punishes a unit that has 

low PM emissions because the performance test will establish the condensable emissions from each unit, 

and the subsequent “filterable PM limit” should be equal to the total PM limit in the regulation minus 

the measured condensable PM emissions. Commenters note that the approach will reward facilities that 

are able to increase their emissions right up to the total PM limit during the performance test, so as to 

obtain the least restrictive subsequent “filterable PM limit.” According to the commenters, the goal of 

the regulation should be to ensure that facilities maintain emissions below the given emission standard 

in the regulation; this is achieved by having a facility demonstrate that filterable PM measured with a 

CEMS in combination with condensable PM measured during a performance test do not exceed the 

given total PM emission standard. Commenter 19114 notes that units that employ a baghouse will be out 

of compliance as often as units equipped with precipitators due to the tighter unit-specific PM limit that 

would be established as a result of the required performance stack test. For example, states the 

commenter, a unit equipped with a baghouse may have emissions during the performance testing of 

0.008 lb/mmBTU for filterable PM and 0.012 lb/mmBTU for condensable PM thereby passing the 

performance test; the unit would then have to meet a 0.008 lb/MMBTU limit on its PM CEMS. The 

commenter states that a unit equipped with an ESP may have emissions during the performance test of 

0.02 lb/MMBTU for filterable PM and 0.01 lb/MMBTU for condensable PM, thereby passing the 

performance test; this unit would then have a 0.02 lb/MMBTU limit on its PM CEMS. The commenter 

states that the baghouse is doing a much better job of controlling PM, but the manner in which the 

proposed rule governs ongoing operations does not give the unit with the baghouse credit for its low 
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emissions. According to the commenter, the limits for the baghouse unit should be calculated as the 

proposed Total PM limit, 0.03 lb/MMBTU, less the condensable fraction, 0.012 lb/MMBTU, to give the 

source its filterable PM CEMS limit of 0.018 lb/MMBTU; this approach would meet the spirit of the 

proposed rule by limiting a source to the MACT floor, while giving the source credit for good 

performance. 

Response to Comment 55: Monitoring of total PM is no longer required in the final rule. PM CEMS 

are no longer required under the final rule. You may elect to comply with an optional operating limit for 

PM. See the response to Comment 53 above.

Comment 56: Multiple commenters (17655, 17716, 17725, 17752, 17881, 18498, 18023) oppose the 

proposed procedure for deriving an operating limit based strictly on the filterable PM emission rate 

during periodic performance tests, and provide the following reasons:

1. According to the commenters, an operational limit equal to filterable PM at the time of testing would 

reflect an unrealistic expectation of future performance. For example, state the commenters, a fabric 

filter always performs well for particulate control but, like any other equipment, would be expected 

to work best when new. It would be unreasonable to hold any equipment to the same level of 

performance after years of operation (even with frequent maintenance).

2. According to the commenters, the source’s margin of compliance may be completely lost depending 

on the vagaries of the situation at the time of a performance test. According to the commenters, if the 

combination of normal operating conditions at the time of the performance test enables the unit to 

operate on the lower end of the normal operating range, the PM operating limit will be unattainably

low during operating conditions on the higher end of the normal range. The commenters state that 

the proposed methodology eliminates the compliance margin for sources with very low emissions on 

the day of the performance test, yet the opposite result may occur for a unit that barely meets 

emissions limits due to challenging conditions on the day of the performance test.

3. According to the commenters, the consequence of losing the compliance margin encourages 

operators to reduce their risk of non-compliance by reverting to a compliance option other than PM 

CEMS.

4. According to the commenters, the proposed methodology encourages operators to run performance 

tests on “the ragged edge” of compliance, and the MACT regulations should not encourage operators 

to conduct compliance tests at sub-optimal conditions. Commenters (18023, 17798, 17912) state that 

the proposed method provides a disincentive for installing controls, or operating the control in a 

manner that allows for a reasonable margin of compliance.

5. Commenter 18023 believes the proposed method for establishing a PM CEMS operating limit yields 

a site-specific limitation that is inconsistent with the MACT program’s goal of uniform standards.

6. According to the commenters, an exceedance of the PM CEMS operating limit does not necessarily 

indicate actual emissions were above the underlying PM standard or non-Hg HAP standard.

Response to Comment 56: The final rule requires the use of a PM CPMS for an operational limit and 

does not enforce a numeric PM limit. If you use this method to demonstrate continuous compliance, you

must install a PM CPMS and establish the operating limit during the initial compliance test for filterable 

PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg for 

liquid oil-fired units). The operating limit for demonstrating continuous shall be based on the highest 1-

hour average measured during the most recent performance test. The source has the option to measure 

non-Hg HAP metals with a reference method each quarter. If you use a PM CPMS and associated 

operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and reestablish the operating limit during each performance test. Any degradation of the control equipment 
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will be accounted for in the yearly reestablishment of the PM operational limit and the compliance 

margin will change accordingly. A PM CPMS does not need to meet the requirements for a PM CEMS 

under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with 

the filterable PM emission limit if the source elects to use this approach (see the final preamble for 

further discussion).

Under the final rule, sources are allowed to establish different operating limits monitored with a PM 

CPMS if they believe there is variability due to varying load conditions. The final rule no longer 

requires monitoring with a PM CEMS. Establishment of the operating limit during the initial compliance 

test for filterable PM, total non-mercury HAP metals, or individual non-mercury HAP metals using the 

highest 1-hour average measured, along with allowing more than one operational limit for different load 

conditions, and a 30-day rolling average should provide certainty of compliance for the source for EGU 

owners or operators who choose to use a PM CPMS. Should EGU owners or operators choose not to 

have to develop, monitor, and then maintain the EGUs in accordance with an operating limit, they could 

choose to use a PM CEMS or quarterly emissions testing.

Comment 57: Commenter 17808 recommends changing the treatment of condensable PM for units 

using PM CEMS to establish an operating limit on filterable PM. The commenter provides the following 

example of why the proposed treatment of condensable PM is inequitable with regard to emissions of 

metals: For instance, states the commenter, in the initial compliance demonstration for Facility A, an 

existing coal-fired power plant with heat input >8,300 Btu/lb, shows total PM emissions of 0.020 

lb/MMBtu with 50 percent filterable and 50 percent condensable PM, a facility-specific filterable PM 

limit of 0.010 lb/MMBtu would be established. However, states the commenter, an identical Facility B 

with the same total PM emissions but a higher ratio of filterable PM to condensable PM, such as 75 

percent, would establish a filterable PM limit of 0.015 lb/MMBtu. According to the commenter, this 

method is inherently uncertain, and could result in a facility having a variable emissions target.

Additionally, states the commenter, this method results in unfairly “ratcheting down” the standard on 

some units and introduces a new set of problems.

Response to Comment 57: PM CEMS are no longer required under the final rule. You may elect to 

comply with an optional operating limit for PM. . See the response to Comment 53.

Comment 58: Commenter 17774 states that the use of a total PM surrogate presents a host of problems 

including:

1. According to the commenter, the EPA’s use of a condensable PM standard has the effect of increasing 

the stringency of the PM rate, as compared to an emission rate for PM that applies solely to filterable 

PM emissions.

2. According to the commenter, the total PM standards are problematic because condensable PM is very

difficult to measure and thus proxies must be used for monitoring.

3. According to the commenter, PM CEMS data simply cannot be used to measure compliance in 

conjunction with a rule imposing a limit on total PM without introducing considerable uncertainty into 

the compliance guidelines. The commenter states that the CEMS technology is quite different from the 

formula the EPA used to set the total PM standard. According to the commenter, a PM CEMS monitors 

only filterable PM emissions, not condensable emissions, and therefore cannot be used to set a total PM 

limit; because of this, the limits for PM will have to be established by PM performance tests, which are 

the only process that can measure both filterable and condensable particulates.
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4. According to the commenter, the limits for PM do not allow for variability in testing or operating 

conditions because they are based on the particular circumstances of one stack test. The commenter 

states that this lack of a variability calculation is contrary to the requirements for setting a MACT

standard; if the EPA retains a total PM standard, it must add a variability factor to the requirements to 

reflect the full range of conditions under which sources are operating. The commenter states that it is not 

feasible to require numerous stack tests, as each is expensive and time-consuming, nor is it acceptable to 

base a standard on isolated stack testing conditions alone.

Response to Comment 58: Measurement of condensable PM is no longer required under the rule. 

8. Variability of reference method data from scrubbed units.

Comment 59: Commenter 17675 states that stack tests completed since installation of scrubbers 

indicates filterable PM is very low and that annual condensable PM and filterable PM test data indicates 

there are no consistent ratios for condensable PM, filterable PM, or total PM from the commenter’s

scrubbed units. Based on these highly variable and consistently low PM data, the commenter believes it 

will be nearly impossible to develop an accurate correlation curve for PM CEMS. In lieu of the PM 

CEMS option, the commenter requests that the final rule include an LEE testing option for sources 

consistently performing at emission rates much lower than the PM standard. The commenter requests 

that such a PM LEE option preclude regular or additional Method 29 tests. 

Response to Comment 59: Measurement of condensable PM is no longer required under the new rule. 

The final rule does include the LEE option with less frequent performance testing.

Comment 60: Commenters 17383 and 19121 state that trying to use a PM CEMS that was designed to 

measure filterable PM for measuring total PM is questionable at best and that based on the commenter’s

limited testing, the ratio of condensable PM to filterable PM is highly variable. According to the 

commenters, under these circumstances, correlation of the PM monitor would be difficult if not 

impossible. Commenter 19121 states that the inclusion of condensable PM fractions in the limit hints at 

trying to control PM2.5 precursors, which is better managed under another CAA program. 

Response to Comment 60: Measurement of condensable PM is no longer required under the new rule. 

PM CEMS are no longer required in the final rule.

Comment 61: Commenter 18443 states that the EPA cannot require sources to set filterable PM 

operating limits with no compliance margin and that for units that emit low concentrations of PM, this is 

an extremely onerous requirement with which it is likely impossible to comply. Units with wet FGDs, 

for example, typically emit filterable PM at or below detection levels. According to the commenter, a 

limit set at these levels would be below the detection level of a PM CEMS and allow no compliance 

margin. The commenter states that the EPA has not justified this type of requirement and it must be 

eliminated from the final rule.

Response to Comment 61: PM CEMS are no longer required in the final rule. PM CPMS should be 

able to operate at the low PM operational levels expected at sources and should not be below the 

detection limits. 

9. Need for PM CEMS availability criteria.
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Comment 62: Commenters 17638 and 17681 state that the EPA must establish minimum CEMS data 

availability and deviation requirements and that the operating costs included in the proposal fail to 

account for all the maintenance costs associated with PM CEMS. One commenter requests that the EPA 

revise those operating cost estimates. 

Response to Comment 62: PM CEMS are no longer required in the final rule. 

10. Table 4 requirement to convert PM CEMS readings to dry basis.

Comment 63: Several commenters (17716, 17725, 18014) advise that the requirement in Table 4 of the 

proposed rule to convert PM CEMS data to a “mg/ dscm” basis creates unnecessary problems because 

most PM CEMS do not measure on a dry basis but are correlated to “mg/wscm.” According to the 

commenters, switching to a mg/dscm is problematic because the current measurement must be converted 

to a dry basis which would require a source to monitor stack moisture or use a some type of default 

value. Notwithstanding the inadvisability of using the PM measured during the compliance test as an 

operating limit, state the commenters, if the final rule retains this provision, sources should be allowed 

to use either the average 30-day correlated analyzer response (mg/wacm, mg/wscm, etc.) or lb/MMBtu

values as an indicator.

Comment 64: Commenter 17881 states that under section 63.10021(a)(11)(ii) diluent data (O2/CO2) is 

only needed for the lb/MMBtu rate calculation or concentration values corrected back to a diluents gas 

concentration (which is not the case, as the PM filterable operating limit is mg/dscm and is not corrected 

back to a specific diluent level). 

Response to Comments 63 - 64: PM CEMS are no longer required under the final rule. PM CPMS 

measurement data are to be in units of raw instrument output and not necessarily on a concentration 

basis in the final rule. The final rule also does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit if the source elects to use this approach (see the final 

preamble for further discussion).

11. ESPs vs. fabric filters.

Comment 65: Commenter 17705 has concerns because while ESPs are highly effective control 

technologies, they may not be as consistent in its day-to-day performance as fabric filter technology. 

According to the commenter, this difference is not a problem at currently permitted PM limits and under 

current compliance demonstration requirements (i.e., annual performance testing), but it could be a 

significant problem if the EPA retains the currently proposed requirements to establish PM operating 

limits, as such operating limits are expected to allow little, if any, operational variability in control 

equipment. The commenter doubts that even utilities with EGUs equipped with fabric filters can be 

confident they can demonstrate continuous compliance if the PM operating limit requirement is 

implemented as proposed by the EPA. 

Response to Comment 65: While the rule no longer requires use of PM CEMS and associated 

operational limits, the rule retains establishing an operational limit and measuring it using a PM CPMS. 

Should the owner or operator be uncomfortable with using a PM CPMS and an operating limit, the final 

rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM 

emission limit if the source elects to use this approach (see the final preamble for further discussion). 

The source can also conduct quarterly performance testing in place of these continuous monitoring 

options.
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12. Direct measurement.

Comment 66: Commenter 17747 states that direct monitoring of pollutants rather than a surrogate (PM) 

will contribute to a better understanding of the health effects associated with each metal. According to 

the commenter, direct measurement for HAP by the EPA is a provision of the CAA Revisions of 1990 

and best fit with the requirements and purpose of the law. 

Response to Comment 66: The rule allows source owners or operators to choose a filterable PM 

emissions limit, along with a total metals emissions limit or individual metals emissions limits, because 

the same emissions control technology that reduces filterable PM emissions also reduces filterable 

metals emissions. 

Comment 67: Commenter 17881 states that it makes little sense to have sections 63.10005(d)(1) 

through (d)(6), as well as section 63.10005(e), describe the averaging of hourly “concentrations”

obtained using a CMS during an initial 30-day period when the emission standards are always expressed 

as emission rates (in units of lb/MMBtu, lb/TBtu, lb/MWh or lb/GWh). Commenter further notes that 

section 63.10005(d)(5) currently discusses the use of PM CEMS for demonstrating compliance with the 

applicable emission limits in Tables 1 and 2 of the proposed rule but that the reference to the use of PM 

CEMS for demonstrating compliance with the emission limits is wholly inappropriate, as the PM CEMS 

are to be used to verify compliance with an operating limit (in units of mg/dscm) consistent with Table 4 

of the proposed rule, not PM emission limits expressed as lb/MMBtu or lb/MWh (and reckoned on a 

different basis, i.e., total PM versus filterable PM). 

Response to Comment 67: Measurement of condensable PM is not required in the final rule. PM 

CEMS are no longer required in the final rule. However, the final rule does provide for the use of a PM 

CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion).

13. Clarification on use of parametric monitoring in lieu of CEMS.

Comment 68: Commenter 17914 requests clarification on the parametric monitoring approach 

described on page 25064. The commenter finds only an annual test requirement for the Parametric 

Monitoring option. The commenter notes that in the preamble (pages 25029 -31) both initial compliance 

and on-going compliance for IGCC or coal or solid oil-derived fuels requirements are discussed and if 

an EGU elects to use total PM as a surrogate for non-Hg HAPS, they must use a PM CEMS. The 

commenter states that an EGU may:

• Install PM CEMS and reduce the level of testing regardless of type of control equipment status

• Demonstrate compliance by testing every month if no controls are installed and no continuous PM 

monitoring is done

• Demonstrate compliance by testing every 2 months if controls are installed and specific control 

equipment parameters are monitored with PM CEMS

The commenter states that any EGU can, as an alternate to testing, install PM CEMS. According to the 

commenter it is unclear in the body of the proposed rule what testing beyond an annual compliance test 

may be required for the parametric monitoring option, and there is no evidence provided by the EPA to 

suggest why a parametric monitoring approach would require additional testing beyond that required for 
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PM CEMS. According to the commenter, it would be expected that a change in coal characteristics, 

combustion system operation or AQCS system performance may cause the parametric correlation to PM 

emissions to change but it is not clear why a PM CEMS would be immune to this same effect. 

According to the commenter, the use of PM CEMS requires use of a quasi-parametric relationship with 

filterable particulate since the PM CEMS signal must be correlated to the reference method, for example 

EPA Method 5 or Method 17. The commenter states that these correlations can change over time and 

with varying conditions. Monthly variation of PM emissions vs. system operating parameters requires 

additional study to determine if any variation exists that may result in exceedance of the total PM limit. 

The commenter states that this study should also include PM CEMS and the potentially variable 

relationship of filterable PM to Total PM over time. The commenter recommends the proposed rule be 

revised to reduce the testing requirements when using the parametric monitoring to an annual test or less 

often when it is proven that PM emissions are < 75% of the MACT limit in line with the final Industrial 

boiler MACT (subpart DDDDD) regulations. The commenter further recommends that the text in 

section 63.1 0022 explicitly include wet ESP technology in the parametric monitoring options for PM.

Response to Comment 68: Measurement of condensable PM is not required in the final rule. PM 

CEMS are no longer required in the final rule. If you use a PM CPMS, you must conduct annual testing 

to assess the operating limit (expressed in the raw output of the PM CPMS) established during the 

previous test.

Comment 69: Commenter 19033 recommends that the operating requirements for ESP power input, as 

documented during performance tests, only be applicable during periods of PM CEMS downtime, so 

that it can be demonstrated that the ESP is operating properly during such PM CEMS downtime events. 

The commenter states that such a provision would be patterned after the Part 75 requirements that 

address demonstration that the APCD is operating properly, so that SO2 substitution values can be 

supported during periods of SO2 CEMS downtime. 

Response to Comment 69: Parameter monitoring of ESP parameters is not required in the final rule.

Comment 70: Commenter 19121 states that units with PM CEMS should not be required to install bag 

leak detectors.

Response to Comment 70: Parameter monitoring of baghouses, including bag leak detectors, is not 

required in the final rule.

14. Corrections.

Comment 71: Commenter 18014 states that Table 8 erroneously references “QA Procedure 5” for the 

PM CEMS QA/QC requirements. According to the commenter, this reference should be changed to 

“Procedure 2.”

Response to Comment 71: This reference has been removed in the final rule.

Comment 72: Commenter 19121 states that part 63 Table 4 is setting operating limit averaging periods 

of 1 hour for outlet emissions is counter to the 30 boiler operating day averaging methodology.

Response to Comment 72: The final rule requires a 30-boiler operating day rolling average for the PM 

CPMS monitoring.
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Comment 73: Commenter 17881 states that the PM CEMS should not be subject to the quality

assurance tests required under section 63.10021 (a)(11)(iv) because filterable PM is not the regulated 

pollutant and correlation testing will dictate operating in an abnormal manner for purposes of obtaining 

three different PM levels. Commenter notes that this applies also to (a)(16)(vii) and (a)(17)). 

Response to Comment 73: The final rule does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit in the final rule if the source elects to use this approach 

(see the final preamble for further discussion). If this option is used, the source must comply with the 

QA requirements in PS 11. However, PM CEMS are not required in the final rule. If the source uses the 

monitoring as a PM CPMS to demonstrate compliance with an operating limit, then the provisions of PS 

11 do not apply, and the applicable QA/QC provisions will be as set forth in the monitoring plan 

required in the final rule.

Comment 74: Several commenters (19536, 19537, 19538) states the compliance provisions specify

periodic performance testing in which the surrogate, regulated pollutants, and operating parameters are 

monitored for two cases: (1) no PM CEMS with PM controls and (2) no PM CEMS with no PM 

controls. The commenters state that if a PM CEMS is used, regardless of whether the units is equipped 

with PM controls, no operational or non-Hg metal HAP monitoring is required except during an every 5-

year performance test and that this is inadequate to determine continuous compliance. Further, it does 

not provide any testing for metals present as gases or condensables. Thus, state the commenters, HAP

such as selenium, which the EPA admits is frequently present in the gases, would not be measured either 

directly with Method 29 or indirectly through a surrogate when PM CEMS is used to determine 

compliance. The commenters also state that initial performance compliance provisions are missing from 

Table 5 for PM CEMS.

Response to Comment 74: You may elect to comply with an optional operating limit for PM. If you 

use this method to demonstrate continuous compliance, you must install a PM CPMS and establish the 

operating limit during the initial compliance test for filterable PM, total non-Hg HAP metals, or 

individual non-Hg HAP metals (or HAP metals inclusive of mercury for liquid oil-fired units). The 

operating limit for demonstrating continuous shall be based on the highest 1-hour average measured 

during the most recent performance test. If you use a PM CPMS and associated operating limit, you 

must conduct the applicable Method 5 or Method 29 test once annually and re-establish the operating 

limit during each performance test. A PM CPMS does not need to meet the requirements for a PM 

CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit if the source elects to use this approach (see the final 

preamble for further discussion). In that case, the PM CEMS is used as the direct method of compliance 

and no additional testing is required other than tests that are required as part of the QA requirements in 

PS 11.

15. Five-year test requirement.

Comment 75: Commenter 17798 states that stack testing once every 5 years to corroborate 

CEMS monitoring is a very long time period to rely on CEMS filterable PM data which may or may not 

relate to actual metals emissions. Therefore, the commenter feels this monitoring approach is overly 

complex, requires expensive CEMS monitoring, and may not demonstrate real metals emission levels 

for up to 5 years. The commenter requests that the EPA consider the following modifications: With the 

CEMS monitoring option, require stack testing every 2 years instead of 5 years to establish compliance 

with metal emission limits relative to filterable PM emissions. The commenter states that using a CEMS

approach is premised on the EPA’s ability to establish a relationship between filterable PM and metals 
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emissions on a sector-wide basis and sources with particular control equipment may require adjustments 

to this method to account for wet conditions from wet scrubbers. The commenter asserts that under a 

CEMS monitoring approach the EPA should eliminate any requirement for testing and setting of 

pollution control equipment operating parameters. 

Response to Comment 75: The comment is moot, as the rule does not require use of PM CEMS; PM 

CPMS are an alternative and annual testing is required to reassess the operating parameter value. For 

those owners or operators who choose to use PM CEMS as an alternative, no additional operating 

parameter value monitoring or limit is necessary. Furthermore, in that case, the PM CEMS is used as the 

direct method of compliance and no additional testing is required other than tests that are required as 

part of the QA requirements in PS 11.

Comment 76: Commenter 17800 asserts that the EPA has not explained why there should be an 

independent filterable PM limitation that changes every 5 years. According to the commenter, although 

it is reasonable to retest for compliance every 5 years because of the innate variability of unit operation 

resetting emission limitation is not. 

Response to Comment 76: The comment is moot, as the rule does not require the use of PM CEMS and 

PM emissions testing every 5 years. Where a source uses a PM CPMS as part of its monitoring 

approach, annual testing is required to reassess the operating parameter value.

16. PM as surrogate Method 202.

Comment 77: Commenter 19114 states that using total PM as a surrogate has numerous technical 

challenges that demonstrating continuous compliance using a filterable PM limit does not. The 

commenter states that filterable PM can be measured continuously through a PM CEMS monitor. 

According to the commenter, the variability of condensable PM in the flue gas is enormous and the test 

methods for condensable PM are still incapable of accurately measuring the condensate in a replicable 

fashion routinely. The commenter states that the study that the commenter conducted, in conjunction 

with EPRI, showed that the Method 202 may not be accurate in stacks with FGD. The commenter states 

that more study is required to understand the limitations with the measurement of condensables and to 

construct a test method that will be accurate and repeatable for in-stack measurements.

Response to Comment 77: While the agency disagrees with the suggestion that Method 202 is 

“...incapable of accurately measuring the condensate in a replicable fashion routinely...,” the comment 

is moot, as the final rule does not contain a total PM emissions limit.

17. Miscellaneous.

Comment 78: Commenter 17800 states that under section 63.10010(g)(3) the EPA is requiring a PM 

CEMS to “...complete a minimum of one cycle of operation (sampling, analyzing, and data recording) 

for each successive 15-minute period.” According to the commenter, depending on the PM CEMS used 

and the level of particulate emitted this may not be possible. For example, states the commenter, a 

system that uses a filter tape (dichotomous sampler) to measure filterable PM where there is very low 

filterable PM levels emitted (similar to the proposed PM standard) may not be able to collect enough 

sample to adequately measure these emissions in this 15 minute timeframe. The commenter states that 

the EPA should allow some flexibility in this requirement to allow for monitoring extremely low levels 

of filterable PM emissions.
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Response to Comment 78: Measurement of condensable PM is not required in the final rule. PM 

CEMS are not required in the final rule.

Comment 79: Commenter 17752 questions, with respect to PS 11, whether it is possible to create or 

measure two PM levels between zero and the levels anticipated in the rule.

Response to Comment 79: The rule now includes an option for using PM CPMS, whose use should 

alleviate the commenter’s concerns, as well as maintains the option for using PM CEMS. Note that other 

compliance options exist should an EGU owner or operator choose not to use PM CPMS or PM CEMS. 

Comment 80: Commenter 17752 suggests that PM CEMS could be use as an “indicator of compliance”

for an “appropriate” filterable PM limit, to identify when investigation and corrective action is 

warranted.

Response to Comment 80: The comment is moot, for while the rule maintains the use of PM CEMS as 

a compliance demonstration option, the final rule also allows the use of PM CPMS, which involves 

establishing and maintaining a site-specific operating limit as an indicator of compliance, as another 

compliance demonstration option.

Comment 81: Commenters 17724 and 17876 state that the CEMS the facility installed in preparation to 

CAMR have significant reliability and operational issues (Hg, PM, HCl). Commenters 17724 and 17876 

state that the EPA has left the long-term operational problems such as calibration gases to industry and 

there are not accurate and reliable monitoring methodologies for demonstrating. Commenters 17724 and 

17876 state the EPA purports to provide compliance flexibility while in reality there is very little 

flexibility in light of the problematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not 

commercially available to measure HCl emissions from coal-fired EGUs, and no HCl CEMS were used 

to collect the data the EPA used to establish the HCl standard.

Response to Comment 81: The agency disagrees with the commenters. As mentioned elsewhere, the 

agency finds that the operation and maintenance issues for the CEMS mentioned are no different than 

for other CEMS now in wide use and acceptance by the industry. The agency is aware that the 

calibration gas issue is to be rectified well in advance of the rule’s compliance date. The agency notes 

that the rule is quite flexible with respect to compliance demonstration, containing numerous choices for 

compliance, including the use of emissions testing alternatives for those EGU owners or operators who 

remain concerned over use of CEMS or PM CPMS. The agency notes that FTIR CEMS exist now and 

can be used to measure HCl emissions continuously, that the HCl emissions limit was developed from 

emissions testing and has been adjusted to be appropriate for measurement with HCl CEMS, and that 

emissions testing options to demonstrate compliance exist for those EGU owners or operators who 

choose not to use CEMS.
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5A07b - Testing/Monitoring: Application of multi-metals CEMS

Commenters: 17283, 17747, 19536, 19537, 19538

1. In favor of multi-metals CEMS.

Comment 1: Commenter 17283 recommends that multi-metal CEMS should be an allowed alternative 

for demonstrating compliance with the EPA proposed metals emissions limits. The commenter states 

that this recommendation is based on the proven performance and commercial availability of multimetal CEMS, the fact that multi-metal CEMS represent substantially enhanced monitoring and PM is 

not an appropriate surrogate for HAP metals emissions in an increasingly complex energy extraction 

process. 

Response to Comment 1: In the final rule, facilities would be allowed to petition the Administrator 

under section 63.8(f) of subpart A of part 63for an alternative to use of multi-metal CEMS at a specific 

site in lieu of required monitoring in the final rule. Also see responses to comments under Comment 

Code 4F01 for further discussion of relationship of PM and non-Hg metal HAP.

Comment 2: Commenter 17747 states that multi-metals CEMS represent the highest level of 

monitoring for these sources (i.e., directly monitoring the HAP pollutant of concern on a continuous 

basis).

Response to Comment 2: Short term multi-metal CEMS demonstrations have historically shown, with 

appropriate QA/QC, that the data are accurate and reliable. Longer term operational information would 

be needed to support a proposal of performance specifications. We agree with the commenter that data 

from multi-metal CEMS is a direct measurement of metals and not a surrogate measurement.

Comment 3: Commenter 17747 asks that the EPA incorporate language in the final rule expressly 

allowing the use multi-metals CEMS once a multi-metals performance specification has been 

promulgated. According to the commenter, the incorporation of this type language would give source 

operators some assurance that monitoring with a multi-metals CEMS would be acceptable to the EPA, 

and it is also likely to encourage the use of multi-metal CEMS on sources, which is beneficial to the 

EPA’s understanding of the health effects associated with metal HAP. Finally, states the commenter, 

multi-metal CEMS would provide source operators with more feedback on control of metals and may 

allow them to optimize operations to minimize HAP metal emissions. The commenter provided 

information about the capabilities of their proprietary testing technology.

Response to Comment 3: We may in the future propose a multi-metal performance specification and 

QA/QC requirements but we have no immediate plans to do so because we lack long term operational 

information and the resources to support a proposal. The final rule does reiterate the ability of a source 

to petition the Administrator under section 63.8(f) of subpart A of part 63for an alternative to use multimetal CEMS at a specific site in lieu of required monitoring in the final rule. The EPA does have a draft 

method on its website at www.epa.gov/ttn/emc that could be the basis of a petition to the Administrator 

for alternative monitoring. We agree that multi-metal CEMS could possibly provide source operators 

with more feedback on control of metals and may allow them to optimize operations to minimize HAP 

metal emissions.

Comment 4: Commenter 17283 states that direct monitoring of all phases of all HAP metals is an 

enhancement over the monitoring of a surrogate (PM) for some urban HAP metals. According to the 
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commenter, periodic testing does not provide reasonable assurance of control/prevention nor does 

monitoring PM provide reasonable assurance of urban HAP metal control/prevention, and multi-metals 

CEMS is commercially available and accepted by the EPA. Thus, states the commenter, use of PM as a 

surrogate for HAP metals monitoring is no longer needed.

Response to Comment 4: We believe that the final rule does provide a reasonable assurance of 

compliance with the non-Hg metals limitation and the monitoring and testing that we are requiring are 

consistent with numerous EPA rulemakings for comparable emission sources. We are providing for 

monitoring continuous compliance with specific standards through the use of an applicable CEMS, or a 

sorbent trap for Hg, or a PM CPMS for non-Hg metals or PM. Should a source owner or operator elect 

not to use CEMS or the other instrumental methods, performance testing is required.

2. Individual metals.

Comment 5: Commenter 17283 states that monitoring only the vapor phase of Hg does not provide 

reasonable assurance of control/prevention under all conditions that are now to include SSM events. The 

commenter states that this is particularly the case when there is a proven and approved technology 

available that measures all phases of Hg. The commenter recommends the use of multi-metal CEMS as 

an alternative to Hg CEMS.

Comment 6: Commenter 17283 states that selenium does not meet two of the three court-defined 

criteria which must be met for PM to be a surrogate for HAP metals: “...HAP metals are invariably

present in cement kiln PM...” (subsection 3.2.1); and “...PM control technology indiscriminately 

captures HAP metals along with other particulates.” (subsection 3.2.2.) According to the commenter, the 

addition of a condensable fraction to the definition of PM only complicates this for other HAP metals.

Response to Comments 5 - 6: The EPA disagrees that selenium does not meet two of the criteria which 

must be met for PM to be a surrogate. Selenium is a metalloid that sits just below sulfur on the periodic 

table and is, chemically, very similar to sulfur. In the high temperature combustion environment, 

selenium is likely to be present as gas phase SeO2 (as, similarly, sulfur is likely to be present as gaseous 

SO2). Much like SO2, SeO2 is a weak acid gas. The ash from western subbituminous and lignite coals 

contains natural alkalinity (in the form of Ca or Na compounds). The alkaline compounds in the fly ash 

effectively neutralize the SeO2 acid gas, forming a particulate that is easily removed in the PM control 

device. Eastern bituminous coals typically contain insufficient free Ca to completely neutralize the SeO2

and the much increased levels of SO2 in that flue gas. However, because SeO2 behaves very similarly to 

its sulfur analog, SO2, it can be expected to also be removed effectively in standard FGD technologies 

(wet scrubbers, dry scrubbers, DSI, etc.). Therefore, selenium will either fall in to the category of ‘‘nonHg metal HAP’’ and be effectively removed in a PM control device, or it will fall into the category of 

‘‘acid gas HAP’’ as gaseous SeO2 and be effectively removed using FGD technologies. We specifically

reviewed the Method 29 data from the utility boiler ICR where we had measured particulate emissions, 

selenium emissions and selenium in the coal. In almost 90 percent of the facilities less than half of the 

estimated selenium was emitted. In the remaining facilities, we reviewed the location where selenium 

was collected in the Method 29 sampling train and found measureable amounts of selenium on the 

quartz filter. While we do not know the amount of selenium that was in the flue gas prior to any 

emissions control, we conclude that selenium was available in particulate form after emissions controls 

and was likely removed by the particulate and/or acid gas controls.

3. Concerns about use of PM as a surrogate.
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Comment 7: Commenter 17283 states that reducing HAP metal concentrations from their current levels 

in feed and fuel to zero would essentially reduce HAP metals to zero in the emissions (reducing HAP 

metals concentrations by many orders of magnitude) while having essentially no impact on PM 

emissions. According to the commenter, processes and additives may increase PM emissions without 

increasing HAP metal emissions, such as might be the case of scrubber solution bypassing demisters, or 

they may increase HAP metal emissions without increasing PM, such as might be the case if trace HAP 

metal concentrations increase in an additive or other feed material, or where an additive is injected into 

the process. The commenter states that without the direct monitoring of HAP metals, there will be no 

way to determine if the HAP metals are changing.

Response to Comment 7: While modifying the feed and fuel such that the HAP metal concentrations 

are zero would achieve essentially zero emissions, the EPA knows of no techniques which could achieve 

this end without transferring the emissions to another source. Also see responses to comments under 

Comment Code 4F01 for further discussion of relationship of PM and HAP metals.

Comment 8: Commenter 17283 states that Method 29 is costly, dangerous, creates hazardous waste and 

is difficult to obtain accurate and reliable results at the low concentration expected with contemporary

controls. The commenter states that in effect, it appears that the EPA is using PM as an indicator or 

parameter to monitor in much the same way they use plant operating parameters in CPMS. According to 

the commenter, as long as PM, fuel, and all control parameters remain relatively constant between 

Method 29 measurements, one might be able to assume that HAP metals emissions have not changed 

dramatically since the last Method measurement, but it would be far less costly, far more informative 

and protective as well as more useful for plant operation if a multi-metals CEMS were used to measure 

HAP metals emissions directly and continuously.

Response to Comment 8: The EPA disagrees with the commenter’s opinion about EPA Method 29. We 

have found the method to provide reliable, low level, repeatable results when properly conducted in the 

field. The cost of using this method is actually much more economical, per analyte than many other test 

methods that the EPA employs to measure emissions.

Comment 9: Several commenters (19536, 19537, 19538) state that total PM is not an appropriate 

surrogate for non-Hg metal HAP and those HAP can be accurately measured by CEMS. According to 

the commenter, if the EPA retains total PM as a surrogate, a PM CEMS should be required, not optional, 

to determine compliance. The commenter states that PM CEMS have been required in consent decrees 

and PSD permits to determine compliance and are in wide use at EGUs.

Response to Comment 9: The final rule uses a filterable PM surrogate limit for non-Hg metal HAP, 

with the required compliance testing using a manual PM method. The EPA also established an alternate 

equivalent standard for non-Hg metal HAPs, but the on-going monitoring with these metals is 

accomplished with a PM CPMS for an operational limit or frequent testing with a metals manual 

method. Also see responses to comments in 4F01 of this document for further discussion of relationship 

of PM and HAP metals. Furthermore, the final rule also does provide for the use of a PM CEMS to

determine compliance with the filterable PM emission limit if the source elects to use this approach (see 

the final preamble for further discussion). In that case, the PM CEMS is used as the direct method of 

compliance and no additional testing is required other than tests that are required as part of the QA 

requirements in PS 11.
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5A08 - Testing/Monitoring: Application of SO2 CEMS

Commenters: 17191, 17383, 17621, 17677, 17722, 17725, 17728, 17730, 17752, 17758, 17775, 17790, 

17800, 17820, 17821, 17868, 17873, 17881, 17886, 17902, 17909, 18014, 18037, 18428, 18498, 18539, 

19120, 19536, 19537, 19538, 18023

1. Allow existing IGCC units to use SO2 CEMS option.

Comment 1: Commenter 17191 believes it is appropriate for the EPA to include the SO2 monitoring 

option in Table 2, part 3b as an alternative to monitoring HCl. The commenter notes in response to the 

EPA statements in the preamble regarding a lack of data on SO2 monitoring for existing IGCCs, that 

SO2 CEMS monitoring data for its IGCC unit are routinely submitted electronically to the EPA and the 

EPA has ready access to the CEMS data as they are publically accessible and have been used previously

in the rulemaking for the Transport Rule (aka Cross-State Air Pollution Rule). The commenter stresses 

the importance of the SO2 monitoring as an option, given the current lack of a PS specific to HCl

CEMS, as described in the proposed rule preamble. The commenter believes that it is in the best interest 

of it cooperative members to be able to rely on existing SO2 monitors for acid gas compliance rather 

than incurring the cost of installing HCl monitors that have little or no long-term demonstrated “real 

world” reliability. The commenter requests that the SO2 CEMS monitoring option be included for the 

existing IGCCs as a matter of equity and fairness. As these data are readily available to the EPA and 

interested public, there is no basis for the EPA’s preamble justification for not including the option. 

While the commenter specifically references their IGCC unit, they do note that it is one of only two 

IGCC EGUs currently operating that are included in the existing IGCC category established by the 

proposed regulation.

Commenter 17191 requests that section 63.9991 be rewritten to eliminate the pre-requisite of using a 

wet or dry FGD technology to qualify for the alternate SO2 CEMS limit. The commenter notes that their 

IGCC system uses a sulfur removal system upstream of the combustion of the syngas; the removed 

sulfur is captured and sold as molten sulfur for reuse. According to the commenter, as the sulfur is 

removed prior to combustion no FGD technology is required for IGCC emissions. The commenter

believes this Clean Coal Technology should not be penalized (prevented from opting to use SO2

monitors) because it uses an upstream technology for sulfur removal, eliminating the need to treat the 

flue gas for SO2 removal.

The commenter attempted to find the provisions in the regulation that need to be amended so that 

existing IGCC units can rely on the option of SO2 CEMS use. The commenter requests that the EPA 

amend other sections of the regulation, as necessary, which may have been overlooked or that may be 

subject to revision before final rule issuance that would prohibit existing IGCC SO2 CEM use.

The commenter suggests the following modifications to section 63.9991:

“(a)(l)(i) You man not use the alternate SO2 limit if your coal-fired EGU does not have a 

system for pre-combustion sulfur removal or a system using wet or dry flue gas 

desulfurization technology installed on the unit. “ (Emphasis reflects proposed inserted 

change).

“(a)(l)(ii) You may not use the alternate SO2 limit if your oil-fired EGU does not have a 

system for pre-combustion sulfur removal or a system using wet or dry flue gas 
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desulfurization technology installed on the unit. “ (Emphasis reflects proposed inserted 

change).

“(a)(l)(iii) You must operate the pre-combustion sulfur removal system, or the wet or 

dry flue gas desulfurization technology installed on the unit at all times in order to 

qualify to use the alternated SO2 limit. “ (Emphasis reflects proposed inserted change).

The commenter also requests that section 63.10000(c)(1) be amended, in part, to read:

“As another alternative to HCl CEMS, you may demonstrate initial and continuous 

compliance through use of a certified sulfur dioxide (SO2) CEMS, provided the unit has a 

system for pre-combustion sulfur removal or a system using wet or dry flue gas 

desulfurization technology. “ (Emphasis reflects proposed inserted change).

Comment 2: Commenter 17758 suggests SO2 CEMS should be allowed to be used as a surrogate for 

HCl for IGCC units since FGD is not needed for those units and HCl CEMS are not a proven 

compliance monitoring technology. The commenter believes such details need to be clearly defined in 

the final rule.

Response to Comments 1 - 2: The EPA disagrees with the commenter’s suggested revisions. First, the 

premise upon which the rule allows for SO2 monitoring in lieu of HCl monitoring of the exhaust of a wet 

or dry FGD unit is that the FGD preferentially removes HCl over SO2. That means that SO2 control is a 

certain indicator of similar or better HCl control when the control measure is a wet or dry FGD. We are 

not aware that other sulfur control measures including pre-control sulfur removal can be related to 

similar HCl emissions reduction. Further, the rulemaking record does not have any SO2 data from 

existing IGCC units to correlate with HCl emissions. The SO2 data the commenter references are not 

data collected as part of establishing the HCl standards under this rule. As noted by the commenter, the 

unit in question appears not to use a wet or dry FGD, which is a prerequisite for using SO2 as an 

indicator of HCl control. The preamble to the proposed rule fully explains the rationale for this 

limitation and the EPA disagrees with the commenter’s suggestions.

2. SO2 CEMS certification.

Comment 3: Commenter 17677 states that section 63.10010(e) creates some confusion about 

certification of SO2 CEMS. The commenter believes the proposed rule should simply allow CEMS

certified under 40 CFR 75 or 40 CFR 60 to be acceptable.

Response to Comment 3: The EPA disagrees as the specific provisions in section 63.10010(e) add 

specific requirements to the general part 60 and part 75 requirements. Note that the EPA believes part of 

the commenter’s confusion results from a typographical error in cross referencing paragraph (g) of the 

section. All of those cross references should be to paragraph (e), not (g), and are corrected in the final 

rule.

Comment 4: Commenter 17402 objects to the linearity test requirement for SO2 monitoring. The 

commenter states that section 63.10010(e)(6)(ii) of the proposed regulations states that one “must 

perform the linearity check test required in Appendix A to part 75 on the SO2 CEMS whether or not it 

has a span of 30 ppm or less.” According to the commenter, this requirement ignores the EPA’s previous 

acknowledgement that a linearity check “begins to lose its significance” at span values less than or equal 

to 30 ppm. The commenter states that in the preamble to the proposed 1998 revisions to 40 CFR Part 75, 
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the EPA acknowledged that span at these low values loses its significance. The commenter believes the 

proposed requirements should be replaced with the Part 75 exemption. According to the commenter part 

75 requires EGUs to ensure that the analyzer span is set to obtain accurate and representative data. Part 

75 also requires the owner or operator of an EGU to conduct an annual analyzer span and range 

evaluation to ensure that the majority of the analyzer readings are within 20 to 80% of span. According 

to the commenter, coupled with these requirements, the three linearity gas concentrations are more than 

sufficient to determine that the analyzer is linear. The commenter states that the proposed linearity

requirement will add significant costs.

Response to Comment 4: The final rule has been amended to remove the fourth gas nominally near the 

emission standard level. The EPA disagrees that a linearity check is unnecessary to ensure quality

assurance of the SO2 CEMs for compliance at emission standard levels. 

Comment 5: Commenter 17758 states that it is confusing why, despite using continuous SO2 monitors 

successfully for more than 20 years, the EPA has proposed additional QA requirements. The commenter 

states that in proposed section 63.10010(e)(6) the EPA has added several problematic additional QA 

requirements for SO2 CEMS that are not currently specified in Appendices A or B of 40 CFR part 75. 

The commenter notes the following:

 Section 63.10010(e)(6)(i) – According to the commenter, the proposed Utility MACT rule would 

require the SO2 CEMS to pass a 7-day calibration error test for units with spans less than or 

equal to 50 ppm and it is unclear whether the specifications in Part 75 or PS 2 are applicable. 

According to the commenter, under Part 75 requirements, the 7-day calibration error 

specification is a difference of less than or equal to 2.5 percent of span or ±5 ppm; using the Part 

75 specifications, current SO2 CEMS should be able to easily meet the alternative ±5 ppm 

requirement. The commenter states that if the PS 2 specifications are to be applied, then the 

specification is restricted only to the drift requirement of 2.5 percent of span, and this will make 

passing the 7-day calibration error test significantly more burdensome. According to the 

commenter regardless of which specification is used, neither will improve the overall quality or 

accuracy of the collected data, since these are only implemented for initial certification or 

recertification events; in other words, there is little a utility can do to upgrade its SO2 CEMS to 

meet this requirement.

 Section 63.10010(e)(6)(ii) – According to the commenter, the addition of the linearity test will be 

an additional QA requirement for many existing systems that have SO2 CEMS installed 

downstream of a wet or dry scrubber, will add significant cost to update software to integrate the 

new procedure, and potential costs to add the necessary hardware to existing systems to 

accommodate the new calibration gas cylinders, and will increase calibration gas costs, not only

in the capital cost of purchasing the additional calibration gases but also in monthly demurrage 

fees.

 Section 63.10010(e)(6)(iii) – According to the commenter, this provision may require utilities to 

add a fourth calibration gas to the linearity sequence in order to have a calibration gas 

“nominally at a concentration level equivalent to the applicable emission limit.” The commenter 

states that if a utility is required to include a fourth calibration gas level to the linearity check 

procedure, an additional cost in terms of hardware and software upgrades to integrate the fourth 

linearity calibration gas into the calibration system will be incurred by the utility. According to 

the commenter, this requirement is unnecessary and will not improve the quality of SO2 data 

being collected. The commenter states that current guidelines in 40 CFR Part 75 ensure that the 

majority of emission measurements made by an SO2 CEMS fall within a certain percentage of 
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the monitor’s calibrated span and that users are required to evaluate the span of the SO2 CEMS 

on annual basis, which has proved sufficient in maintaining the overall integrity and accuracy of 

the SO2 emissions being reported. At a minimum, states the commenter, the EPA should quantify

the term “nominally” (e.g., a calibration gas within ±20 percent of the equivalent concentration 

level).

Response to Comment 5: The final rule will be amended to remove the 7-day calibration error test for 

units with spans less than or equal to 50 ppm and remove the fourth calibration gas nominally near the 

standard. The EPA disagrees that a linearity check is unnecessary to ensure quality assurance of the SO2

CEMs for compliance at emission standard levels and will retain that requirement. In addition, sources 

may choose to comply with HCl CEMS or periodic HCl testing in lieu of updating their SO2 CEMS

system to check linearity quarterly. 

3. Revisions to FGD applicability.

Comment 6: Commenters 17728 and 17775 support the EPA’s inclusion of an option for use of an SO2

CEMS to comply with a surrogate limit for SO2; however, they believe several adjustments are needed 

to make this a reasonable option. The commenters state that to use the option, wet or dry FGD 

technology must be operated “at all times.” The commenters state the EPA should clarify that this 

requirement is not intended to disqualify EGUs that experience SO2 control device malfunctions or that 

must bypass controls during the initial portions of startups or to perform maintenance (which generally

require bypass of the entire control unit). The commenter states that for units without a bypass stack, any

resulting emissions would be monitored in the main stack with the SO2 CEMS; for units with a bypass 

stacks, temporary bypass might be necessary during a malfunction or to perform necessary maintenance 

to minimize periods of malfunction. According to the commenter, either way, as long as the SO2

emissions are accounted for those emissions will reflect the potential for higher HCl as well, and any

unit complying with the 30-day rolling average SO2 limit will achieve the necessary control for HCl

(i.e., the acid gas HAP). Thus, the commenters believe the EPA should clarify that the “at all times”

requirement does not apply to periods of malfunction, or to the temporary use of a bypass stack during 

periods of malfunction or maintenance, provided SO2 emissions are accounted for and the applicable 

standard is met.

Commenter 17752 states the EPA must clarify in section 63.9991(a)(1)(iii) that “at all times” is intended 

to disqualify EGUs that operate SO2 controls intermittently, and not to disqualify EGUs that experience 

SO2 control device malfunctions or that must operate without control devices during periods of EGU 

startup and shutdown.

Commenter 17714 states that the EPA should clarify that operation of FGD technology is only required 

for periods when the affected unit is operating. Commenter 17714 states the requirement to operate the 

APCD “at all times” should include provisions to follow manufacturer’s recommendations regarding 

when APCD operation is to be initiated and/or curtailed during startup/shutdown of the unit.

Commenter 17885 states that for the alternative SO2 limit, the EPA should qualify that that “at all times”

is not intended to disqualify units that experience control malfunctions or that bypass during 

startup/shutdown.

Comment 7: Commenters 18539 and 19120 note that section 63.9991 (a)(1)(iii) indicates that the FGD

must be operated at all times in order to qualify to use the alternate SO2 limit to demonstrate compliance 

with the acid gas HAP emission limitation. The commenters believe that if a unit can demonstrate 
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compliance with the applicable SO2 limit based on monitored emissions from the bypass and the 

scrubbed stack, a source should be allowed to exhaust to the bypass stack, at least, on a limited basis, as 

many of these stacks are already equipped with SO2 CEMS. One commenter notes that exhausting to the 

bypass stack is a necessary option in many cases, and provides four examples. 

Comment 8: Several commenters (17800, 17868, 18428) believe the EPA should make clear that this 

requirement in section 63.9991(a)(1)(iii) is intended to disqualify EGUs that operate SO2 controls 

intermittently, and not to disqualify EGUs that experience SO2 control device malfunctions or that must 

turn off controls to perform maintenance. The commenters note the higher SO2 recorded by the CEMS

during such periods will reflect the potential for higher HCl as well, and as long as the SO2 CEMS meets 

the surrogate standard for HCl these FGD off periods should not disqualify an EGU from using an SO2

as a surrogate. The commenters suggest the EPA make clear that the existence of a bypass stack does 

not disqualify an EGU from complying with the standard. 

Comment 9: Commenter 17886 supports the option to use SO2 CEMS to comply with a surrogate SO2

limit; however, the commenter believes use of a bypass stack during startups or malfunctions as part of 

good engineering and maintenance should not disqualify an EGU from this option. The commenter

suggests the EPA could require sources to account for these periods as provided in 40 CFR section 

75.16(c)(3), which requires use of a maximum potential value for each hour when the bypass stack is in 

use.

Comment 10: Commenter 18037 does not support the requirement that SO2 controls must be operated 

at all times if the SO2 surrogate is selected. The commenter believes that so long as a facility complies 

with SO2 emissions limits, operators should have the flexibility to operate SO2 controls in any mode to 

meet the compliance limit. The commenter recommends that the EPA remove the continuous control 

requirements regarding SO2 from the proposed rule. The commenter believes this additional requirement 

is superfluous if SO2 is a reasonable surrogate, and if facilities monitor SO2 continuously using reliable 

CEMS. The commenter believes an EGU that demonstrates compliance with SO2 limits, but whose SO2

controls are not in continuous operation, should not be considered in violation of the rule.

Comment 11: Commenter 17909 suggests the EPA should allow a 12-month rolling SO2 limit and 

clarify that FGD bypass is allowed during times of FGD forced outage. The commenter believes these 

changes would allow very limited continued operation through the bypass during upset conditions. 

Comment 12: Commenter 18023 believes that for PC units, the EPA should allow a scrubbed unit to 

bypass for a short time and allow the source to use the SO2 monitors in the bypass stack. As written, the 

rule appears to require a unit with the ability to bypass to install an HCl CEMS or otherwise monitor 

HCl on the bypass stack. If a unit that bypasses controls for a short period of time is capable of meeting 

the MACT SO2 limit, then scrubber bypass should be allowed. The commenter believes there is no 

environmental justification for penalizing these units.

Response to Comments 6-12: In the final rule, the EPA has clarified the “at all times” language. The 

intent is that the FGD be operated during all boiler operations and not operated intermittently, 

seasonally, or on some other non-fulltime basis. Thus, this alternate limit is allowed even if bypass may

occur during malfunction, but sources may be subject to penalties or other action if the malfunction 

causes the source to not comply with the requirements of the standards. We have established work 

practice standards for periods of startup and shutdown, as those terms are defined in the final rule, and 

the use of the FGD system must be in according with the work practice standards during those periods 

(i.e., the system must be engaged before coal or residual oil is burned in the boiler unit).
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4. SO2 as surrogate.

Comment 13: Commenter 17730 agrees with the proposal by the EPA to use SO2 as a surrogate as one 

of the options for measuring the acid gases category of HAP. The commenter also appreciates the 

proposals reliance on the SO2 CEMS as the basis of ongoing compliance with the requirements. The 

commenter believes SO2 emissions were well correlated with the acid gases in the analysis of the EPA 

ICR test data. SO2 CEMS are used by the commenter to measure the emissions of SO2, and the 

commenter believes they produce accurate emission estimates.

Comment 14: Commenter 17758 believes there is no basis for testing of the surrogate SO2 at a unit that 

is complying with the HCl standard or for HCl emissions testing at a unit with HCl CEMS. For example, 

states the commenter, proposed section 63.10006(h) requires EGUs “without SO2 CEMS but with 

installed systems that use wet or dry flue gas desulfurization technology” to conduct “all applicable 

performance tests for SO2 and HCl emissions” at least every year and to “conduct SO2 emissions 

testing” at least every month. The commenter suggests the EPA make clear that these provisions do not 

apply to EGUs with HCl CEMS.

Comment 15: Commenter 17383 supports the use of SO2 CEMS as a surrogate monitoring technology 

for HAP acid gases.

Comment 16: Several commenters (19536, 19537, 19538) endorses SO2 CEMS methods to determine 

compliance, and believes they should be required, rather than presented as an option.

Comment 17: Commenter 17621 believes given the use of pulsed fluorescence analyzers, it is 

reasonable to expect that equipment will be available to measure SO2 in the flue gas at the proposed 

alternative MACT limits for new and existing coal-fired EGUs (approximately 0.04 lb/MMBtu and 0.2 

lb/MMBtu, respectively), even accounting for the dilution extractive sampling systems. The commenter

notes that at the emission levels typically found in power plants, the impact of sample line losses has not 

been an issue and operators have minimal problems meeting the 7.5% relative accuracy; however, when 

trying to measure very low concentrations, sample line losses may make the RA criterion more difficult 

to meet.

Comment 18: Commenter 17725 believes there is no value in performing Cylinder Gas Audit (CGA) 

tests quarterly on SO2 analyzers with span values less than 30 ppm SO2 that are currently certified to 

report under 40 CFR part 75 rules. The commenter recommends the EPA add a subsection to section 

63.10010(e) that clearly states that 40 CFR part 75 data substitution procedures and bias adjustment 

factors are not to be used to calculate the 30 boiler operating day average SO2 emission rate.

Comment 19: Commenter 17886 recommends the EPA clarify that provisions in section 63.10006(k) 

do not apply to EGUs with SO2 CEMS that are used to meet requirements pertaining to the alternative 

acid gas limit.

Comment 20: Commenters 17775 and 17868 recommend the EPA clarify the subsequent performance 

testing requirements for units without HCl CEMS in proposed section 63.10006(h) and (i). The 

commenters suggest the EPA make clear that the provisions for EGUs “without HCl CEMS” do not 

apply to EGUs with SO2 CEMS, and must remove the initial testing requirement for HCl. The 

commenters believe there is no basis for testing of HCl at a unit that is complying with the surrogate 

SO2 limit and proposed Tables 1 and 2 clearly provide sources the option of meeting an HCl or an SO2

standard. Commenter 17775 also believes the EPA does not explain what it means by EGUs “without 
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SO2 CEMS” or what significance those SO2 CEMS have for EGUs not choosing to comply with the 

surrogate SO2 limit. The commenter suggests that virtually all coal-fired EGUs covered by this proposed 

rule already have SO2 CEMS installed as a result of other regulatory programs, like the Acid Rain 

Program.

Commenter 17775 notes proposed section 63.10006(j) requires EGUs “without HCl CEMS but with 

HCl emissions controls” to test for HCl at least every month, and proposed section 63.10006(k) requires 

EGUs “without HCl CEMS and without HCl emissions controls” to test for HCl at least every other 

month. The commenter notes there is nothing in the proposal to exempt EGUs with SO2 CEMS, but not 

HCl CEMS, from proposed requirements applicable to EGUs “without HCl CEMS.” The commenter

also notes proposed section 63.10005(a) also specifically requires HCl testing initially for any EGU that 

uses “a continuous monitoring system that measures a surrogate for a pollutant (e.g., an SO2 monitor).”

Comment 21: Commenter 17881 notes for those units with an SO2 CEMS, the concept of an additional 

performance test every 5 years makes little sense, as such units are required to determine a new 30-day

rolling average emission rate for every operating day following the initial 30-day compliance test.

Response to Comments 13 - 21: The EPA appreciates the support for the use of SO2 as an alternate 

equivalent standard and reliance on an SO2 CEMS. The EPA also agrees that sections 63.10005 

and 63.10006 need to be clarified to be consistent with Table 5 – if an HCl CEMS is used, the SO2

testing requirements do not apply, and vice versa.

5. Part 75 concerns.

Comment 22: Commenter 17722 supports inclusion of 40 CFR part 75 monitoring provisions for SO2

CEMS; however, the commenter does not support the addition of new part 75 requirements. The 

commenter cites section 63.10010(e)(6), which requires additional provisions not currently needed for 

an SO2 CEMS under part 75. The commenter notes that as a comprehensive monitoring rule, part 75

provides certified data within the means of the technology. The commenter notes these additional 

monitoring requirements were exempted from certain monitor ranges because the monitoring technology

is unable to perform the EPA methods either due to monitor limitations or due to protocol limitations. 

The commenter believes since current part 75 SO2 collected data is accepted by the EPA as credible 

evidence of compliance with Acid Rain provisions, it should also be acceptable to the EPA for 

demonstration of compliance with the MACT standard without creating additional requirements as listed 

in section 63.10010(e)(6).

Comment 23: Several commenters (17725, 18014, 18498) suggest that while the rule allows the use of 

Part 75 SO2 CEMS, it includes additional QA/QC requirements that will be problematic. The 

commenters reference section 63.10010(e)(6)(i), which states the operator “must perform the 7-day

calibration error test required in Appendix A to part 75 on the SO2 CEMS whether or not it has a span of 

50 ppm or less.” The commenters do not understand what this requirement will accomplish as the 

majority of part 75 affected sources has completed initial certification years ago and has been collecting 

“quality-assured” data for years.

Comment 24: Commenters 17790 and 17820 have concerns with the linearity and 7-day calibration 

error test requirements contained in the proposal that are not required under part 75. Commenter 17820 

believes requiring these tests will complicate compliance for EGUs currently complying with part 75

and without providing any added accuracy to the measurement. Commenter 17790 suggests these 

requirements be removed for companies that plan to use their part 75 SO2 CEMS. The commenter notes 
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CEMS with a span less than 50 ppm are exempt from the 7-day calibration error and CEMS with a span 

less than 30 ppm are exempt from the quarterly linearity testing and that CEMS are meeting the 7-day

calibration error specification on a daily basis during their daily calibration. The commenter also notes 

the EPA also determined that for CEMS with spans less than 30 ppm, the linearity testing was not 

significant at the lower emission level. The commenter notes that the EPA is requiring a calibration gas 

at a level equivalent to the emission limit, even if that means adding a fourth calibration gas level, and 

that adding this calibration gas level will cause significant cost and significant modifications to Data 

Acquisition and Handling Systems (DAHS). In addition, the commenter notes part 75 already has 

existing requirements to ensure the monitor span value is set at a level to cover the range of the unit’s 

operating emissions.

Comment 25: Commenter 17873 believes the increased QA/QC requirements for SO2 CEMS as a 

surrogate for HCl emissions goes well beyond what the EPA has previously required in either 40 CFR

parts 60 or 75 monitoring requirements, and the EPA does not provide adequate justifications for 

increasing these QA/QC requirements beyond what part 75 requires. The commenter believes the fourth 

linearity calibration injection standard is overly burdensome to the industry.

Comment 26: Commenter 17775 believes no reason was provided for the requirements in the proposed 

section 63.10010(e)(6)(i) and (ii) that allows use of an SO2 CEMS meeting part 75, but imposes linearity

and 7-day calibration error test requirements not required under part 75. The commenter cites 67 FR

40394 and 40408-09 (June 12, 2002) in which the EPA specifically exempted CEMS with spans of 50 

ppm or less from the 7-day calibration error requirement under part 75 because it was no longer 

necessary. The commenter also cites 63 FR 28032 and 28061/3 (May 21, 1998) where the EPA 

specifically exempted spans of 30 ppm or less from the linearity requirement in acknowledgment of the 

fact that the tests were no longer significant at low emission levels. The commenter suggests if these 

tests are no longer relevant or significant, there is no purpose in requiring them in this rule and that 

requiring the test will complicate compliance for EGUs currently complying with part 75 without 

providing any added accuracy to the measurement.

Comment 27: Commenters 17775 and 17820 believe the EPA provides no rationale for this added 

requirement in proposed section 63.10010(e)(6)(iii) that requires a calibration gas at a level equivalent to 

the emission limit, even if that would result in a fourth calibration level. The commenters note part 75

already includes provisions to ensure that the analyzer span value is set at a level that will result in use 

of calibration gases that are consistent with the emissions range over which the unit operates, citing 40 

CFR part 75, Appendix A section 2.1.1. The commenters believe there is nothing to be gained by 

potentially adding a fourth calibration gas, and since existing SO2 CEMS and the accompanying DAHS 

have not been certified using a fourth calibration gas, and are not currently designed to support a fourth 

calibration gas, this new requirement would unnecessarily increase costs for SO2 CEMS. The 

commenters believe the EPA must remove these requirements, or issue for comment a proposal that 

provides some rationale for requiring these tests in this context.

Comment 28: Commenter 17821 strongly opposes the requirements in section 63.10010(e)(6)(iii) to 

introduce a fourth concentration level of calibration gases during the initial and subsequent quarterly

linearity audits. The commenter states the EPA appears to be imply that more accurate measurements 

would be obtained by the SO2 monitoring system if the fourth level of calibration gases was added; 

however, the commenter believes no additional accuracy would be obtained by the introduction of an 

additional gas injection level, and it would simply consume additional resources and slow down a test 

that already takes 2-3 hours to complete. The commenter also believes it would also necessitate the 

invalidation of hourly data during the injection of the linearity gases. The commenter notes that by 
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adding the fourth gas injection level, sources would be forced to inject gases for approximately 40 

minutes (10 minutes for each of the four gas concentrations); when the 5-7 minutes required to reach a 

stable stack gas reading are added to that total, sources would not collect enough valid stack 

measurement minutes within an hour to validate the hour. The commenter therefore believes this process 

would result in approximately 2-3 hours of invalid data each and every quarter.

Commenter 17821 additionally states the alternative limit when using an SO2 emissions system for 

compliance with an HCl limit under these proposed rules is defined in terms of lb/MMBtu. SO2 and 

diluent monitors (O2 or CO2) are audited for linearity in ppm concentration or percent concentration, not 

as a value expressed in lb/MMBtu. The commenter believes to require a source to evaluate an SO2 or 

diluent monitor for linearity at a fourth concentration level “nominally at the concentration level 

equivalent to the applicable emission limit” would be extremely subjective. The commenter states that 

concentrations of SO2 and diluent gases can change as the unit load changes due to the amount of excess 

air being supplied to boilers at various loads. This variability in the air excess flow would result in a 

change to the nominal equivalent values for the test.

Commenter 17821 continues to state that sources currently using SO2 monitoring systems in compliance 

with 40 CFR 75 are required to develop span ranges that capture the majority of the hourly averages 

between 20% and 80% of the span range. According to the commenter, with this requirement in place, 

most sources are utilizing span ranges that are set to capture the majority of nominal readings at 

approximately 50% of that span range. 40 CFR 60 and 40 CFR 75 cylinder gas audits and linearity 

audits already require a source to inject a gas in the range of 50% to 60% of the span range of the 

monitor; therefore, an injection of audit gas in the “nominal” range of measurement is typically

performed. Additionally, states the commenter, all sources equipped with SO2 emission control systems 

utilize dual range SO2 monitoring systems (as required by both 40 CFR 60 and 40 CFR 75). The 

commenter believes performing a linearity audit with a fourth injection level on the high range of the 

SO2 monitor at the “nominally at the concentration level equivalent to the applicable emission limit”

would be meaningless as the high range of the monitor is not intended to measure low level 

concentrations but is designed to measure higher concentrations in the event of a malfunction or upset of 

the SO2 emission control system. The commenter believes very low concentrations of SO2 will dictate 

very low range measurement on these dual range analyzers, which will make passing a linearity test very

difficult. The commenter states that the standard is percent of the reference value, which may put the 

error limits inside the accuracy standards for the reference gas. The commenter states that part 75

provides a waiver for linearity testing of ranges less than 50 ppm and an alternate standard for ranges 

less than 200 ppm. The commenter recommends that these be allowed for the SO2 surrogate 

measurement as well, which will also serve to avoid maintaining separate databases for CSAPR and 

MACT purposes.

Comment 29: Commenter 17881 believes the restrictions and caveats placed on the use of part 75 SO2

CEMS at section 63.10010(e)(6), the provisions of paragraphs (i) and (ii) would require that 7-day

calibration error tests and linearity tests be conducted on low-level emissions monitoring systems (i.e., 

systems with span values of less than 50 ppm or 30 ppm, as applicable) make little sense, as the EPA has 

already evaluated the utility of conducting such tests under 40 CFR part 75 and concluded that these 

tests were not appropriate for level-level emissions monitoring systems.

Commenter 17881 believes the provisions of section 63.10010(e)(iii) which would also require that at 

least one calibration gas level used for the linearity tests have the same nominal concentration level 

equivalent to the applicable emission limit (and that a fourth such gas be used if none of the required 

low, mid or high gases meet this requirement) are nonsensical, as the vast majority of part 75 SO2
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CEMS installed on units with add-on SO2 control devices will be dual-range instruments. As such, states 

the commenter, the high level range of these instruments will generally be reflective of SO2 emissions 

without add-on SO2 controls, which will surely be much higher than the applicable SO2 emission limit, 

and thus, the SO2 CEMS will be calibrated over an aggregate (i.e., low and high) measurement range 

which encompasses the applicable SO2 emission limit, and this should be adequate to ensure the 

accuracy of the SO2 CEMS measurements at or near the applicable emission limit. The commenter

suggests a more reasonable caveat (in lieu of section 63.10010(e)(6)(iii)) would be a prohibition on the 

use of a default high range value as allowed under 40 CFR part 75, Appendix A, section 2.1.1.4(f) for 

those dual span units with SO2 emissions controls. According to the commenter, this would essentially

ensure that any EGU which elects to comply with a surrogate SO2 limit (which inherently requires addon SO2 controls) has quality assured SO2 measurement ranges which encompass the applicable SO2

emission limit.

Commenter 17881 believes the concept of a calibration gas with a concentration nominally equivalent to 

the applicable SO2 emission limit is unworkable, as the SO2 emission limits are not inherently expressed 

on a concentration basis (i.e., are expressed as lb/MMBtu or lb/MWh), are assessed on a 30-day rolling 

average basis, and would be influenced by boiler operating loads and the resulting diluent gas levels and 

electrical outputs. The commenter provides an example for a subbituminous boiler and questions that 

given the concentration equivalent of a given SO2 emission limit is influenced by boiler operating 

conditions, how could a nominally equivalent concentration even be determined with any level of 

certainty. The commenter also questions what is nominally equivalent in the context of the example 

provided.

Comment 30: Commenter 17902 believes section 63.10010(e)(6)(i) thru (iii) will require additional 

calibration error and linearity check tests that are not currently required under 40 CFR part 75 and are 

not necessary and may not even be feasible due to instability of calibration gases at lower concentration 

levels. The commenter recommends that the final rule should not require additional SO2 CEMS

requirements beyond the QA/QC requirements and guidance in the existing federal regulations for 40 

CFR part 75.

Comment 31: Commenter 17868 suggests the EPA allow all part 75 exceptions. The commenter notes 

proposed section 63.10010(e) allows use of an SO2 meeting part 75, but disallows the linearity and 7-

day calibration error test exceptions and requires a calibration gas at a level equivalent to the emission 

limit (even if it is a fourth level).

Comment 32: Several commenters (17775, 17800, 17811, 17868, 18014) note that proposed section 

63.10021(a)(13) sets out the ongoing requirement for SO2 CEMS, which are similar to proposed section 

63.10010(e), except this provision does not reference the part 75 option. One commenter suggests the 

EPA reference the part 75 alternative in this provision as well, or consolidate the two provisions.

Comment 33: Commenters 17725 and 18498 note that section 63.10010(e)(6)(ii) states that one “must 

perform the linearity check test required in appendix A to part 75 on the SO2 CEMS whether or not it 

has a span of 30 ppm or less”; however, this requirement ignores the EPA’s previous acknowledgement 

that a linearity check “begins to lose its significance” at span values less than or equal to 30 ppm as 

discussed in the proposed 1998 revisions to 40 CFR part 75. One commenter provides an example and 

proposes the requirement should be removed and replaced with the part 75 exemption.

Comment 34: Several commenters (17725, 18014, 18498) reference section 63.10010(e)(6)(iii), which 

states “the initial and quarterly linearity checks required under Appendix B of Part 75 must include a 
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calibration gas (at a fourth level, if necessary) nominally at a concentration level equivalent to the 

applicable emission limit.” The commenters see no reason to introduce a fourth calibration gas and the 

term “nominally” is not clearly defined. The commenters state that part 75 has requirements in place to 

ensure that the analyzer span is set to obtain accurate and representative data. Commenter 17725 notes 

this requirement will significantly increase SO2 CEMS operating cost as the system will need to be 

modified to include an additional regulator, the DAHS will need to be reprogrammed, and costs will be 

incurred to purchase a fourth calibration gas (including monthly cylinder demurrage).

Comment 35: Commenter 17752 requests the EPA clarify what “if necessary” means in section 

63.10010(e)(6)(iii) in regards to conducting linearity checks at a fourth level. The commenter believes if 

an EGU qualifies for and elects to use a SO2 CEMS, yet has a state limit that is more restrictive, there 

would be no benefit to having a fourth level at the proposed applicable emission limit. According to the 

commenter, any emission limit will reside in the lower range of a dual range analyzer, which is typically

a narrow range to begin with. The commenter believes this requirement is “not necessary” and would 

only add complications and costs to an already accurate and sound system.

Comment 36: Commenter 17821 supports the EPA’s inclusion of the option to operate, maintain, and 

quality assure an SO2 monitoring system under 40 CFR 75 if the source operates such a system for 

compliance with Acid Rain. 

Comment 37: Commenter 17886 suggests the EPA harmonize the SO2 CEMS requirements with part 

75 as most if not all EGUs should already have these systems in place meeting part 75 requirements. 

The commenter believes failure to harmonize monitor requirements in past regulations has created 

confusion and additional costs for both the EGU and the EPA.

Comment 38: Commenter 18014 states that in Table 5 for the SO2 CEMS (Item 5) in the “using”

column for Item a, the table should include the alternative to use Part 75 requirements for “installation”, 

“operate”, and “maintain CEMS.” (See section 63.10010(e).) The commenter also notes the table 

references section 4.1.3 and 5.3 of Appendix A to the subpart, but SO2 is never mentioned in Appendix 

A.

Comment 39: Commenter 17881 objects to subjecting part 75 monitoring systems to the data reduction 

procedures in section 63.10010(e)(4), as these procedures are in part inconsistent with the part 75 data 

reductions procedures at section 75.10(d). The commenter cites the requirements from section 63.8(g)(2) 

and section 75.10(d)(2), noting that while the language appears similar, it could still result in different 

data validation cases where maintenance or quality activities are conducted in a given hour and only two 

data quadrants are used to validate the hour. For example, states the commenter, if an unit operated for 

60 minutes in a given clock hour and collected valid 1-minute values at minutes 14 and 15 due to quality

assurance activities, such an hour would be valid under the provisions of section 63.10010(e)(4) but 

invalid under the 40 CFR 75.10(d)(1) provisions. The commenter believes forcing part 75 subject 

sources to maintain two separate sets of data based upon two different validation regimes is overly 

burdensome and unwarranted, and suggests part 75 SO2 CEMS should not be subject to the provisions 

of section 63.10010(e)(4).

Comment 40: Commenter 18014 suggests the EPA should add a subsection to section 60.10010(e), 

which clarifies that bias adjusted data and part 75 missing data shall not be used in calculating the 30 

boiler operating day average SO2 emission rate. According to the commenter, although this is discussed 

in Appendix A to subpart UUUUU for Hg CEMS (Reference Appendix A sections 1.4 and 4.1.2.4), this 

data exclusion is not clearly stated for SO2 CEMS. 
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Response to Comments 22 - 40: After reviewing the comments and assessing the need for a “nominal”

gas for the linearity test, the EPA has removed this requirement from the final rule while retaining a 

requirement for a linearity check even for low SO2 concentrations. Sources can already report linearity 

tests for these units within the context of the existing ECMPS reporting without triggering any critical 

errors regardless of the test results. This test can be accommodated within the current framework 

without causing issues for part 75 reporting. The 7-day calibration error test is removed as unnecessary. 

As noted elsewhere in this response to comments document, the final rule confirms that the bias 

adjustment and substitute data provisions under part 75 do not apply when using an SO2 CEMS to 

demonstrate compliance with the SO2 emission limit in this rule.
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5A09 - Testing/Monitoring: Application of HCl CEMS

Commenters: 16513, 17383, 17402, 17621, 17622, 17627, 17638, 17681, 17696, 17704, 17705, 17715, 

17716, 17718, 17724, 17725, 17728, 17729, 17756, 17769, 17775, 17790, 17795, 17800, 17813, 17820, 

17821, 17851, 17868, 17881, 17886, 18014, 18037, 18443, 18539, 19114, 18023

1. HCl CEMS is not proven technology.

Comment 1: Numerous commenters (17383, 17402, 17681, 17696, 17704, 17705, 17715, 17718, 

17724, 17728, 17729, 17627, 17638, 17769, 17775, 17790, 17795, 17813, 17820, 17868, 18037, 18443, 

18539, 19114, 18023) note concerns with HCl CEMS technology.

Comment 2: Commenter 17402 recommends that the EPA remove the HCl CEMS monitoring 

requirement from the proposed rule until HCl CEMS are proven technologies. The commenter states 

that EGU sources have limited experience with HCl CEMS, and limited information on the accuracy and 

long-term performance of such technologies as applied in the field. The EPA proposes an HCl standard 

equivalent to approximately 2 ppm, which the commenter believes is an extremely low performance 

standard for a new monitor to meet.

Comment 3: Commenters 17638 and 17681 state that there are no FTIR HCl CEMS currently in use in 

the U.S. on a coal-fired EGU.

Comment 4: Commenter 17813 does not believe HCl CEMS are in production and questions if there 

are any HCl CEMS that work.

Comment 5: Commenter 17696 states that while the EPA suggests that FTIR CEMS may be 

appropriate to monitor HCl emissions pending promulgation of a performance standard specific to HCl

CEMS, 76 FR 25031, FTIR does not have a track record of consistently and reliably measuring HCl

levels expected in the stack gas of EGUs.

Comment 6: Commenter 17704 believes the technology for HCl CEMS is not fully developed or 

proven for EGUs. The commenter understands that stack testing for HCl every month is offered as an 

alternative, but scheduling testing that often is difficult and not practical; therefore, that really only 

leaves the choice of HCl CEMS. The commenter believes that HCl CEMS have been used to measure 

higher concentrations for other industries; however they are not proven at the low levels proposed in the 

rule.

Comment 7: Commenter 17705 believes the use of HCl CEMS has been attempted primarily on dry

stacks, and that HCl CEMS may not be available for use on wet stacks, noting concern that many EGUs

plan to use wet FGD technology to comply with the proposed acid gas standards. In addition, states the 

commenter, information provided by EPRI indicates that the proposed HCl standard may be lower than 

the quantitation limit of the two types of instruments currently available for HCl measurement. If the 

EPA retains a numeric HCl standard in the final rule, the commenter encourages the EPA to take a 

leadership role in assuring that the monitoring methodology that is required is actually available for use 

across a broad range of plant configurations and can reliably demonstrate compliance with the standard.

Comment 8: Several commenters (17718, 17627, 17715, 18037, 18539) state HCl CEMS currently are 

not commercially available or adequate for in-stack measurements and likely will not be available by the 

compliance date of the rule. The commenters believe sources will be forced to either take a fuel limit or 
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an operating parameter limit. The commenters state the fuel analysis limit is impractical as it relates to a 

coal-fired facility because of the variability that is inherent in coal, and that it will be impossible to 

control fuel deliveries in such a manner as to negate the possibility of burning coal with chlorine content 

above that which was used during compliance testing.

Comment 9: Commenters 17715 and 19114 state HCl is not routinely monitored by EGUs, and there is 

little stack test data beyond that collected by the EPA during the ICR process. The commenter states that 

no HCl continuous monitors were used to collect any of the data used by the EPA to establish the HCl

standard, and there is no information about HCl emissions at conditions other than normal full load 

operations, but nevertheless, the EPA proposes to rely on continuous HCl monitors as its preferred 

monitoring method for compliance. The commenter believes it is imprudent for the EPA to set forth a 

monitoring standard for which there has been very limited experience in the relevant industry and for 

which the technology has not been commercially developed. The commenter notes that the EPA states 

that FTIR has been shown to be adequate for in-stack measurements. However, the commenter states 

FTIR has been shown to be unreliable in stack applications, especially at emission rates as low as the 

EPA has proposed. The commenter recommends the EPA should not dictate FTIR as the technology to 

be utilized.

Comment 10: Several commenters (17383, 17724, 17820) are concerned that HCl monitors are not a 

proven option in the electric utility industry. According to the commenters, while these monitors exist 

and have operated on other sources, the electric utility sector presents distinct challenges. Commenter

17724 questions the need for SO2 monitoring in addition to parametric monitoring associated with 

scrubber operation. 

Comment 11: Commenter 17728 believes HCl CEMS are not at this point a viable option, as the 

technology remains unproven. The commenter expresses concerns about the ability of HCl CEMS to 

accurately measure compliance with the proposed standard.

Comment 12: Several commenters (17728, 17775, 17820) believe the EPA must consider the 

limitations of compliance measurements when setting enforceable standards.

Comment 13: Commenters 17718 and 17729 state at the EPA emission rate of 0.002 lb/mmbtu, the HCl

in the flue gas will be less than 2 ppm. The commenters believe that currently, HCl CEMS are not 

capable of measuring accurately at concentrations below 2 ppm.

Comment 14: Several commenters (17775, 17868, 17820) are concerned about the ability of HCl

CEMS to accurately measure compliance with the proposed standard because the limit is at or near the 

detection limit for current HCl CEMS technology.

Comment 15: Commenter 17790 states that while there are limited HCl CEMS installations, they are 

not a proven technology like SO2 or NOX CEMS. The commenter also suggests there are significant 

technology obstacles in applying HCl CEMS to a wide variety of sources with different temperatures, 

moisture and gas conditions. The commenter notes its own experience with significant problems with 

Hg CEMS, the heated umbilical (a critical part of the CEMS) is unproven at extended lengths (over 200 

feet).

Comment 16: Commenter 17769 believes there are valid technical concerns regarding the feasibility

and commercial acceptance of the use of HCl CEMS, particularly that the reactivity of HCl, makes 

obtaining reliable measurements a difficult task. The commenter identifies the three basic HCl CEMS
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configurations and discusses technical issues with each. The commenter describes sample conditioning 

problems associated with extractive systems, difficulties with representative measurements and 

operation and maintenance (O&M) problems for in-situ instruments, and NH3 interactions with HCl

creating problems for dilution sampling systems. The commenter also discusses the MCS 100 E Multi 

Component Analyzers as the most widely employed and presumably most advanced HCl CEMS and 

notes issues with detection limits associated with the use of the unit. The commenter believes there are 

substantial technical questions regarding the use of HCl CEMS, and the EPA should not require them as 

part of the EGU NESHAP.

Comment 17: Commenter 17795 believes that HCl CEMS are not an option at the proposed levels with 

a certification performance specification that has a known negative bias. For existing units, states the 

commenter, an HCl standard of 0.002 lb/MMBtu equates to 1.2 ppm (assuming a heat rate of 10,000 

Btu/kW). The commenter believes while this value is above the detection limit it will be extremely

challenging to demonstrate compliance through a continuous HCl emissions monitor. For example, 

states the commenter, the lowest achievable emission rate (LAER) for new combined cycle combustion 

turbines is approximately 2.0 ppm of NOX. Unlike HCl, NOX is not water soluble or temperature

dependant prior to analysis. The commenter notes their industry has more than 30 years of experience 

monitoring NOX and limits of 2.0 ppm are challenging to demonstrate on a continuous basis. According 

to the commenter, measuring a highly water soluble compound that is expected to be less than 1.2 ppm

where water is a large part of the sample matrix will be problematic and may simply result in unreliable 

data.

Comment 18: Commenter 18443 believes the cost and accuracy of HCl CEMS do not justify the 

difference in emission reduction measurements produced by a performance test and continuous 

compliance metrics. The commenter suggests HCl CEMS were developed for sources with much greater 

HCl emissions than EGUs and as such do not provide precision and accuracy at the range they are 

expected to operate. Additionally, states the commenter, the HCl standard does not take into account 

chlorine variability in coal. The commenter recommends instead of effectively mandating HCl CEMS, 

EPA should allow sources to comply with HCl limits through an annual performance test, in conjunction 

with documented process metrics.

Comment 19: Commenter 19114 notes that HCl is not routinely monitored by electric generating units, 

and there is little stack test data beyond that collected by the EPA during the ICR process. No HCl

continuous monitors were used to collect any of the data used by the EPA to establish the HCl standard, 

and there is no information about HCl emissions at conditions other than the limited data available for 

normal full load operations. The commenter believes it is imprudent for the EPA to set forth a 

monitoring standard for which there has been very limited experience in the relevant industry and for 

which the technology has not been commercially developed. The EPA states that FTIR has been shown 

to be adequate for in-stack measurements. However, FTIR has been shown to be unreliable in stack 

applications, especially at emission rates as low as the EPA has proposed. Given these (and other) 

uncertainties regarding FTIR performance, the commenter believes the EPA should not dictate FTIR as 

the technology to be utilized. The commenter provides several examples of concerns expressed by 

agencies regarding the use of HCl CEMS, including excerpts from state agencies in their Response to 

Comments document that supported the issuance of final air permits.

Comment 20: Commenter 18023 believes there is only one HCl CEMS in operation in the U.S. on a 

coal-fired power plant stack and it is a tunable diode laser (TDL) based device. The commenter states 

TDL is not the EPA’s preferred FTIR technology, so there is no performance specification available for 

it. The commenter states that this existing TDL device also uses the open path measurement approach 
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and, as such, does not lend itself to daily QA/QC procedures typical of the power plant CEMS

equipment that meets Part 75 requirements. According to the commenter, the current technology (FTIR) 

used for stack testing is not very rugged; sample transport issues may require HCl CEMS analyzers to be 

stack mounted, which will provide a maintenance and availability challenge. According to the 

commenter, most analyzers require stable temperature and humidity that would be difficult to manage 

on a stack exposed to ambient or above ambient temperatures.

Comment 21: Commenter 18023 suggests HCl CEMS must work at extremely low concentrations to 

meet the proposed MACT standard. The commenter states that NIST does not have any HCl standards, 

and the lowest concentration of EPA Protocol HCl gas advertised by a gas vendor is 25 ppm. The 

commenter states that that value is based on gravimetric (weight) traceability, and converted to ppm, the 

limit in the proposed rule is approximately 1 ppm. According to the commenter, this limit may be below 

the quantitation limit (QL) of the available instruments and thus would not be measureable.

Response to Comments 1-21: The EPA disagrees with commenters’ contention that continuous HCl

monitoring is premature or not available for the measurement at the limits set in the proposed standard. 

We understand from vendors of HCl CEMS that they have been used on source categories such as 

municipal waste combustors, cement plants, and biomass and other power generation units. We have 

reviewed HCl CEMS vendor technology claims and found sufficient capability to support this rule 

requirement. We are presently engaged with representative stakeholders to develop a generic 

performance specification for HCl CEMS. The HCl Performance Specification is scheduled for 

completion in time to be responsive to this rule promulgation. To use the HCl CEMS option at the start 

of the program, the EPA has included a comparable performance specification PS 15, using a Fourier 

Transform Infrared (FTIR) analyzer, which could be employed in the event that the issuance of PS for 

HCl CEMS is delayed. Should an EGU owner or operator be concerned about using HCl CEMS as a 

compliance demonstration method, other options exist for acid gas HAP monitoring including: 1) using 

HCl CEMS for compliance, 2) seeking approval for an alternative HCl monitoring procedure through 

section 63.7 f., 3) monitoring SO2 continuously as a surrogate for HCl at facilities equipped with wet 

scrubber control technology for SO2, and 4) frequent reference method testing. Including these options in 

the rule provides flexibility to adopt CEMS monitoring options as the technology continues to mature 

and EPA performance specifications become available.

Comment 22: Commenter 17622 states they recognize the reluctance of the utility industry to proceed 

with plans to measure HCl because 1) They know it can be difficult to measure in low concentrations; 2) 

The technologies used for it such as FTIR, TDL or Perma Pure driers with GFC analyzers are unfamiliar 

to them; 3) The EPA has not published performance specifications for HCl measurement leading to 

some uncertainty. The commenter believes that if electric generating facilities can identify a reliable, 

low-maintenance, affordable option for low level HCl measurement (0-10 ppm), they will adopt it more 

readily. The EPA should help try to prove this point out over the coming months.

Response to Comment 22: The EPA acknowledges that certain applications of HCl CEMS will require 

further demonstrations and advances for this technology and is currently working on HCl PS for 

technologies other than FTIR.

2. Concerns over lack of performance specification.

Comment 23: Multiple commenters (17402, 17638, 17681, 17696, 17716, 17728, 17729, 17769, 17800, 

17820, 17821, 17851, 17868, 17881, 17868, 17881, 17886, 18014, 18023) express concern that the 

agency has not made available performance specifications for HCl CEMS.
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Comment 24: Commenter 17402 states the absence of such requirements makes it difficult for regulated 

units to comment on how they might comply with the proposed QA/QC specifications in the context of 

the Utility MACT rule.

Comment 25: Commenter 17696 believes it is premature and inappropriate for the EGU NESHAP rule 

to specify the use of HCl CEMS given that the EPA has not yet promulgated a performance standard 

specific to HCl CEMS. Without the existence of an accepted performance specification for HCl CEMS

in advance of the compliance dates, the commenter believes EGUs cannot reasonably be expected to 

purchase and install HCl CEMS and rely on them for compliance determinations.

Comment 26: Several commenters (17716, 17820, 18014) state the EPA has developed no performance 

specification for non-FTIR based HCl CEMS. Table 5 lists PS 6, but the commenters believe PS 6 does 

not apply since it is for systems that measure pollutant emissions in units of mass per unit of time. The 

commenters state the lack of a performance specification for HCl CEMS (coupled with limited utility 

HCl CEMS operating experience, particularly for compliance near the detection limits of the systems) 

makes it difficult to provide meaningful comments.

Comment 27: Commenter 17729 recommends the EPA should not require compliance monitors for 

which an EPA performance specification does not exist.

Comment 28: Several commenters (17775, 17795, 17800, 17868) note that the EPA proposes to require 

certification of HCl CEMS according to PS 15 or PS 6. The commenters state that as the EPA 

acknowledges in the preamble, PS 15 applies only to FTIR CEMS. PS 6 applies to continuous emission 

rate monitoring systems (“CERM”), which measure mass emissions rate per unit of time, not

conventional CEMS. The commenters note FTIR CEMS is not a viable option and sources need a well 

documented HCl performance specification well in advance of the compliance date in order to evaluate 

and procure appropriate instrumentation. The commenters state that in order to provide an HCl CEMS

option, the EPA says “we expect to publish (a performance specification) prior to the compliance date of 

this proposed rule and to make it available to source owners and operators” (76 FR 25031). The 

commenters believe in the absence of an existing specification, the EPA should recognize in the rule that 

PS 15 does not apply to HCl CEMS.

Comment 29: Several commenters (17775, 17795, 17800, 17820, 17868) support the EPA’s decision to 

convene a workgroup of interested stakeholders to aid in development of an appropriate performance 

specification. The commenters suggest the EPA allow EGUs to petition the EPA for use of an 

alternative specification if none has been promulgated by the time EGUs need to make decisions about 

their compliance options.

Comment 30: Commenter 17868 notes they supports the option for use of HCl CEMS and urges the 

EPA to complete work on a reasonable performance specification.

Comment 31: Commenter 17886 recommends that the EPA make HCl CEMS monitoring requirements 

contingent upon issuance of an HCl CEMS performance specification, as an HCl CEMS Performance 

specification is not currently available and the EPA has set the proposed HCl limits near the detection 

level of current technology. The commenter also believes, since the proposed limits are lower than the 

quantification limits of current technology, HCl CEMS should only be used for purposes of CAM.

Comment 32: Commenter 17881 has generally heard that the FTIR technology associated with PS 16 is 

not a viable option at this point in time due to concerns about detection limits in EGU exhaust gas 
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matrices, potential measurement issues in wet stack environments, lack of low-level calibration 

standards, etc. The commenter suggests that until such time as the EPA has promulgated performance 

specifications for HCl and HF, the EPA should allow affected EGUs to petition for the use of an 

alternate performance specification. The commenter notes it is possible that new EGUs may face a 

compliance date as early as 1/1/2012, and believes it is highly unlikely that an HCl PS can be developed 

by that time. The commenter also notes it is not possible to comment on the QA requirements for HCl

CEMS when there is no performance specification available.

Comment 33: Commenter 17769 notes that there are no performance specifications or quality-assurance 

provisions for HCl CEMS and the commenter is not aware of any FTIR HCl CEMS currently in use in 

the U.S. on a coal-fired EGU. The commenter notes that currently no federal regulations require the use 

of HCl CEMS without express exemptions, alternatives and caveats. The commenter provides examples 

including the Portland Cement NESHAP, CISWI NSPS and the proposed NESHAP for Polyvinyl 

Chloride and Copolymer Production. The commenter cites several rulemakings in which the EPA 

expressed various reasons for its hesitation to require the use of HCl CEMS, including lack of data, 

significant costs, and lack of performance specifications. The commenter believes the EPA’s rationale 

for not adopting performance specifications (specifically, PS-13) is that the EPA could not demonstrate 

that an HCl CEMS would meet the specifications, citing 64 FR 52828, 52930. The commenter believes 

there is no certainty over the suitability and reliability of HCl CEMS and that the EPA must provide 

public notice and an opportunity for comment on any specifications prior to EPA requiring them as part 

of any rule.

Comment 34: Commenter 17821 encourages the EPA to allow the use of alternate HCl CEMS

performance specifications so the choice of HCl CEMS is not limited to FTIR monitoring systems. The 

commenter believes that because the FTIR is not a practical monitoring option, using an HCl CEMS is 

not a realistic option for companies to consider without another option. According to the commenter, 

therefore many sources would have to revert to either using SO2 as a surrogate, or to conducting stack 

testing at an unreasonable frequency. The commenter believes FTIR CEMS are difficult to calibrate and 

maintain. They typically require a level of expertise to set up, operate, and maintain that is far above the 

typical CEMS technician found at a power generation facility. The commenter notes that some states, 

including Indiana and Pennsylvania, have approved the use of alternate performance specifications for 

HCl CEMS on hazardous waste incinerators allowing the use of HCl CEMS other than those based on 

FTIR methods.

Comment 35: Commenter 17851 believes the EPA should not apply PS 15 to HCl CEMS, but should 

promulgate a PS specifically designed for these instruments. The commenter notes most commercial 

HCl CEMS use some form of infrared light attenuation to measure HCl concentrations and that 

requiring HCI CEMS to use PS 15 is simply not appropriate. The commenter believes the EPA should 

promulgate a performance specification specifically for HCl CEMS much like they have performance 

specifications for other CEMS (e.g., PS 11 for PM CEMS, and PS 12A for Hg CEMS, etc.). The 

commenter also believes that it is not appropriate to require compliance with an HCl CEMS unless there 

is a promulgated performance specification for HCl CEMS. The commenter suggests that these CEMS

should not be required until a performance specification for these types of units is promulgated. 

However, if the agency decides to require these CEMS, the commenter believes there is a better interim 

solution than PS 15. The EPA has already approved two preliminary other test methods for HCl CEMS, 

OTM 22 and 23. The commenter believes that it makes more sense to temporarily use a preliminary test 

method already approved for HCl CEMs than to use an already promulgated performance specification 

that may not apply. The commenter suggests that the EPA modify the final rule to allow the use of OTM

22 and 23 instead of PS 15.
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Comment 36: Commenter 18023 believes it is inappropriate to require HCl CEMS without appropriate 

industry practice demonstrating their availability and without a relevant Performance Specification.

Commenter 17775 states that the EPA must provide a reasonable performance specification for HCl and 

HF CEMS in time for EGUs to make decisions regarding compliance options.

Response to Comments 23 - 36: See Response to Comments 1-21 under 5A09 of this document.

3. Proposed alternatives.

Comment 37: Commenter 17704 believes as an alternative, a stack test emission factor based on an 

annual stack test would be more appropriate for their Powder River Basin (PRB) subbituminous coal 

units. According to the commenter, the amount of chlorine in the PRB coal the commenter utilizes does 

not vary much over a year, and a once per year stack test emission factor would be a sufficient means of 

calculating HCl emissions. The commenter suggests adding an option that would have an alternative for 

using a stack test emission factor instead of HCl CEMS, as long as, the fuel utilized by the unit does not 

change during the year. The commenter states that if a new fuel is introduced a new stack test could be 

required.

Response to Comment 37: The rule provides an alternative to an HCl CEMS based on periodic stack 

testing. See section 63.1006(j) and (k). The required testing frequency is more frequent than the 

suggestion made by the commenter.

Comment 38: Commenter 17728 recommends that if no performance specification is forthcoming by 

the time decisions about compliance options need to be made, the EPA should allow EGUs to petition 

for use of an alternative specification.

Response to Comment 38: Sources may petition for an alternative specification consistent with the 

provisions of section 63.7.

Comment 39: Commenter 17724 questions the need for SO2 monitoring in addition to parametric 

monitoring associated with scrubber operation. The commenter suggests that like PM, the EPA should 

allow a source to choose either SO2 monitoring or scrubber parametric monitoring in conjunction with 

fuel analysis as a continuous compliance option, and that the EPA should not categorically create 

secondary compliance monitoring.

Response to Comment 39: If an SO2 CEMS is used consistent with the alternative SO2 limit included 

in the rule, no parameter monitoring requirement applies.Comment 40: Commenter 17715 supports SO2

as a surrogate for HCl at scrubbed units.

Response to Comment 40: The EPA acknowledges the commenter’s support.

Comment 41: Commenter 17402 suggests in the alternative that facilities be permitted to utilize 

monthly fuel sampling coupled with periodic stack testing to meet monitoring compliance obligations.

Response to Comment 41: The final rule eliminates the fuel sampling option. A source may use an

SO2 CEMS where an FGD is installed, may use HCl CEMS, or may conduct periodic testing to 

demonstrate compliance.
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Comment 42: Commenter 17696 believes until the EPA develops an accepted performance 

specification for HCl CEMS, that HCl CEMS should be used for compliance purposes with the EGU

NESHAP rule only upon the EPA approval of an alternative monitoring method in accordance with 40 

CFR 63.8(f).

Response to Comment 42: The EPA has set forth PS 15, which uses a Fourier Transform Infrared 

(FTIR) analyzer as an acceptable alternative for HCl CEMS performance specifications. Sources may

seek alternative specifications through section 63.7. See also Response to Comments 1-21 under 5A09.

Comment 43: Commenter 17775 suggests that in the absence of an existing specification, the EPA 

should recognize in the rule that PS 15 does not apply to HCl CEMS and allow EGUs to petition the 

EPA for use of an alternative specification if none has been promulgated by the time EGUs need to 

make decisions about their compliance options.

Response to Comment 43: See response to Comment 42, directly above.

Comment 44: Commenter 17621 believes there are three likely candidate technologies for continuous 

measurement of gas-phase HCl: FTIR, tunable diode laser (TDL), and gas filter correlation (GFC); 

however, there is little or no experience with any of these technologies on EGUs, although all three have 

been used in Europe on municipal waste incinerators. The commenter states that the EPA has approved 

a reference method using FTIR for HCl in cement plant emissions. The commenter states that GFC is 

widely used on waste incinerators in Europe for HCl monitoring, but U.S. experience with this 

technology on EGUs is limited to CO2 monitoring. According to the commenter, all of these 

technologies operate in the near infrared range and are to some extent subject to interference from water 

vapor, but both FTIR and TDL systems are able to resolve this interference.

The commenter notes with increasing measurement path there is a tradeoff between increased sensitivity

and loss of signal strength. According to the commenter, particulate and entrained droplets in the flue 

gas can degrade the signal strengths in an in situ application in wet stacks, and demonstration of in situ 

techniques in a wet stack environment needs to be conducted. An alternative approach is to extract a gas 

sample and measure HCl. The commenter states that sample transport in a hot, wet flue gas is 

problematic and would require multipass measurement cells to achieve sufficient path length for the 

required sensitivity. Currently, states the commenter, the only installation on a U.S. EGU is an in situ 

TDL on a dry stack, and in that application, there was sufficient intensity to measure HCl and to identify

process variations. The commenter states that there is no experience with HCl monitors on a wet stack; 

the preferred installation by the suppliers is to make an in situ measurement, or at least place the 

instrument close coupled to the stack, to avoid problems with condensation of HCl during transport.

The commenter notes that the key tasks that need to be completed before an HCl monitor can be 

deployed and used for compliance measurements include: (1) Determine detection and quantitation

limits; (2) Quantify interferences of likely species in flue gas; (3) Validate CEMS in a wet stack; (4) 

Develop alternative extractive sampling techniques; (5) Develop low-level calibration standards; and (6) 

Develop and validate an EPA performance specification.

Comment 45: Commenter 17725 suggests HCl CEMS should not be limited to FTIR monitoring 

methodology as HCl CEMS based on FTIR technology tend to be very expensive to maintain and are 

labor intensive. The commenter suggests newer technologies such as Tunable Diode Laser Spectroscopy

(TDLS) and Ion Mobility Spectroscopy (IMS) are showing great promise as a suitable replacement for 

selective gas components such as HCl and HF.
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Response to Comments 44 - 45: The EPA acknowledges that certain applications of HCl CEMS will 

require further demonstrations and advances for this technology. The agency is working to finalize a PS 

for HCl CEMS (not limited to just an FTIR approach) and notes that the use of an HCl CEMS is just one 

option for demonstrating compliance under the final rule, not a requirement. The PS for HCl CEMS will 

include consideration of detection and quantitation limits, interferences, performance of CEMS under 

site specific stack conditions, evaluating extractive as well as in-situ measurement techniques, and the 

requirements for low-level calibration standards.

4. Support of HCl CEMS.

Comment 46: Commenter 17622 states the proposed rule suggests that using a compliance approach for 

DSI of setting injection rate operational limits based on performance testing. According to the 

commenter, because this approach could result in operators setting injection limits based on performance 

testing with a higher reactivity sorbent and later substituting a lesser quality sorbent, compliance with 

the HAP limit could be jeopardized. To avoid this potential issue the commenter recommends the use of 

CEMS technology to facilitate ongoing HCl emissions compliance. The commenter also recommends at 

a minimum, if injection rate limits are utilized, reagent reactivity should also be specified.

Comment 47: Commenter 17756 supports the EPA’s selection of HCl as a surrogate for the other acid 

gas HAP. The commenter also agrees with the EPA’s proposal to allow EGUs the option of meeting an 

alternative SO2 limit, if a unit uses a CEMS device to demonstrate compliance with SO2 limits. 

According to the commenter, as drafted, proposed section 63.9991(a)(1)(i) limits the units that can 

comply with an alternative SO2 limit to those that have “wet or dry FGD technology installed on the 

unit.”

Response to Comments 46 - 47: The EPA notes the commenter’s support for use of an HCl CEMS. As 

for the reagent reactivity concern, the general requirements for testing require that the tests be conducted 

under normal conditions, which would include using the same quality sorbent during testing as is used 

during operations. This type of deliberate violation of the regulations is considered unlikely as a general 

concern, and will be best handled through effective compliance oversight and no change to the rule is 

necessary. The EPA also acknowledges the support for the SO2 alternate equivalent standard option 

where that applies.

5. Additional concerns.

Comment 48: Commenter 16513 notes that PSEG Bridgeport Harbor 3 is required to comply with the 

SO2 emissions rate or fuel sulfur content limits of Regulations of Connecticut State Agencies 22a-174-

19a, which PSEG accomplishes by use of low sulfur Indonesian coal. As a result, states the commenter, 

PSEG Bridgeport Harbor 3 currently meets the Utility NESHAP’s SO2 limit of 0.20 lb/MMBtu for coalfired EGUs. The commenter states that under the Utility NESHAP, a unit with acid gas controls is not 

required to install and operate an HCl CEMS. The commenter suggests the EPA clarify whether or not 

the use of low sulfur fuel would qualify as an acid gas control. The commenter believes if so, PSEG

Bridgeport Harbor 3 may forgo the installation of HCl CEMS.

Response to Comment 48: The use of the SO2 alternate equivalent standard option applies only where 

an FGD is in use, because that control device ensures adequate acid gas control, and the monitoring of 

SO2 ensures proper operation of the control device. In the situation described, without an FGD installed, 

the unit would not qualify for the SO2 alternate equivalent standard and must meet the HCl limit. The 

source can demonstrate compliance using an HCl CEMS or periodic HCl testing.
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Comment 49: Commenter 17718 believes that within the proposed regulatory language of 40 CFR

63.10006, there does not appear to be an option for reduced HCl performance testing requirements on 

coal-fired units with non-HCl controlled bypass stacks. The commenter identifies a facility that is 

currently configured to send its emissions to a common wet FGD shared with Unit 1 and 3 at the same 

facility. The common emissions are then emitted through a common stack. The commenter states that all 

three units are affected coal-fired units designed to burn greater than 8,300 BTU/lb coal, but Unit 2 is 

also configured and permitted to utilize a bypass stack. According to the commenter, within the 

proposed language of 40 CFR 63.10010(a)(4), it appears the facility’s bypass stack would be required to 

install similar monitoring systems as the main common stack, but without FGD technology on the 

bypass stack, it appears that the current 40 CFR part 75 SO2 CEMS located on the bypass stack could 

not be used for compliance determinations as a surrogate for HCl. Furthermore, states the commenter, 

even if the company desired to install an HCl monitor on the dry stack to monitor emissions, it would 

still be required to conduct performance testing every month because there apparently is not an option to 

allow HCl monitoring under 40 CFR 63.10006(i)-(k) to cover a non-HCl controlled unit/stack.

Response to Comment 49: The EPA has modified the requirements for monitoring a bypass stack. 

Under the final rule, the installation of a monitor on a bypass stack is not required.

Comment 50: Commenter 17881 suggests section 63.10011 (b)(1), relating to establishment of a 

maximum chlorine fuel input, should only apply to units which are not complying with the SO2

surrogate or are not relying on an HCl CEMS. 

Response to Comment 50: Under the final rule, no fuel input operating limits apply. The source may be 

required to conduct a new performance test where there is a significant change in fuel use that could 

result in emission increases.

Comment 51: Commenters 17724 and 17876 state that the CEMS the facility installed in preparation to 

CAMR have significant reliability and operational issues (Hg, PM, HCl). Commenters 17724 and 17876 

state that the EPA has left the long-term operational problems such as calibration gases to industry and 

there are not accurate and reliable monitoring methodologies for demonstrating. Commenters 17724 and 

17876 state the EPA purports to provide compliance flexibility while in reality there is very little 

flexibility in light of the problematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not 

commercially available to measure HCl emissions from coal-fired EGUs, and no HCl CEMS were used 

to collect the data the EPA used to establish the HCl standard.

Response to Comment 51: The agency disagrees with the commenters. As mentioned elsewhere, the 

agency finds that the operation and maintenance issues for the CEMS mentioned are no different than 

for other CEMS now in wide use and acceptance by the industry. The agency is aware that the 

calibration gas issue is to be rectified well in advance of the rule’s compliance date. The agency notes 

that the rule is quite flexible with respect to compliance demonstration, containing numerous choices for 

compliance, including the use of emissions testing alternatives for those EGU owners or operators who 

remain concerned over use of CEMS or PM CPMS. The agency notes that FTIR CEMS exist now and 

can be used to measure HCl emissions continuously, that the HCl emissions limit was developed from 

emissions testing and has been adjusted to be appropriate for measurement with HCl CEMS, and that 

emissions testing options to demonstrate compliance exist for those EGU owners or operators who 

choose not to use CEMS.
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5A10 - Testing/Monitoring: CEMS, General

Commenters: 15678, 16849, 17191, 17197, 17265, 17283, 17316, 17402, 17620, 17623, 17627, 17638, 

17655, 17677, 17681, 17716, 17718, 17722, 17725, 17730, 17731, 17740, 17757, 17758, 17767, 17770, 

17772, 17774, 17775, 17776, 17781, 17796, 17800, 17805, 17816, 17820, 17821, 17856, 17871, 17873, 

17877, 17881, 17885, 17902, 17913, 17928, 18014, 18015, 18031, 18037, 18428, 18443, 18449, 18539, 

19032, 19033, 19041, 19114, 19120, 19121, 19122, 19536, 19537, 19538, 18023

1. Support for the PM CEMS, HCl CEMS and Hg CEMS.

Comment 1: Several commenters (15678, 17722, 19032) support the EPA requirements of installing 

PM CEMS, HCl CEMS and Hg CEMS to demonstrate continuous compliance with the emission 

standards.

Comment 2: Commenter 17283 supports the EPA that monitoring is an integral part of emission 

controls and that enhanced monitoring should be encouraged.

Comment 3: Commenters 17402 and 17620 support electronic reporting similar to the 40 CFR Part 75

ECMPS process.

Comment 4: Commenter 17740 supports the EPA that the Hg monitoring requirements established by

the CAMR are sufficient and appropriate requirements for the EGU MACT.

Response to Comments 1 - 4: The EPA appreciates the commenters’ support for various provisions 

involving CEMS. The final rule builds on the proposed provisions and clarifies what CEMS are allowed 

to demonstrate compliance, whether Hg, HCl, HF, or SO2, as well as how to report that CEMS data 

using ECMPS. In addition, upon request from a source owner or operator, the agency will consider 

allowing use of multiple metals CEMS for non-Hg metals. Until a method and performance 

specification for multiple metals CEMS is promulgated, source owners or operators wanting to request 

their use should consider having their applications consistent with the draft multiple metals CEMS

method and performance specifications located at the following internet address: < 

http://epa.gov/ttn/emc/prelim/otm19.pdf>.

Given the low non-Hg metals and PM emissions limits and possible difficulties in using PS 11 to certify

PM CEMS at those low levels, the rule no longer requires the use of PM CEMS. Rather, PM CPMS, in 

which a PM detecting instrument is used as a parameter monitor is contained in the rule. Continuous 

parametric data from the PM CPMS signal will be collected and reported to the agency’s central data 

exchange. The final rule also does provide for the use of a PM CEMS to determine compliance with the 

filterable PM emission limit if the source elects to use this approach (see the final preamble for further 

discussion). In that case, the PM CEMS is used as the direct method of compliance and no additional 

testing is required other than tests that are required as part of the QA requirements in PS 11.

2. Opposition based on testing requirements.

Comment 5: Commenter 16849 states that the proposed rule does not include provisions to use the 40 

CFR Part 75 “conditionally valid data procedures.” For example, states the commenter, if a CEMS fails 

a linearity check, the CEMS remains out-of-control until the successful completion of a subsequent 

linearity check, and this would require the operator to invalidate the 40 CFR part 75 conditionally valid 

data (for SO2, CO2, O2, or flow monitors) for EGU MACT recordkeeping and reporting purposes. 
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According to the commenter, a clearer approach would allow quality-assured data from a CEMS

certified and operated in accordance to 40 CFR part 75 to be used for compliance with the exception of 

bias-adjusted and missing data.

Response to Comment 5: For the CEMS data that will be reported through ECMPS, the EPA has added 

provisions to harmonize these reporting elements so that the data are reported in a consistent manner, 

including conditionally valid data procedures. The exceptions are that no missing data or bias provisions 

in part 75 are applied for purposes of complying with these standards.

3. Opposition based on limitations to the technologies.

Comment 6: Commenter 16849 states that there are known limitations to the technologies available to 

monitor the surrogate HAP and provides the following details:

According to the commenter, Hg CEMS are difficult to maintain and accuracy is questionable at low Hg 

levels in conditions seen at utility plants. The commenter states that the NSPS limit is so restrictive that 

utility plants cannot meet the proposed limits and control equipment vendors will not guarantee the 

limits. According to the commenter, the EPA did not take into consideration the variability of Hg 

content in coal when setting the low limits for Hg. The commenter states that in order to represent coal 

variation, a better solution would be to use a requirement such as the Illinois Hg removal limit of 90%

which is based on a 720 hour (30-day) rolling average of 1-hour readings and does not rely on a set 

maximum limit over 30 days as the proposed limit. According to the commenter, Hg analyzer 

performance has been so unpredictable that utility companies that have continued the use of the CEMS

for state requirements are contemplating the replacement of CEMS with sorbent traps for the NESHAP. 

The commenter states that the EPA has not publicly released NIST Traceability protocols, and early

elemental Hg Vendor Prime calibrator certifications exhibited poor accuracy and precision.

Response to Comment 6: The EPA disagrees. The EPA does not believe a percent reduction 

requirement averaged on a 30-day rolling basis would be more readily monitored than a 30-day rolling 

average emission limit. In addition, as stated elsewhere, the EPA questions the legality of a percent 

reduction standard in light of court precedent and we do not have sufficient information to set such a 

standard even if we believed it was legally available. Sorbent trap monitoring is allowed if a source 

owner or operator chooses to use that monitoring option. The interim NIST traceability protocols have 

been publically released and represent the results of a collaborative process for establishing protocols 

amongst the affected stakeholders for Hg CEMS monitoring.

Comment 7: Commenter 16849 states that there are known limitations to the technologies available to 

monitor the surrogate HAPS and provides the following details:

According to the commenter, PM CEMS are difficult to maintain and the NESHAP proposes a 

hybridized reference method, mixing EPA Method 5 and 5B. The commenter states that using total PM 

for the MACT metals limit surrogate and then setting the filterable PM limit based on the performance 

test does not work nor allow for a compliance margin. The commenter states that the NESHAP requires 

maintenance of the PM concentration at or below the highest 1-hour average measured during the most 

recent performance test demonstrating compliance with the total PM emissions limitation, and the 

performance testing for total PM includes both filterable and condensable PM which would establish the 

plant or unit limit. The commenter states that since the PM CEMS only measures filterable PM, the 

margin of compliance for the unit or plant would be the amount of total condensable PM. The 

commenter states that the EPA identifies that EGUs using PRB as a fuel without wet FGD technology
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have very low condensable PM emissions. According to the commenter, this method establishes an 

enforceable limit but does not provide a reasonable margin of compliance and artificially changes the 

limit established in the rule. The commenter states that low limits set during initial performance testing 

reflect capabilities of new equipment running at steady-state, maximum efficiency, and these conditions 

will not be achievable as equipment begins to age. Commenter 16849 requests that the performance test 

requirement be removed, using the RATA to verify the CEMS and the CEMS be the compliance 

measure based on the 12-month average. According to the commenter, the limit should be set at 0.03 

lb/MMBtu, not based on performance testing. Commenter 16849 states that with the addition of PM 

CEMS on all units, the requirement for opacity CEMS is no longer needed, and PM CEMS should be 

used to demonstrate compliance for opacity.

Response to Comment 7: The final rule adjusts the manner in which PM instruments are used to 

determine and monitor filterable PM as an operating limit for non-Hg metals. The rule establishes 

emissions testing based on filterable PM only, not total PM. The rule also provides for use of PM 

instruments as CPMS. The final rule also does provide for the use of a PM CEMS to determine 

compliance with the filterable PM emission limit if the source elects to use this approach (see the final 

preamble for further discussion). In that case, the PM CEMS is used as the direct method of compliance 

and no additional testing is required other than tests that are required as part of the QA requirements in 

PS 11. As for opacity requirements, the EPA disagrees that these MACT standards can undo all prior 

opacity standards for EGUs under all programs. The EPA will evaluate the extent to which opacity

monitoring may no longer be needed as it reviews existing federal standards for affected units, including 

considering how particular sources choose to operate their PM instruments (e.g., as PM CPMS or PM 

CEMS), and will make any appropriate adjustments as part of that future, regular review. States may

wish to consider how instrumentation in this rule could be useful in evaluating requirements for their 

own opacity standards.

Comment 8: Commenter 16849 states that there are known limitations to the technologies available to 

monitor the surrogate HAPS and provides the following details:

According to the commenter, vendors are not assuring the abilities of HCl CEMS, and these monitors 

have no record in the utility industry. The commenter states that currently no performance test is 

available for HCl.

Comment 9: Commenter 17191 states that Table 15 of the docket entry EPA-HQ-OAR-2009-0234 of 

the regulation shows that there is no alternative option of using SO2 CEMS data as a surrogate for acid 

gas compliance monitoring for existing IGCC units. The commenter states that the only alternative for 

compliance is HCl CEMS installation. Commenter 17191 notes that the HCl monitoring system is 

untested technology for IGCC systems.

Comment 10: Commenter 17402 supports the CEMS requirements outlined in the proposed rule, so 

long as the technologies have been proven in the field, like SO2 monitors and Hg sorbent traps, and 

unlike filterable PM monitors, continuous Hg monitors, and HCl CEMS.

Comment 11: Commenter 17677 disagrees with the EPA regarding high frequency emission testing 

requirements or PM CEMS due to difficulties in certification at very low emission levels.

Comment 12: Commenter 17757 states that there is no effective CEMS for Hg. According to the 

commenter, the HCl CEMS are not commercially available or adequate for in-stack measurements. 

Commenter 17757 disagrees with the EPA establishing CEMS standards about which there is limited 
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experience in the industry and for which the technology has not yet been commercially developed. 

Commenters (17757, 19033, 19041) state that it is unclear whether installing and operating CEMS for 

the regulated HAP and HAP surrogates eliminates the obligation to also monitor compliance with 

operating limits/parameters on control equipment based on a performance stack test. According to the 

commenters, a properly installed and calibrated CEMS should suffice. Clarification on this point is 

necessary.

Comment 13: Commenter 18023 states that the EPA must provide reasonable continuous compliance 

requirements for Hg and other HAP and eliminate requirements for undemonstrated or unreliable 

technologies such as HCl CEMS and PM CEMS.

Comment 14: Commenters 17800 and 17902 state that while CEMS for Hg and PM are available 

commercially, EGUs do not have experience in their operation and maintenance on a long term basis. 

Hg CEMS are not reliable and require two to three times the effort to maintain as typical SO2 or NOX

CEMS. According to the commenters, further testing and verification of the of the required CEMS

equipment at utility sites need to be conducted before they should be used.

Response to Comments 8 - 14: These brief comments raise a variety of issues that generally have been 

addressed in response to other more detailed comments. The EPA is maintaining the proposed 

requirements to use CEMS where appropriate. If a source owner or operator does not choose to use an 

HCl CEMS in situations where the SO2 alternative is not permitted, HF CEMS, or PM CPMS, the rule 

provides for a periodic stack testing alternative. If a source owner or operator does not choose to use an 

Hg CEMS, the rule provides for a sorbent trap alternative. Apart from PM CPMS, operating parameter 

monitoring requirements no longer exist in the rule. The EPA disagrees that Hg CEMS and PM CEMS

are unproven technologies. See response to more detailed comments in other sections of this Response 

to Comments document on those issues.

4. Opposition based on operating limit requirements.

Comment 15: Numerous commenters (17197, 17623, 17627, 17716, 17722, 17725, 17731, 17740, 

17757, 17770, 17774, 17775, 17776, 17800, 17805, 17816 17820, 17871, 17877, 17885, 17902, 18023, 

17913, 18014, 18015, 18031, 18037, 18443, 18539, 19033, 19114, 19122, 19536, 19537, 19538) request 

that the EPA remove the operating limit requirements for facilities that utilize CEMS to demonstrate 

compliance. According to the commenters, this will reduce the cost and administrative burden of the 

rule without sacrificing human health or environmental benefits, and the CEMS will continuously

monitor the level of emissions and document the source’s compliance. The commenters state that 

requirement to demonstrate compliance in a second form through an operating limit is burdensome and 

unnecessary. According to the commenters, the EPA should remove requirements to test for the 

underlying pollutants being controlled through a surrogate because such tests are redundant and 

unnecessary for compliance with the proposed utility MACT.

Comment 16: Commenters 19120 and 17881 request clarification of the applicability of monitoring and 

operating limits to units using CEMS for compliance monitoring.

Comment 17: Several commenters (17730, 17758, 17775) disagree with the EPA requirements for 

sources to establish compliance with the non-Hg metal limits using total PM as a surrogate and PM 

CEMS as the measurement tool, with the HCl limit using HCl CEMS or an SO2 CEMS for ongoing 

compliance, or with the Hg limit using a Hg CEMS or a sorbent trap system to also comply with an 

operating load limit or with control device operating parameter limits for PM, HCl, or Hg controls.
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Comment 18: Commenter 17775 states that the EPA provides no data or discussion to justify chosen 

control device operating parameters, which are not in most cases sufficiently connected to emissions to 

justify imposing enforceable limits.

Comment 19: Multiple commenters (17627, 17740, 17770, 17776, 17816, 18014, 18015) state that the 

EPA should amend the regulatory language in section 63.10007(c) to make it clear that fuel sampling 

and operating parameter limits do not apply when either all of the regulated HAP or their surrogates are 

continuously monitored by a CEMS.

Comment 20: Commenter 19033 recommends that section 63.1008(a) be amended to require 

performance fuel analysis tests, if the regulated pollutant or specified surrogate emissions are not 

continuously measured by a CEMS.

Comment 21: Commenter 18023 proposes that operating limits should be a trigger for maintenance or 

inspection only.

Comment 22: Commenter 17877 states that operating limits or parameters should not be required on 

emission control devices where compliance is demonstrated by CEMS and that operating limits should 

not be established based on initial performance testing.

Comment 23: Commenter 17928 states that stack testing is unnecessary to assure compliance if a unit 

installs or uses CEMS.

Response to Comments 15 - 23: The final rule clarifies that where a CEMS is used for a given 

pollutant (including an alternate equivalent standard in the case of SO2) then no parameter monitoring is 

also required for demonstrating continuous compliance with the emission limit for the applicable 

pollutant. The final rule also clarifies that sources do not have to test for a pollutant where the source is 

meeting a surrogate emission standard (such as filterable PM for non-Hg HAP). As mentioned in other 

responses, with the exception of PM CPMS and in limited cases, site-specific parameters for liquid oilfired units, the remaining fuel analysis, operating limit and parameter monitoring comments, are moot, 

for the rule no longer requires operating limits. For the EPA’s response to those comments which 

oppose the manner in which operating parameter limits are set, please see responses to comments under 

Comment Code Section 5A05 in this Response to Comment document. As noted elsewhere, no 

operating parameter requirements apply when a CEMS is used to demonstrate compliance for an 

applicable pollutant.

5. Opposition based on averaging times.

Comment 24: Commenter 16849 recommends that averaging times for demonstrating compliance with 

the Hg limits be increased to a 365-day rolling average due to variability in coal quality, varying Hg 

content, removal equipment, and Hg CEMS monitor accuracy.

Comment 25: Commenter 17197 supports the proposed “30-boiler operating day rolling average”

calculation methodology based on averaging all of the valid hourly averaged measurements during the 

preceding 30 boiler operating days. According to the commenter, if compliance is based on daily periods 

rather than hourly periods, a single (abnormally high or low) hourly measurement could be the basis of a 

daily period that could improperly bias the resulting 30-day average. The commenter states that using 

hourly averages as the basis for the 30-day boiler operating day rolling averages removes the potential 
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for skewed results from days containing only a few unit operating hours and consequently yields 

representative emission rates for the 30-day compliance demonstration period.

Comment 26: Commenter 17740 does not support compliance demonstration with the tested average 

PM value using a 30-boiler operating day PM average.

Comment 27: Commenter 17402 states that since the rule does not propose a cap-and-trade program, 

units should not be required to collect a monitored value for each operating hour.

Response to Comments 24 - 27: The final rule maintains the 30-day rolling average using hourly 

values. This averaging period enables short-term readings to be averaged out, and this averaging period 

is consistent with the periods already used in subpart Da of the NSPS and in the acid rain program. The 

standard was not set based on data sets representing a 365-day period, and we decline to adopt such an 

approach in the final rule. Sources are required to monitor during all operating periods when continuous 

monitoring is used to demonstrate compliance.

6. Opposition based on bias adjustments.

Comment 28: Several commenters (17881, 17796, 18023) support eliminating the bias adjustment for 

mercury, HCl, and PM CEMS since it is believed that bias adjustment of data has only been utilized 

with trading system based rules where mass emissions are being totaled.

Comment 29: Commenter 18023 states that bias can cause both over-and-under reporting. The longer 

averaging time should alleviate the need for bias adjustment.

Comment 30: Commenter 17767 states that unless the EPA is prepared to allow for the low bias of 

emissions data as well as high, it is best to follow the proposed rule and remove the Part 75 Bias Test for 

Hg, HCl, and PM CEMS.

Response to Comments 28 - 30: There is no bias adjustment factor applied for purposes of this rule.

7. Opposition based on compliance requirements.

Comment 31: Commenter 16849 disagrees with the EPA about the ability of Hg CEMS to reach 

compliance within the first 30 days of operation. According to the commenter, with the needed 

adjustments and repairs to Hg CEMS and the additional operation of multiple control devices, plant 

personnel will need at least 180 days to optimize control and monitoring equipment.

Response to Comment 31: For existing units, the final rule requires sources to demonstrate compliance 

within 180 days after the date 3 years from publication of the final rule in the Federal Register. Such an 

extended period provides ample opportunity for the types of adjustments suggested by the 

commenter. For new units, the rule likewise provides up to 180 days for demonstrating initial 

compliance.

Comment 32: Commenter 17716 disagrees with the EPA about showing on-going compliance by 

combining CEMS data with non-CEMS data to demonstrate compliance.
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Response to Comment 32: The comment is moot, as the rule no longer contains a total PM limit, no 

longer requires use of PM CEMS for filterable PM, and no longer requires use of Method 202 to 

determine condensable PM.

Comment 33: Commenter 17758 states that the purpose of the fuel input limits is to ensure that EGUs

that are not using CEMS or sorbent trap monitoring systems repeat the relevant performance test if their 

fuel characteristics change such that compliance with the applicable limit at the current level of control 

is no longer assured. According to the commenter, since all EGUs are required to demonstrate initial 

compliance with each emissions limit through performance testing, and the proposed rule defines 

performance testing to include the first 30 operating days of CEMS data, the proposal appears to require 

that EGUs meet fuel input limits regardless of the performance testing option that they choose. The 

commenter states that there is no logical rationale for requiring sources that establish compliance with 

the non-Hg metal limit using PM as a surrogate and PM CEMS, with the HCl limit using HCl CEMS or 

an SO2 CEMS, or with the Hg limit using Hg CEMS or a sorbent trap system to also comply with fuel 

input limits for metals, chlorine or Hg.

Response to Comment 33: The comments are moot because the rule no longer requires fuel analysis or 

operating limits.

Comment 34: Commenter 17775 notes that the EPA does not propose separate continuous compliance 

requirements for HF CEMS.

Response to Comment 34: Section 63.10010(d) addresses operating requirements for HF CEMS.

Comment 35: Several commenters (17800, 18015, 18037) state that compliance testing and monitoring 

requirements that include periodic emission testing, other performance testing and CEMS are 

unnecessarily restrictive and expensive to implement, perform and operate. According to the 

commenters, the regulations for Hg CEMS had numerous unresolved issues related to accuracy, 

calibration standards, and quality assurance provisions, and the EPA should allow time for development 

of performance specifications and, field testing and verification of the accuracy and precision 

of HCl monitoring equipment at utility sites before they are required for compliance purposes.

Response to Comment 35: For comments on technical aspects of HCl and Hg monitoring, see the 

specific responses to comments on those technologies in other sections of this document. The EPA 

disagrees with granting states flexibility to establish compliance plans for sources. This is a federal rule, 

which provides flexibility to sources to select appropriate monitoring for their facility. In the event the 

source believes an alternative monitoring method should apply, the part 63 provisions establish a 

method to request alternative monitoring, and the EPA and the states have established procedures for 

handling such requests in the event implementation of a specific NESHAP is delegated to a state agency.

Comment 36: Commenters 17805 and 17816 state that there is no logical reasoning for requiring 

sources to establish parametric limits for compliance at units already demonstrating compliance 

with CEMS.

Response to Comment 36: The comments are moot because the rule no longer requires fuel analysis or 

operating limits.

Comment 37: Commenter 17856 states that due to the very low concentrations of Hg in stack gases, 

any little flaw in the precision or accuracy of the monitor could lead to an inaccurate compliance 
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determination. The commenter states that the uncertainty associated with the use of these technologies 

further illustrates the need for provisions within the rule allowing a state to develop compliance plans 

tailored to a particular unit’s operations. According to the commenter, states need monitoring 

requirements with flexible options for compliance plans, such as fuel sampling and analysis, emission 

control monitoring, and the installation of CEMS, to provide sufficient assurance that actual emissions 

limits are being met.

Response to Comment 37: For comments on technical aspects of HCl and Hg monitoring, see the 

specific responses to comments on those technologies in other sections of this document. The EPA 

disagrees with granting states flexibility to establish compliance plans for sources. This is a federal rule, 

which provides flexibility to sources to select appropriate monitoring for their facility. In the event the 

source believes an alternative monitoring method should apply, the part 63 provisions establish a 

method to request alternative monitoring, and the EPA and the states have established procedures for 

handling such requests in the event implementation of a specific NESHAP is delegated to a state agency.

Comment 38: Commenter 17881 states that the EPA needs to clarify whether fuel analysis and/or the 

establishment of operating limits apply in those cases where a CEMS is used to directly measure 

the HAP or an associated surrogate.

Response to Comment 38: The comments are moot because the rule no longer requires fuel analysis or 

operating limits.

8. Opposition based on monitoring requirements.

Comment 39: Commenter 17740 recommends that the EPA eliminate fuel sampling and parameter 

monitoring for an EGU which meets the specified emission limits as demonstrated through use of a 

CEMS and states the following:

a. The EPA has not provided a rational justification for additional requirements to Part 75. See 40 CFR

section 63.10010.

b. The EPA should allow at least 1 year for sources to install and certify an HCl CEMS and should 

require HCl testing once every four unit operating quarters, but no less than once every eight calendar 

quarters.

Comment 40: Commenter 17758 states that the EPA does not have a performance specification that is 

specific for non-FTIR-based HCl monitors. The commenter states that table 5 of the docket entry EPAHQ-OAR-2009-0234 lists PS 6 as an applicable performance specification, but PS 6 is written for the 

certification of systems used to measure pollutant emissions in units of mass per unit of time. The 

commenter states that the EPA protocol gases are not widely available and are expensive relative to 

traditional CEMS calibration gases. According to the commenter, lowest available concentrations are 

significantly higher than proposed limits. Commenter 17758 recommends that the EPA allow use of SO2

monitors installed downstream of a wet or dry scrubber or DSI system to comply with the HCl

monitoring requirements.

Comment 41: Commenter 17775 states that the EPA should describe why EGUs need to monitor 

control device parameters for meeting fuel input levels and that there is no discussion at all of the 

proposed fuel input levels in the docket entry EPA-HQ-OAR-2009-0234.
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Response to Comments 39 - 41: As stated elsewhere in response to more detailed comments, source 

owners or operators who use CEMS to demonstrate continuous compliance are not required to monitor 

operating parameters or fuel for the same pollutant, as fuel analysis is no longer required and, apart from 

PM CPMS, operating limits are no longer required. A source can opt to use an SO2 CEMS instead of an 

HCl CEMS in specific circumstances, and can use emissions testing in lieu of an HCl CEMS. The EPA 

also intends to promulgate a performance specification for HCl CEMS prior to the compliance date of 

this rule, at least with respect to the compliance date for existing sources.

Comment 42: Commenters 17716 and 18449 state that section 63.10021(a)(10)(ii) does not include a 

reference to CO2 contrary to the requirements in section 63.10010(b) which allow the use of O2 or CO2. 

According to the commenters, the majority of Part 75 affected coal-fired units utilize dilutionextractive CEMS which are equipped with CO2 analyzers, and dilution-extractive CEMS cannot 

measure O2 as a diluent.

Response to Comment 42: The final rule addresses this oversight.

Comment 43: Commenter 17881 states that in cases where an EGU elects to calculate annual Hg 

emissions based upon the average measured Hg concentration and measured exhaust flow rate, the EPA 

has already granted the use of the default moisture content values for the determination of exhaust gas 

moisture content in 40 CFR part 75, section 75.11(b)(1). 

Response to Comment 43: The final rule allows for moisture defaults as proposed. Given the lack of 

defaults for oil-fired units, we have added an option for sources to petition for an alternative unitspecific default in those cases.

Comment 44: Commenters 17881 and 19114 state that the proposed regulation referring to “fuelspecific CO2 concentration” in section 63.10005(l) has following flaws:

a. According to the commenters, the proposed rule does not contain any such default CO2 concentration 

values and does not reference another regulation containing such values, and it is hard to believe that the 

EPA intended for each regulated source to develop a custom “fuel-specific CO2 concentration” based 

upon the equivalent O2 diluent cap and the fuel or fuels being fired.

b. According to the commenters, these provisions do not distinguish between boilers and the combustion 

turbines used in IGCC technologies; boilers and combustion turbines are fundamentally different 

combustion processes and operate at very different levels of excess air (which in turn impacts 

the diluent gas concentrations).

c. According to the commenters, the proposed rule language is not clear on when the diluent cap values 

should be applied; it simply states that they should be applied during periods of startup and shutdown 

(which are not defined in the proposed rule, and are only generically defined in section 63.2). The 

commenters state that under 40 CFR Part 75, the diluent cap values are simply applied whenever the 1-

hour average diluent concentrations fall below the applicable diluent cap values (without any

qualification that the unit must be in startup or shutdown modes). Outside of periods of startup and 

shutdown, state the commenters, it is hard to envision any other circumstances which would cause 

the diluent concentrations to fall below the diluent cap values.

Response to Comment 44: Given the changes from proposal, these provisions are no longer relevant 

and do not appear in the final rule.
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Comment 45: Commenter 18014 states that EGUs that install a CEMS should not be required to 

provide further assurance of compliance with the emissions standards. According to the commenter, 

such additional monitoring is redundant and creates an unnecessary burden on these sources and as such 

should be removed from the rule. 

Response to Comment 45: The EPA agrees, and the final rule clarifies this approach.

9. Opposition based on QA/QC requirements.

Comment 46: Several commenters (17716, 17881, 18014) state that the O2 and CO2 CEMS

requirements in section 60.10010(b) should refer to 40 CFR Part 75 in lieu of the alternate requirements 

specified in Appendix A to subpart UUUUU of the docket entry EPA-HQ-OAR-2009-0234. According 

to the commenters, the following text should be added to Table 5 of the docket entry EPA-HQ-OAR2009-0234, as applicable: “Alternatively, for an affected source that is also subject to the O2 or CO2

monitoring requirements of 40 CFR Part 75 of this chapter, the owner or operator may install, certify, 

maintain, operate and quality assure the data from an O2 or CO2 CEMS according to 40 CFR Part 75 in 

lieu of the procedures in paragraphs b(1) through b(3) of this section.”

Response to Comment 46: The final rule includes language comparable to the requested language for 

an O2 or CO2 CEMS. For the SO2 CEMS, see responses to similar comments under 5A08 of this 

document.

Comment 47: Commenter 17716 disagrees with the EPA about additional QA/QC requirements for use 

of SO2 CEMS. The commenter states that although use of SO2 CEMS is allowed for compliance 

demonstration, the requirements state that the operator “must perform the 7-day calibration error test 

required in Appendix A to 40 CFR Part 75 on the SO2 CEMS whether or not it has a span of 50 ppm or 

less.” According to the commenter, because the majority of 40 CFR Part 75 affected sources have 

completed initial certification years ago and have been collecting “quality-assured” data for years, the 

benefit to this requirement is not apparent.

Response to Comment 47: This requirement has been removed in the final rule based comments, and 

we do not think it is appropriate to include the provision pending further review of the technical issue by 

EPA’s monitoring groups.

Comment 48: Commenters 17820 and 17821 state that there are already other monitoring requirements 

for units required to report under Part 60, and there have been attempts to harmonize those rules to 

reduce confusion and cost. According to the commenters, the Part 60 rules, like these proposed rules, are 

not as detailed as Part 75 and could lead to inconsistencies in data quality between operators. Adding 

additional, different, and possibly conflicting requirements for this rule will cause additional confusion, 

increase downtime, and increase costs with no evidence of any benefit. 

Response to Comment 48: The EPA has attempted to harmonize the CEMS requirements under this 

rule primarily with the Part 75 CEMS requirements that already apply to most of the affected EGUs

under this rule.

10. Opposition based on sampling.

Comment 49: Commenter 17316 states that the outlet location for CEMS Probe is not the best location 

for these probes. The commenter states that the “outlet location” defined as the immediate exit of the 
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boiler, just downstream of the combustion process, is not an appropriate location where a “representative 

sample” can be collected. Commenter 17316 recommends that “representative samples” should be 

obtained by locating the probe in the downstream ductwork or in the stack.

Comment 50: Commenter 17655 states that the monitoring requirement for three new monitoring 

devices in existing smoke stacks threatens stack integrity and adds that the EPA did not consider safety 

issues associated with drilling additional holes in existing stacks and chimney liners.

Comment 51: Commenters 17775 and 17928 disagree with the EPA requirement for HAP stack testing 

for EGUs using surrogates, surrogate stack testing for EGUs using CEMS, and surrogate testing for 

EGUs not relying on surrogates for compliance demonstration.

Response to Comments 49 - 51: In response to comments, the final rule has removed all requirements 

for duplicative testing of a HAP and the applicable surrogate. Facilities complying with a surrogate 

standard will conduct the performance test for that standard, and not for the corresponding HAP 

emission limit (and vice versa).

Comment 52: Commenter 18014 states that it is unclear as to whether EGUs that fire a single type of 

fuel are exempt from all fuel sampling and analysis requirements.

Response to Comment 52: This comment is moot because the fuel analysis requirements are not 

included in the final rule.

Comment 53: Commenter 17902 states that installation of additional CEMS for PM and HCl requires 

significant structural modifications, such as: 

a. Installation of additional ports (to install the sampling probe);

b. Stack platforms (additions or modifications to existing platforms to access new monitoring 

equipment);

c. Shelters (to house climate controlled equipment);

d. Electrical instrumentation (to power shelters, heat probes, etc); and,

e. Communications systems (needed fiber optics, Ethernet to communicate with existing computer 

programs).

Response to Comment 53: The addition of new monitoring equipment may require additional 

modifications to existing CEMS infrastructure, although the EPA questions whether the changes are 

significant structural modifications in light of the emission control requirements of this rule. To the 

extent a source believes these changes are too significant, the source can conduct periodic stack testing 

as an alternative to either a PM CPMS or an HCl CEMS.

11. Need clarification on operational limitations.

Comment 54: Commenter 17800 states that the compliance with MACT standards that have numerical 

limits should be based on what is being measured in the stack and not on how the unit is being 

operated. Use of CEMS should preclude operational limits. According to the commenter, the operational 
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requirements in Table 4 of part 63 subpart UUUUU are unnecessary, requiring unneeded record keeping 

that does not improve compliance and should be eliminated from this rule. The commenter states that if 

the unit chooses to install and properly operate and maintain CEMS for filterable PM, Hg and HCl, these 

operating limits are unnecessary. According to the commenter, once the CEMS are certified and 

recording quality assured data, these systems determine the unit’s compliance status. The commenter 

states that the EPA should clarify when CEMS are being used for compliance, operational limitations on 

unit load and the applicable control equipment are unnecessary as well as the reporting requirements in 

section 63.10031 pertaining to those operational requirements.

Response to Comment 54: Where a CEMS is used, EPA largely agrees. As discussed in detail 

elsewhere in this response to comments document, EPA has eliminated all operating limits in Table 4, 

with the exception of an operating limit associated with a PM CPMS, and in limited cases, site-specific 

parameters for liquid oil-fired units. In consideration of the PM emissions limit and the burden 

associated with certifying a PM CEMS via PS11, the agency decided to allow use of a PM instrument 

not as a CEMS but as a CPMS. The operating limit for use in conjunction with a PM CPMS functions in 

the same manner as parameter monitoring from other rules. The highest hourly average of the PM 

CPMS signal produced over three test runs is used as the operating limit, and that value becomes 

averaged over a rolling 30 boiler operating day average. The final rule also does provide for the use of a 

PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this 

approach (see the final preamble for further discussion). In that case, the PM CEMS is used as the direct 

method of compliance and no additional testing is required other than tests that are required as part of 

the QA requirements in PS 11.

12. Requirements for bypass stacks.

Comment 55: Commenter 17718 states that within the proposed regulatory language of 

section 63.10006, there does not appear to be an option for reduced HCl performance testing 

requirements on coal-fired units with non-HCl controlled bypass stacks. The commenter states that 

within the proposed language of section 63.10010(a)(4), it appears that a bypass stack would be required 

to install similar monitoring systems as the main common stack. According to the commenter, without 

flue grade sulphurization technology on the bypass stack, it appears that the current 40 CFR Part 75 SO2

CEMS located on the bypass stack could not be used for compliance determinations as a surrogate 

for HCl. The commenter states that even if the company desired to install an HCl monitor on the dry 

stack to monitor emissions, it would still be required to conduct performance testing every month. 

Comment 56: Commenters 17772 and 17873 state that PM CEMS do not operate properly during 

startups and shutdowns. According to the commenters, PM CEMS are not calibrated under startup or 

shutdown conditions, nor are they calibrated using the changing fuel mix (e.g., moving from 100 percent 

oil to 100 percent coal) associated with start-up, and values during these times are not valid for 

compliance purposes. If a bypass stack is predominately used during startup and shutdown, state the 

commenters, there should be no requirement to install a PM CEMS. The commenters state that the EPA 

has the discretion necessary to regulate PM through a work practice standard; instead of requiring costly

and duplicative monitoring equipment to measure intermittent emissions that occasionally flow through 

bypass stacks, the EPA should develop work place standards that would put parameters around how 

often and when bypass stacks can be employed.

Comment 57: Commenter 17781 states that the periods of EGU startup and shutdown resulting 

in FGD bypass, as well as reasonable periods of FGD malfunction which are addressed in an appropriate 

manner, should not disqualify an EGU from using the SO2 surrogate for HCl.
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Response to Comments 55 - 57: The final rule provides an option to monitor a bypass stack or to treat 

any hour in which the unit bypasses the main stack and fails to collect quality-assured data as an hour of 

monitoring downtime. The EGU owner or operator remains subject to the 30 boiler operating day rolling 

average during bypass operations.

13. Opposition based on maintenance requirements.

Comment 58: Commenters 17775 and 17800 state that the EPA did not account for the fact 

that EGUs need to perform maintenance, in addition to required QA/QC, in order to keep monitoring 

systems running properly. The commenters state that the EPA should recognize this in the 40 CFR part 

63 general provisions, which require sources to maintain their monitoring systems and exempts 

“maintenance periods” from operating requirements. 

Response to Comment 58: Normal maintenance activities associated with quality control (not quality

assurance) procedures in a source’s monitoring plan are exempt as part of the QC exemption provided in 

the final rule. No additional exemption is necessary.

14. Need for clarification on monitoring, recordkeeping and reporting requirements.

Comment 59: Commenter 17776 states that the EPA needs to clarify the proposed rule that monitoring, 

recordkeeping, and reporting requirements do not apply for facilities equipped with CEMS. According 

to the commenter, facilities which use CEMS for monitoring of a regulated pollutant or surrogate should 

not require fuel sampling, parameter monitoring, or compliance with fuel or operational limits. 

Response to Comment 59: The rule does not require monitoring operating limits where a CEMS is 

used for the applicable standard. If a source has PM control equipment and uses a PM CPMS-based

operational limit, no control device monitoring is required. The same is true for SO2/ HCl controls.

Comment 60: Commenter 17776 states that for PM (Item 1) and HCl (Item 3) in Table 5, references to 

Appendix A of subpart UUUUU in the “using” column are listed, but Appendix A of 

subpart UUUU does not address monitoring certification and ongoing monitoring requirements for PM 

and HCl CEMS. 

Response to Comment 60: These cross references have been corrected in the final rule.

Comment 61: Commenter 17725 states that the EGU MACT Rule does not include provisions to use 

the Part 75 “conditionally valid data procedures.” The commenter states that if a CEMS fails a linearity

check, the CEMS remains out-of- control until the successful completion of a subsequent linearity 

check, and this would require the operator to invalidate the Part 75 conditionally valid data (for SO2, 

CO2, O2 or flow monitors) for the EGU MACT recordkeeping and reporting purposes. According to the 

commenter, a clearer approach would be to allow quality-assured data from a CEMS certified and 

operated in accordance to Part 75 to be used for EGU MACT compliance.

Response to Comment 61: The final rule provides for certain Part 75 procedures for the CEMS and 

sorbent trap monitoring systems used to comply with this rule, including the use of the conditionally 

valid data procedures.

15. Lack of variability.
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Comment 62: Commenter 18014 states that the snapshot nature of performance test data means the 

results will provide little insight on the true range of boiler variability and the associated effects on 

emission controls. According to the commenter, the EPA should address the additional variability

introduced by the CEMS within the rule. The commenter states that the “apples-to-oranges” contrast of 

the CEMS versus reference method data (particularly given the current state of PM, HCl and Hg CEMS) 

provides additional support to use the CEMS data as indicators of performance rather than direct 

measures of compliance. According to the commenter, since neither the CEMS measurement variability

or the plant operational variability that will be an inherent part of the CEMS data will not be reflected in 

the reference method-based UPL, a separate multiplier should be applied to the UPL (or applied as an 

additional multiplier to the FVF adjusted floor average) to address for the CEMS/operating variability

issue.

Response to Comment 62: The PM monitoring will be used as a PM CPMS and not as a direct 

compliance method with an emission limit. For the Hg CEMS or sorbent trap monitoring system, and 

the HCl CEMS, EPA disagrees. This issue is discussed in more detail in the comment sections directly

related to Hg CEMS and HCl CEMS. 

16. Missing information.

Comment 63: Commenter 18014 states that the rule does not include the equations for calculating PM 

or HCl mass emissions; Appendix A only includes equations for Hg. 

Response to Comment 63: There is no requirement to calculate PM mass emissions; PM monitoring is 

a parameter-based approach to ensure compliance with an operating limit. For HCl, section 9 of 

Appendix B to the final rule provides the appropriate method for calculating emissions in terms of the 

emission standard.

17. Recommendations.

Comment 64: Commenter 15678 recommends that CEMS need to be certified and recertified according 

to the EPA proposed procedures, such as Table A-1 on page 25140 of the Federal Register (Vol. 76, No. 

85 / Tuesday, May 3, 2011) for the required certification tests and performance specifications for Hg 

CEMS.

Comment 65: Commenter 16849 recommends that further testing and verification of the accuracy of the 

required CEMS equipment at utility sites be conducted before they are used for compliance purposes.

Comment 66: Commenter 17191 recommends that the SO2 monitoring as a surrogate for acid gas HAP

be included as an option for IGCCs as it is for other categories that have SO2 data available.

Comment 67: Commenter 17197 recommends that a footnote be added to Table 5 of the docket entry

EPA-HQ-OAR-2009-0234 that states “Daily calculate a new 30-boiler operating day rolling average of 

all of the hourly CEMs emissions data for the preceding 30-boiler operating days.”

Comment 68: Commenter 17265 is requesting clarification of whether CEMS are warranted across-theboard for the HCl source category, and supports retaining a source’s option to select CEMS as the 

monitoring method, but recommends that the QA provisions be further developed to ensure the 

credibility and accuracy of the data.
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Comment 69: Commenter 17283 recommends proposed alternative standards for total or individual 

metals, including specific language in the final rule allowing enhanced monitoring of these metals with 

multi-metals CEMS as an alternative to Reference Method 29 measurements and/or PM CEMS and/or 

Hg CEMS.

Comment 70: Commenter 17283 states that cycle time equal to or less than 15 minutes is currently

required for CEMS in various places (Table A-1, Table A-2, and pages 25110-25113) of the docket 

entry EPA-HQ-OAR-2009-0234 and strongly recommends that these references to 15-minute cycle 

times be eliminated because, according to the commenter:

a. 15-minute cycle times are not required to evaluate health effects or demonstrate compliance with 

limits,

b. Reference methods require sampling times of about 4 hours at these low concentrations, and

c. The proposed cycle time is not consistent with PS12 A or Cement MACT rules.

Comment 71: Commenter 17283 recommends that units employing PM CEMS should be exempted 

from federal and state opacity monitoring requirements.

Comment 72: Commenter 17677 recommends that the EPA must have certifiable methods for source 

CEMS in order to determine accuracy. According to the commenter, without certifiable 

methods/procedures, data accuracy cannot be relied upon for compliance determinations.

Comment 73: Commenter 17677 recommends that the EPA clarify the language relating to initial 

compliance demonstrations for CEMS.

Comment 74: Commenter 17730 recommends that the EPA should provide procedures for averaging 

actual emissions data from CEMS to determine monthly average weighted emissions and revision of 

section 63.10009 to include procedures for units using CEMS to calculate average weighted emissions 

in lieu of compliance with the operating limits for control devices proposed in section 63.10022.

Comment 75: Commenter 17681 recommends that the EPA should allow compliance to be 

demonstrated based on stack tests and CAM plans.

Comment 76: Commenter 17638 recommends that the EPA allow compliance to be demonstrated based 

on stack tests and CAM plans other than PM and HCl CEMS.

Comment 77: Commenters (17716, 18014) recommend that the EPA should revise section 63.10007 to 

indicate that the fuel sampling and operating parameter limits are not required when the applicable HAP 

(or surrogates) are monitored using a CEMS.

Comment 78: Commenter 17731 concurs that the performance stack testing requirements set out in 

Table 5 (part 76 CFR 25129-31) should not be required of those EGUs that use CEMS for continuous 

compliance because the requirements are redundant and burdensome without providing added benefit.

Comment 79: Commenters (17767, 17881, 18428) recommend that it is appropriate that the proposed 

rule does not require the generation and submittal of missing data substitutions, as the emissions 

limitations are rate-based and not mass-based.
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Comment 80: Commenter 17775 recommends that the EPA should allow use of 40 CFR Part 75

provisions as an alternative for diluent monitoring.

Comment 81: Commenter 17775 recommends that the EPA revise section 63.10010(a) to acknowledge 

the other monitoring options in the rule (including the option of stack testing with monitoring of 

operating parameters and, fuel analysis for liquid oil-fired units), or limit applicability of the section to 

those circumstances where an EGU opts to, or is required to install a CEMS or sorbent trap system.

Comment 82: Commenter 17775 recommends that the EPA should eliminate the redundancy between 

section 63.10010(a)(4) and Appendix A section 2.

Comment 83: Commenter 17775 recommends that the EPA include provisions similar to 40 CFR Part 

75 that allow EGUs that are otherwise using CEMS to report a site-specific default value during bypass 

in lieu of installing and maintaining CEMS on the bypass stack.

Comment 84: Commenter 17776 recommends that the EPA should revise the requirement to use 

PM CEMS for demonstrating continuous compliance with the total PM limit. PM CEMS can only

analyze for filterable PM per EPA PS 11.

Comment 85: Commenter 17776 recommends that the EPA should allow the use of sorbent trap 

monitoring systems as another means for continuous monitoring of Hg emissions. Commenter also 

recommends that the EPA allow annual performance tests for HCl until HCl CEMS technology 

advances further.

Comment 86: Several commenters (17725, 17820, 18014, 19033) recommend that section 

63.10010(b)(5) should be revised to include CO2, for example, “the average of all of the hourly oxygen 

or carbon dioxide emissions data for the preceding 30 boiler operating days,” and that section 

63.10021(a)(10)(ii) should include a reference to CO2 records.

Comment 87: Commenters (17718, 18037, 18539) recommend that performance testing should be 

conducted annually for each of the stacks instead of every other month as currently proposed. According 

to the commenters, it may not be feasible to complete testing at all units within a monthly or 2-month 

period due to lack of test crews, unit scheduling, scheduled maintenance, and other considerations.

Comment 88: Commenter 17722 states that the EPA should allow “to-be-approved” monitoring 

techniques and technologies as part of the final rule. As one example, Commenter is aware of a 

novel sorbent tube technology that is under development by the University of North Dakota’s Energy

and Environmental Research Center (“EERC”), where the sorbent tubes are designed to measure HAP 

acid gases and non-Hg HAP metals. According to the commenter, EERC is under contract with the 

Department of Energy to run parallel Method 26 and Method 29 tests later this year, and if 

these sorbent tubes prove viable, like Hg sorbent tubes, the final EGU NESHAP rule should allow use of 

this new approved monitoring technology.

Comment 89: Commenters 17821 and 17881 recommend removal of requirements for calculating (and 

reporting) long-term 30-day rolling averages for O2 (and CO2) emissions. O2 (and CO2) concentration 

data are typically used as a diluent gas when using CEMS measurement data to calculate emission rates 

in terms of lb/MMBtu. According to the commenters, the diluent gas components of these equations 

under 40 CFR 60 are not averaged into long-term averages; only the emission rate data (lb/MMBtu) are 

averaged over long-term periods, and these long-term emission rate averages are calculated not from 
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long-term O2 or CO2 averages and long-term SO2 or NOX averages, but from the hourly emission rate 

data that is calculated using the hourly diluent gas values.

Comment 90: Commenter 17821 recommends that the EPA allow the use of certified flow monitoring 

systems to calculate emissions rates when volumetric flow rate is needed. The commenter states that 

volumetric flow CEMS certified in accordance with 40 CFR 75 are used for reporting purposes already

and allowing these data to also be used to calculate mass emissions would provide consistent data.

Comment 91: Commenter 17881 states that the provisions at section 63.10010(b)(4) require that 

CEMS data be reduced to 1-hour averages according to the requirements in section 63.8(g)(2) and (4). 

According to the commenter, these data reduction procedures are not fully consistent with the 

procedures specified at section 60.13(h) and section 75.10(d)(1), and commenter suggests that the 

preceding data reduction procedures be allowed as alternatives to those which are currently specified.

Response to Comments 64 - 91: The EPA has considered all of these various recommendations in 

finalizing the proposed monitoring requirements. In general, the final rule builds on the proposed 

requirements by providing for monitoring continuous compliance with specific standards through the 

use of an applicable CEMS, or a sorbent trap for Hg, or a PM CPMS for non-Hg metals or PM. Should a 

source owner or operator elect not to use CEMS or the other instrumental methods, performance testing 

is required. In revising the proposed rule, the EPA has finalized an approach that builds off the Part 75

requirements wherever possible for CEMS. The EPA believes that the initial and ongoing certification 

and QA procedures for applicable CEMS are appropriate for ensuring the collection and reporting of 

quality data. The final rule includes a variety of specific changes to help clarify the use of CEMS versus 

operating parameter monitoring, calculation of 30-day rolling averages, and other specific issues with 

the monitoring requirements raised in these brief recommendations and more specific comments on 

aspects of the proposed standards. Where a source owner or operator wishes to use an alternative 

monitoring approach, such as a multi-metals CEMS, the source owner or operator may propose such a 

method under the general provisions in section 63.8(f) of subpart A of part 63.

18. Need for clarifications of rule.

Comment 92: Commenters 17718 and 17881 request that the EPA clarify when the 30-day operating 

period begins if the systems are already certified (e.g., current SO2 or PM CEMS being used for 

40 CFR Part 75 and/or 40 CFR Part 60 monitoring programs). 

Response to Comment 92: The 30-day period will begin on such date as you indicate in your 

Notification of Intent to conduct a performance test (see section 63.10030(d)). You must complete the 

initial test within the period specified in the rule.

Comment 93: Commenter 17718 states that the EPA should clarify whether initial testing of the bypass 

emissions needs to be tested within the 180-day timeframe described in the proposed language and that 

alternatively, setting a firm testing timeframe on bypass stack emissions seems overly burdensome. 

According to the commenter, creating emissions (and incurring costs) by switching a unit into bypass 

mode that would not otherwise have been used simply in order to perform emission testing appears to 

create unnecessary burden.

Response to Comment 93: Under the final rule, you may elect to monitor the bypass stack or treat 

hours in which the bypass is used as monitor downtime. The EGU owner or operator remains subject to 

the 30 boiler operating day rolling average during bypass operations. To report data from any 
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monitoring on a bypass stack, you do need to have a certified monitoring system. Because you can 

decide to not monitor the stack, there is no requirement that the certification occur in the first 180 

operating day period.

Comment 94: Commenters 17718 and 19121 states that in the proposed regulatory language seen in 

section 63.10005(l), it is mentioned that a “default diluents gas concentration value of 10.0 percent O2 or 

the corresponding fuel-specific CO2 concentration” are to be used during periods of startup or shutdown 

when calculating emissions in units of “lb/MMBtu” or “lb/TBtu.” According to the commenter, the EPA 

should clarify how to calculate the “corresponding fuel-specific CO2 concentration.”

Response to Comment 94: Because of the revisions related to startup and shutdown provisions, the 

cited language is no longer applicable. 

Comment 95: Commenter 17820 cites that Table 8 states that the source is to convert “hourly emissions 

concentrations to 30 individual boiler operating mg/dscm values,” which suggests that compliance is 

assessed based on the average of 30 individual daily values but that section 63.10010(g)(5) states that 

30-day rolling average is calculated as “the average of all of the hourly particulate emissions data for the 

preceding 30 boiler operating days.” The commenter states that this requirement needs to be clarified.

Response to Comment 95: The referenced language in the proposed rule is not used in the final rule.

Provisions in Appendix A and Appendix B to the final rule describe the procedure for calculating 30-day

averages where an Hg CEMS, sorbent trap monitoring system, or HCl CEMS are used for compliance. 

Overall, the language in the final rule ensures a uniform approach for calculating averages from CEMS 

data and from a PM CPMS.
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5A11 - Testing/Monitoring: Disable bias tests for Hg, HCl, and PM CEMS

Commenters: 17718, 17740, 17816, 17820, 17873, 17877, 17881, 17909

1. Support for eliminating bias tests.

Comment 1: Multiple commenters (17718, 17740, 17816, 17820, 17873, 17877, 17909) recommend 

that the EPA disable the ECMPS Part 75 bias test for Hg, HCl, and PM CEMS. The commenters state 

that bias adjustment may be appropriate for emissions trading programs to ensure that companies are not 

under-reporting their emissions and, hence, failing to surrender an adequate number of allowances for 

compliance purposes, but it is unnecessary for compliance with the MACT standards.

Comment 2: Commenters 17718 and 17816 support the EPA’s proposed approach to streamline the 

continuous compliance requirements for monitoring, reporting, and recordkeeping and urge the EPA to 

remain open to additional accommodations that are identified in the course of implementing the 

program.

Comment 3: Commenter 17877 states that eliminating the bias test for these monitors will also reduce 

the file size, complexity, and time required to maintain and report quality assured data.

2. Other bias test comments.

Comment 4: Commenter 17881 states that the proposed EGU MACT rule appears to be silent on the 

concept of whether SO2 missing data substitution under 40 CFR Part 75 would be allowed in the context 

of 63.10010(e)5. In addition, states the commenter, the concept of bias adjustment factors (BAFs) under 

40 CFR Part 75 does not appear to be addressed. According to the commenter, in other cases where the 

EPA has allowed the use of Part 75 CEMS for compliance demonstrations under other regulatory

programs (i.e., 40 CFR Part 60, subpart Da), the EPA has prohibited the use of missing data substitution 

and BAFs.

Response to Comments 1 - 4: As suggested in the proposed rule, the final rule does not require any bias 

adjustment when reporting data under this rule. For missing data related comments, see responses to 

comments under Comment Code 5A12.
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5A12 - Testing/Monitoring: CEMS monitor out-of-service versus missing data substitution

Commenters: 17316, 17620, 17655, 17818, 17821, 17877, 17881, 17886, 17904, 18023

1. Agrees that there is no need for missing data substitution.

Comment 1: Several commenters (17655, 17877, 17904) agree with the EPA that there is no need for 

missing data substitution procedures in this monitoring scheme. According to the commenters, missing 

data routines are unique to those programs that are market-based rather than performance based in their 

design. The commenters state that since these monitors are not considered instruments of commerce, 

normal monitoring downtime provisions should apply.

Comment 2: Commenter 17877 notes that hours when a monitor is out of service should be counted as 

monitor down time against the percent monitor availability, but substituting data is unnecessary. 

According to the commenter, maintaining a consistent set of rules to govern monitors that are only used 

to demonstrate compliance with an emission limit not tied to trading, simplifies the assurance of ongoing compliance for both the regulated community and the regulators. The commenter states that 

eliminating missing data substitution for these monitors will also reduce the file size, complexity, and 

time required to maintain and report quality assured data.

2. Options for missing data substitution.

Comment 3: Commenter 17620 suggests that sources should be required to infer emissions during 

monitor downtime at the highest daily rate over the past 90 days during each hour that a monitor is not 

in service.

Comment 4: Commenter 17818 disagrees with the EPA’s proposal to not require data substitution 

during monitor downtime for Hg, HCl, or PM CEMS. The commenter understands that under the Acid 

Rain Program the data substitution is essential to properly account for all mass emissions for the 

pollutant in question, but for the proposed rule, compliance with HAP emissions limitations takes place 

over a relatively long period of time. The commenter’s opinion is that it is appropriate to require data 

substitution for compliance with long-term emission rate limits to help ensure that a more accurate 

indication of unit emissions is developed during all periods of unit operation in order to assess the unit’s 

compliance with the applicable emissions limitation. The commenter also notes that a requirement for 

data substitution will also help encourage the owner/operator to maintain the related CEMS in a high 

state of accuracy and availability.

Comment 5: Several commenters (17316, 17821, 17881) state that there are conditions other than those 

listed in section 63.10020(b) that are legitimate reasons for monitoring system data loss and should also 

be excluded from downtime reporting. The commenters state that these conditions include: planned and 

unplanned preventive maintenance, corrective action maintenance, diagnostic checks, linearity tests, 

system integrity checks, cylinder gas audits, QA/QC, system purges, installation of system upgrades, 

etc. The commenters request that the EPA revise section 63.10020 to reflect that these conditions are not 

deviations of monitoring requirements. 

Comment 6: Commenter 17316 states that traditionally CEMS regulations have been performance 

based, and this approach has worked well. The commenter states that if the EPA believes monitoring 

system data loss to be a significant issue then the rule might establish a minimum data recovery
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threshold, such as 95 percent data availability per quarter, exclusive of calibrations, preventive 

maintenance and QA testing, as is done in many permits.

Comment 7: Commenter 18023 states that a penalty should not be associated with Hg system 

availability or monitor downtime. The commenter states that this is because: (1) Hg monitor repairs take 

much longer to recover and settle once the system is returned to service than current CEMS analyzers 

for NOX and SO2, (2) QA/QC activities take longer to perform, especially with the required calibrator 

checks, and (3) the sorbent trap versus continuous monitor issue is almost an apples to oranges argument 

regarding availability with missing days/weeks for sorbent traps versus missing hours for monitors. 

According to the commenter, section 6.1.3 will only increase the amount of monitor downtime; total 

availability should be calculated and recorded for tracking purposes but penalties should not be 

associated with them, especially with the limited experience performing QA/QC with these devices.

Comment 8: Commenter 18023 states that under section 6.1.3 Data Reduction and Calculations, the 

rule should allow the use of valid Part 75 substituted data for these parameters since those substituted 

values are acceptable to the EPA for other emission monitoring programs. 

Comment 9: Commenter 17886 states that section 63.10020(c), should exclude preventative 

maintenance and corrective action maintenance activities in what should be considered a deviation of the 

monitoring requirement.

Response to Comments 1 - 9: We have not included any specific minimum data availability

requirement for CEMS or other monitoring in this final rule nor do we provide a specific tool for data 

substitution. We believe that there are other provisions in the final rule to provide incentives to conduct 

monitoring in a manner consistent with good air pollution control practices and to provide data sufficient 

to demonstrate compliance with a relatively long-term emissions rate limit (e.g., lb/MMBtu or lb/MWh). 

We agree that data quality certainty associated with any calculated value decreases with the collection of 

fewer data such as would occur with extended periods of monitoring system downtime. Even so, we 

believe also that it is necessary and critical to compliance with the regulation that a source uses all 

measured data collected during an averaging period to assess compliance regardless of any periods of 

missing data. Sources should not disqualify any data otherwise meeting required data quality 

requirements simply because there were data missing for other hours or days of the averaging period.

Instead of a minimum data availability threshold that would invalidate data collected for some averaging 

periods because one did not collect data for at least “x” percent of an averaging time, the final rule 

requires that a source report as deviations to the rule failure to collect data during required periods and 

that are not covered by exceptions allowed in the final rule. 

On the issue of applying a data substitution procedure to represent actual emissions or pollution control 

performance, we believe that defensibility concerns make it incumbent on you to collect and evaluate 

other information in accordance with 40 CFR section 63.6(f)(3) during periods of monitoring downtime 

to assure compliance with the applicable emissions limitations and standards.

We believe that enforcement authorities also can and should determine whether a source is meeting any

monitoring system operating requirements. Should the source or the enforcement authority be concerned 

about the representativeness of data such as during periods of missing data, either may consider 

collecting information through other means (e.g., supplemental emissions testing) to fill data gaps not 

only because such gaps are deviations from the rule but such gaps can lead to uncertainty about 

compliance status.
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We further believe that the final rule provides sufficient means to ensure CMS performance and ongoing 

compliance without specifying an arbitrary numerical minimum data availability or data substitution 

requirement. We believe that specifying that failure to collect required or otherwise excepted data is a 

deviation from the rule will provide the necessary incentive to collect data sufficient to demonstrate 

compliance with the limits in the final rule.
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5A13 - Testing/Monitoring: Oil monitoring option

Commenters: 17316, 17870

Comment 1: Commenter 17316 observes that section 63.10011 seems to indicate that a unit may not 

fire any fuel whose Hg, chlorine, fluorine or non-Hg total Metals content is greater than that measured in 

the fuel combusted during performance testing (unless the unit is equipped with a CEMS), so that HAP

content of the fuel combusted during performance testing establishes an upper bound on the HAP fuel 

content for all subsequent fuel deliveries (until the next performance test), without any consideration of 

the extent to which performance test emissions were below the applicable MACT standard. The 

commenter states that this approach to setting fuel based MACT operating limits seems unnecessarily

restrictive, and imposes very difficult compliance issues, as the HAP content of fuel oil is not subject to 

contract specification. The commenter proposes an alternative method to establish a maximum allowed 

HAP: adjust the HAP content of the fuel oil combusted during performance testing to account for the 

amount by which measured stack HAP emissions fell below the applicable HAP standard. The 

commenter states that this same approach could be applied to all fuel oil HAP constituents because: (a) 

the only source of Hg, chlorine, fluorine, and non-Hg metals is the fuel itself, and (b) because it is 

reasonable to assume that the fraction of HAP in the fuel emitted as stack emissions should be relatively

constant, so long as any add-on controls are operating properly, it would seem reasonable and 

appropriate to proportion up the HAP content of the fuel combusted during performance testing, by the 

ratio of HAP emission standard to the measured HAP emissions, in order to determine an appropriate 

operating limits for each HAP constituent in fuel oil. According to the commenter, this approach 

protects the standard, but avoids placing an unmanageable and unfair compliance (fuel) restriction on 

the site.

Response to Comment 1: The comment is moot because the rule no longer requires fuel analysis or 

operating limits based on non-Hg metals content of fuel. The only fuel monitoring provision in the final 

rule is an option for liquid fuel units to use fuel moisture monitoring. If you combust liquid fuels and 

you wish to demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel 

moisture content of fuel in place of quarterly stack testing.

Comment 2: Commenter 17316 states that in regard to requirements that if a source demonstrates 

compliance with HAP limits “based on fuel analysis, you must conduct monthly fuel analysis for each 

type of fuel burned.” The commenter notes that oil is a homogeneous fuel that is relatively consistent 

(from shipment to shipment), and therefore such frequent fuel sampling and analysis for oil-fired EGUs

is not warranted.

Comment 3: Commenter 17316 states that the monthly fuel analysis required in section 63.10006(s) 

contradicts the discussion of this topic in the preamble (FR page 25053 column1) which specifies that 

(after the initial compliance demonstration by fuel analysis)], the EPA “is proposing a source be 

required to recalculate the fuel pollutant content only if it burns a new fuel type or fuel mixture.” The 

commenter is concerned that this requirement is unjustified for sites that receive oil deliveries less 

frequently than monthly. The commenter proposes that fuel sampling for oil fired units only need be 

conducted in months that additions are made to the oil storage tank serving the boiler, but this sampling 

should be conducted subsequent to all deliveries in the month.
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Response to Comments 2 - 3: Much of these comments are moot because the rule no longer requires 

fuel sampling; however, the agency agrees that fuel moisture sampling (if that option is selected by a 

source) need only occur on delivery of a new shipment of fuel oil.

Comment 4: Commenter 17870 asks for clarification of the rule allowing fuel analyses to demonstrate 

initial and continuous compliance with applicable emission limitations, as an alternative to performance 

stack testing and continuous compliance. The commenter states that in the rule, owners/ operators of all 

affected liquid oil-fired units may perform fuel analyses to demonstrate initial and continuous 

compliance, but in the preamble (FR page 25031) limited-use liquid oil combustion units are allowed “to 

demonstrate compliance with the Hg emission limit, the HAP metals, or the HCl and HF emissions 

limits separately or in combination based on fuel analysis rather than performance stack testing, upon 

request by you and approval by the Administrator.” The commenter asks for clarification on whether 

this applies to limited-use or all liquid oil-fired units.

Response to Comment 4: In large part, this comment is moot, as the rule no longer allows metals or 

hydrogen halide sampling of fuel oil. As mentioned elsewhere, in reviewing comments on monitoring 

frequency and burden, the agency dropped fuel analyses and operating limits based on those fuel 

analyses, reduced stack testing frequency to quarterly for both units with and without controls, and 

developed a stack testing exemption in quarters with limited operating hours. In particular, units that 

exhibit limited use – less than seven days of boiler operation per quarter – are exempt from testing for 

that quarter; however, each unit must perform a stack test at least annually. The limited use provision 

gives relief to sources while maintaining expected emissions performance. In addition, if an EGU has an 

annual oil-fired capacity factor of less than 5 percent, then the only standard that applies is the 

performance tune-up requirement (see Comment Code 4D02 of this document). Should an owner or 

operator of a liquid oil-fired unit choose not to conduct stack testing to demonstrate compliance, the rule 

allows an owner or operator to choose continuous monitoring as an alternative means of demonstrating 

compliance. In addition, the rule will still contain HCl and HF emissions limits for units that combust 

fuel oil and use of emissions testing or of CEMS to demonstrate compliance with those emissions limits, 

but the rule will allow moisture content sampling of the fuel oil as an alternative means of demonstrating 

compliance for units that have fuel moisture content no greater than 1.0 percent. The rule no longer 

requires establishment of operating parameters for control devices for these pollutants. See more 

discussion of the EPA’s responses to operating parameter monitoring under Comment Code 5A06 in this 

document.
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5A14 - Testing/Monitoring: Other

Commenters: 16513, 16849, 17316, 17402, 17620, 17622, 17626, 17627, 17637, 17638, 17655, 17681, 

17690, 17696, 17697, 17704, 17705, 17715, 17716, 17718, 17724, 17725, 17729, 17730, 17731, 17737, 

17739, 17740, 17754, 17758, 17760, 17761, 17767, 17775, 17781, 17796, 17800, 17803, 17804, 17805, 

17807, 17808, 17812, 17813, 17816, 17818, 17820, 17821, 17838, 17855, 17856, 17867, 17868, 17870, 

17873, 17880, 17881, 17886, 17902, 17909, 17925, 17927, 17928, 18014, 18024, 18025, 18031, 18034, 

18039, 18428, 18444, 18477, 18487, 18498, 18502, 18539, 18963, 19033, 19114, 19120, 19121, 

19536/19537/19538, 18023

1. Commenters concerned about the proposed frequency of performance tests.

Comment 1: Numerous commenters (17402, 17627, 17638, 17681, 17696, 17704, 17716, 17718, 

17725, 17737, 17740, 17758, 17760, 17775, 17796, 17800, 17803, 17804, 17807, 17816, 17820, 17821, 

17838, 17856, 17867, 17870, 17881, 17902, 17909, 17925, 18014, 18025, 18031, 18428, 18444, 18477, 

18963, 19033, 19114, 19120) believe that the proposed frequency of performance testing under section 

63.10006 is excessive or overly burdensome.

Comment 2: Commenters 16513 and17804 state that the rule would significantly increase the workload 

of state agencies by as much as 50 percent as a result of observing emission tests and/or reviewing 

emission test protocols, and updating AFS. Commenters recommend revising the testing to quarterly or 

biannually. . 

Comment 3: Several commenters (17402, 17627, 17704, 17716, 17718, 17760) state that the EPA 

should allow facilities to comply with the performance testing requirements on an annual basis similar to 

their current permit requirements. Commenter 17402 believes that less frequent stack testing coupled 

with more frequent fuel sampling can ensure continuous compliance because data in the docket indicate 

that over the long term, emissions are fairly consistent despite potential variability in fuels and 

operations. Commenter 17402 believes that annual Method 29 stack testing combined with existing 

permit requirements (to properly operate air pollution control equipment at all times) combined with 

monthly fuel samples and calculations (consistent with proposed section 63.10011) compose a viable 

means for ensuring continuous compliance. Commenters (17402, 17718) believe this suggested 

combination is preferable to the logistical and cost concerns implicit in monthly or bi-monthly testing 

requirements, and the commenters cite the limited availability of test crews, coordination with system 

dispatch, scheduled boiler maintenance, and winter storms as constraints that make the proposed 

monthly and bi-monthly testing frequencies infeasible. Commenter 17402 provides an analysis of stack 

test data submitted by EGU operators under the ICR to support his position that emission rates are 

stable.

Comment 4: Commenter17760 indicates that many dual-fuel (oil or gas) units maintain permits to burn 

fuel oil for periods of high electricity demand when natural gas may not be available (due to residential 

heating demand) and states that recent natural gas prices make fuel is concerned that the monthly or bimonthly testing requirements will force dual. The commenter states that first, the proposed frequency of 

testing will impose a significant cost burden on plant operators. For example, all of commenter 17803’s 

units are gas capable and, with the current difference in oil and gas prices, oil is consumed only during 

periods of gas unavailability or as required by the New York Independent System Operator to ensure 

reliability during periods of high electric demand. According to the commenter, monthly testing would 

result in significant economic burdens. For example, commenter 17803’s cost of the uneconomic oil 

consumed during the 2010 ICR testing last year was approximately $2-3 million. Second, states the 
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commenter, inflexible testing schedules may induce units to run solely for testing purposes, leading to 

increased emissions. According to the commenter, any oil-fired units are operated as peakers or cycling 

units, and may spend a significant portion of the year off-line and the proposed testing requirements 

would require these units to run even if there were no demand for additional power. Commenter 17316 

adds that for dual fuel (oil/gas) units, the proposed testing regimen is even more environmentally 

counter- productive because these units tend to operate on natural gas during the ozone season, but 

proposed section 63.10007(c) would require the firing of oil during ozone season.

Comment 5: Several commenters (17316, 17627, 17716, 17718, 17725, 17760) state that the proposed 

performance testing requirements for sources without CEMS are cumbersome and expensive for units 

with low annual capacity factors (e.g., oil-fired units) because frequent performance testing could 

require operation of such units during periods of low electricity demand when such units normally do 

not operate. Commenters (17316, 17760) state that in some cases the proposed testing frequency for oilfired units with low annual capacity factors will result in an increase in annual HAP emissions that could 

exceed any reduction in hourly emission rates achieved by the rule. Commenter 17760 adds that if the 

EPA does not agree with annual testing of oil-fired units with low annual capacity factors, then the 

testing frequency should be a function of “fuel operating” hours.

Comment 6: Several commenters (17627, 17718, 19114) believe that the EPA’s assertion that most 

units will choose to install CEMS rather than the burdensome stack testing option may be faulty because 

HCl CEMS technology is not yet available, PM CEMS are still quite unproven, and other CEMS

systems may be incapable of measuring emissions as low as the EPA has proposed. Commenter 19114 

further states that for low capacity units they have determined that they could not complete such testing 

at all of its units within a 2-month period due to lack of test crews, unit scheduling, scheduled 

maintenance, and other considerations. According to the commenter, the EPA should consider the 

frequency and types of monitoring appropriate for various subcategories, including an exemption for 

low capacity factor and LEE units.

Comment 7: Several commenters (17638, 17681, 17725, 17740, 17758) state that the proposed monthly

or bi-monthly testing frequency is excessive, unnecessary, and cost prohibitive. Commenters (17638, 

17681, 17758) note that the EPA established the limits based on single tests from multiple units, and 

conclude that there is no basis for the proposed frequency.

Comment 8: Commenter 18477 states that to conduct source testing, commenter must establish a 

schedule that maximizes the amount of work done by the vendor in the minimal amount of time, in order 

to manage the exorbitant cost of importing such expertise and equipment. The commenter states that any

upset that occurs during the source testing schedule, a common phenomenon when testing multiple units 

within a relatively short time frame, further strains commenter’s generation resources. Commenter states 

the current proposed rule, assuming installation of control devices for non-Hg metals on all 14 of 

commenter’s units, testing each of 14 steam units every other month equates to 84 source tests annually. 

If the four units commenter has identified for potential retirement were not equipped with such devices, 

108 source tests would be required under the proposed rule. In either case, states the commenter, the 

proposed rule’s non-Hg metals source testing regime would be a severe burden to our already 

overburdened ratepayers. The commenter notes that the cost of source testing in significantly higher 

than in the continental U.S. and that the commenter paid a 20 percent premium to perform the ICR

testing.
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Comment 9: Several commenters (17760, 17881, 18477) note that annual testing would be consistent 

with the industrial boiler MACT (DDDDD), stationary combustion turbine MACT (YYYY), and the 

RICE MACT (ZZZZ) that provides semi-annual to annual testing.

Comment 10: Commenters 17870 and 17881 state that the proposed testing frequency is impractical to 

conduct especially in the northern climates where temperatures in many months (about 5) of the year are 

too cold. According to the commenters, severe weather events can postpone stack access for safety 

reasons (ice, lightening), thus reducing the margin of maintaining such a rigorous test schedule. The 

commenters state that the process of submitting test notifications, conducting the test, and then reporting 

is a never ending paperwork loop. Commenter 17881 suggests that annual testing is more reasonable for 

units without CEMS but with controls and operating limits and semi-annually for units with 

CEMS. Commenter 17870 suggests the all stack testing requirements governing coal-fired EGUs should 

be no more frequently than quarterly under standard operation (i.e., unless boiler operations or 

characteristics are substantially altered, in which case initial testing should be repeated). According to 

the commenter, quarterly stack testing in combination with parameter monitoring (discussed below) 

should be enough to ensure that a unit is operating within the required limits, and quarterly testing would 

capture seasonal variations in operation while not unnecessarily repeating testing of the same conditions.

Comment 11: Commenter 18502 recommends that the EPA reduce the compliance testing requirements 

based on the relatively small size and emissions and remoteness of non-continental EGUs burning liquid 

oil.

Response to Comments 1 - 11: In response to these comments, the final rule includes a number of 

changes from the proposed rule that will reduce the overall testing required under the final rule. First, 

the final rule establishes a separate subcategory for an EGU with an annual oil-fired capacity factor of 

less than 5 percent. These units are subject only to the performance tune-up work practice standard in 

the final rule. Second, the optional periodic testing requirements have been made consistent between 

controlled and uncontrolled sources, with a reduced frequency of quarterly performance testing. In 

addition, the final rule has removed all requirements for duplicative testing of a HAP and surrogate

standard (such as filterable PM and HAP metals).

Comment 12: Commenter 17856 questions the need for such frequent stack testing for units with 

CEMS because of the extensive operational and parametric monitoring.

Response to Comment 12: The final rule has been amended to not require additional performance 

testing if complying with Hg, HCl or SO2 CEMs. For sources electing to use PM CPMS, the 

performance testing frequency has been reduced to annual testing.

Comment 13: Multiple commenters (17638, 17681, 17690, 17716, 17725, 155, 156, 17758, 17760, 

17803, 17820, 17870, 17902, 17909, 18014, 18025, 18428, 18498) believe that the testing frequency for 

units opting to comply with the non-Hg HAP metal or HCl emission limits should be once every four 

unit operating quarters (not calendar quarters), but no less frequently than once every eight calendar 

quarters following the required frequency for RATA’s at 40 CFR Part 75, Appendix B, section 2.3.1.1 

and using the definition for “operating quarter” under part 72.2 (i.e., 168 or more unit operating hours). 

Commenters 17820 and 17881 state that testing guidelines under section 63.10006(n) should use the 

operating days and quarters approach of Part 75.

Response to Comment 13: As previously explained, the optional periodic testing requirements have 

been made consistent between controlled and uncontrolled sources, with a reduced frequency of 
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quarterly performance testing. In addition, the final rule has removed all requirements for duplicative 

testing of a HAP and a separate alternate equivalent standard (such as filterable PM and HAP metals).

Comment 14: Multiple commenters (17716, 17725, 155, 17820, 18498, 17775, 17800) request that the 

testing provisions in the final rule incorporate a grace period similar to the Part 75 provisions. According 

to the commenters, such a grace period allows a source time to complete testing after coming back 

online and would benefit sources and the EPA by eliminating the need for submission of source specific 

petitions to seek minor extensions of testing deadlines.

Response to Comment 14: The EPA disagrees that the grace period provisions should be applied to 

when a source is unable to complete testing by the deadline specified per 63.7 and explained in the 

“Clean Air Act National Stack Testing Guidance” released on April 27, 2009.

Comment 15: Several commenters (17716, 17821, 17881) state that the specific testing deadlines that 

are provided in section 63.10006(n) will be overly burdensome not only for limited operation units, but 

also for units in extended planned or unplanned maintenance outages. The commenters note that section 

63.10006(n) does provide windows for testing, they may be inadequate for planned unit maintenance 

outages. Commenter 17821 suggests establishing guidelines and allow sources to work with state and 

local permitting agencies to schedule tests. 

Comment 16: Commenter 18025 recommends that a unit operating hour be defined as a clock hour 

during which a unit combusts any regulated fuel, either for part of the hour or for the entire hour. 

Commenter is recommending that this definition apply specifically to the regulated fuels under the 

Utility Toxics Rule (e.g., coal and liquid oil). By requiring a minimum level of operation to trigger stack 

testing requirements, states the commenter, this approach would ensure that no unit is run simply for the 

sake of testing

Response to Comments 15 - 16: As previously explained, the optional periodic testing requirements 

have been made consistent between controlled and uncontrolled sources, with a reduced frequency of 

quarterly performance testing. In addition, the final rule has removed all requirements for duplicative 

testing of a HAP and a surrogate standard (such as filterable PM and HAP metals).

Comment 17: Commenter 17681 recommends the testing schedule, instead of annual testing on a 13-

month timescale, be revised to “or every other federal fiscal year” or something along those lines so that 

facilities may coordinate testing with their state required permits for consistency.

Comment 18: Commenter 19033 recommends that the HCl sampling frequency be reduced from every

other month to quarterly in the second year, and biannual the third year if HCl emissions are measured 

to be non-detectable for all tests conducted. Accordingly, the commenter recommends that section 

63.10006(j) be amended, as follows: (j) For solid oil-derived fuel- and coal-fired EGUs without HCI 

CEMS but with HCl emissions control devices, you must conduct all applicable performance tests for 

HCl emissions according to Table 5 and section 63.10007 at least every other month during the first 

calendar year after the standard becomes applicable. Provided that HCI emissions are measured to be 

non-detectable, the HCI emissions testing frequency may be reduced to quarterly during the second year 

and bi-annual the third year.

Commenter 17722 states that for language in section 63.10006(j), the EPA should add an exception for 

EGUs monitoring continuously by SO2 CEMS, as the bi-monthly performance tests are not required for 

continuously monitored surrogates.
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Comment 19: Commenter 17821 states the proposed testing frequency constrains a company’s ability

to follow customer demand and increases a company’s cost to operate its generation resources. 

According to the commenter, existing tests such as periodic RATAs are less frequent, of shorter 

duration, and/or allow much more operational flexibility, and the proposed Utility MACT tests by

comparison are far more frequent, of longer duration, and demand more operational restrictions 

requiring operators to focus on making their generating units available for testing conditions to the 

detriment of the primary function of generating electricity. The commenter states that the proposed rule 

is too prescriptive in telling sources how they are to operate their facilities. According to the commenter

the EPA fails to recognize that requiring a single unit to satisfy testing conditions also constrains other 

units in the system.

Comment 20: Commenter 17796 questions the proposed frequency of stack tests in section 

63.10006(d). As an alternative to the requirement for monthly or bimonthly stack tests (depending on 

the use of control devices), the commenter recommends that once the initial performance test is 

conducted for PM (filterable and condensable) and non-HAP metals, and fuel sampling procedures and 

operating parameters are established, compliance will be assured by the use of such fuel sampling and 

operating data combined with less frequent (semiannual) stack testing.

Comment 21: Commenter 17925 recommends that continuous compliance source testing should be 

required no more frequent than annually. The commenter states that the EPA has had a past history of 

requiring annual source testing at coal-fired units where continuous monitors for certain emission 

species either didn’t exist or couldn’t be applied at the source; for instance, at some coal fired units in 

the past, opacity monitors couldn’t be applied on wet plumes after scrubbers. As a result, states the 

commenter, the EPA required annual total particulate testing by Method 5 in lieu of requiring the 

operator to make an opacity monitor perform on the wet plume. The commenter requests the EPA to 

apply the same sound judgment now with respect to frequency of source testing for demonstrating 

continuous compliance with metals emissions and HCl.

Comment 22: Commenter 17316 suggests that performance testing for oil-fired units should be 

conducted every 3 years rather than the schedule proposed in section 63.10006(f),(g),(l) and (m) because 

the proposed schedule is unjustified and a very substantial economic burden for smaller utilities. 

Commenters (17316, 17725, 17760) indicate that the total expenditures for such a test program include 

the direct monthly costs of contracted testing services and the significant costs of operating oil-fired 

units strictly for monthly tests when other more economical generating units are available to meet the 

demand for electricity or requiring dual fired units to burn fuel oil for testing purposes when natural gas 

prices are lower than residual fuel oil. According to commenter 17725, performance testing of a unit 

without metals or acid gas controls requires a minimum of 4 full load hours per month; an additional 2 

hours at full load for boiler stabilization; potential additional runs if the test crew has problems; and time 

for calibrations between test runs. The commenter estimates such a unit would operate for 72 hours per 

year just for testing, not including the time to start-up the unit, ramp the unit to full load and then ramp 

down the unit. Commenter 17725 states that review of published data for 2008, 2009, and 2010 shows at 

least 34 residual oil-fired units whose 3-year annual capacity factors are 5 percent or less.

Comment 23: Several commenters (17316, 17870, 18428) state that oil is a homogeneous and 

reasonably consistent fuel, so that variations in the metals, chlorine, and fluorine contents should not be 

significant and therefore monthly or bimonthly testing is not warranted. Commenter 17870 states that 

fuel analysis on each shipment of oil should be sufficient to demonstrate compliance. Commenter 18428 

states that in the preamble, the EPA states that additional performance tests for Hg are conducted “at 

least annually.” However, there is no reference to this annual testing in the proposed rule. Given the 
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extremely low level of Hg in oil, states the commenter, any requirement or reference to annual testing 

for Hg emissions from oil-fired units is unnecessary and should be removed

Comment 24: Commenter17704 appreciates the proposal’s inclusion of an alternative to the use of PM 

CEMS for monitoring non-Hg metals emissions, but the commenter states that the bi-monthly stack 

testing alternative is not practical because the effected source operator does not have resident stack 

testing crews, and the scheduling of tests with contract testing crews and the scheduling of testing loads 

with the grid reliability control center would be difficult to do every two months. Commenter 17704 

states that the amount of metals in the PRB coal utilized at the effected source does not change 

significantly and annual testing should be sufficient for monitoring the non-Hg metals.

Comment 25: Several commenters (17716, 17725, 17758, 18014) state that the proposed frequency of 

performance testing is not consistent with the expected variability in emissions because units without 

add-on control systems are required to complete stack test less frequently than units with add-on control 

systems, but for units without add-on control systems, the emissions of HCl, HF, and non-Hg metals are 

most closely tied to fuel characteristics. These commenters and commenter 17402 suggest that in lieu of 

the proposed monthly or bi-monthly frequency, periodic fuel analyses should be used to determine if a 

significant change has occurred since the annual performance test. Commenter 17402 provides 

suggested revisions to proposed section 63.10006 and section 63.10021 outlining a methodology for 

using monthly fuel analyses and performance tests conducted every 4 unit operating quarters; the 

suggested methodology includes criteria for using monthly fuel samples to determine when higher 

frequency stack testing is required. Commenters (17716, 17725) cite statements in the preamble to the 

proposal indicating that for liquid oil-fired units, no correlation was found between non-Hg metallic

HAP emissions and PM emissions or the operation of PM control devices. These commenters conclude 

that the emissions of HCl, HF, and non-Hg metals are most closely tied to fuel characteristics and that 

periodic assessment of fuel characteristics should be used to determine whether additional emission 

testing is needed. This commenter also believes that the source’s expected removal efficiency should 

also be taken into consideration to minimize unnecessary testing.

Comment 26: Commenter 17718 encourages the EPA to maximize the efficiency of monitoring and 

reporting requirements and to avoid redundancy. This commenter states that the data gathering 

requirements in the proposal are extremely difficult due to the lack of approved test methods, data 

variability, and short deadlines for testing. The commenter suggests that the EPA should extend the 

testing frequencies to at least a quarterly basis to allow more substantial analysis of gathered data and to 

reduce potential burdens resulting from more frequent laboratory analyses and test report submittals.

Comment 27: Commenter 17737 states that a monthly testing frequency is unmanageable for units that 

do not have SO2 control technology or HCl CEMS, and the commenter states that proposal provide no 

explanation for this unprecedented frequency. According to the commenter all plausible operating 

scenarios that could utilize the compliance option for sources without SO2 controls require use of fuel 

with very low chlorine content. In such cases, states the commenter, fuel analyses provide assurance of 

compliance at a fraction of the cost. This commenter believes the final rule should allow operators to 

maintain records of the type of fuel being burned and to perform monthly fuel analyses to demonstrate 

that the fuel chlorine content is within acceptable limits.

Comment 28: Commenter 17718 is concerned that the monthly or bi-monthly performance testing 

option may be incompatible with timely submission of test reports under proposed section 63.10006(t) 

because historically, testing firms and labs have not handled the high volumes of work implicit in this 

compliance option.
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Comment 29: Commenter 17821 states that the proposed initial testing schedule requiring tests within 

30-operating days of the startup of new controls is too tight. According to the commenter, few 

installation projects will meet their construction deadlines and will force initial testing into very

compressed schedules.

Comment 30: Commenter 17807 states that the proposed testing frequency is not practicable and not 

justified. The commenter suggests annual stack testing and a CAM plan instead of bimonthly testing.

Comment 31: Commenter 17880 supports the requiring of liquid oil-fired units to conduct additional

performance testing for Hg on an annual basis; conduct additional performance tests for HAP metals and 

acid gasses every 2 months for units that have emissions controls, and monthly for units that do not. 

Comment 32: Commenter 17867 notes that several MACTs allow for less frequent testing given 

consecutive passing results as follows:

 40 CFR 63 subpart DDDD (Boiler MACT) section 63.7515 – testing frequency is annual until 

compliance is demonstrated for 3 consecutive years, then frequency is relaxed to every 3 years.

 40 CFR 60 subpart KKKK (Combustion Turbine NSPS) section 60.4340 – testing frequency is 

annual unless emission are less than 75 percent of the standard, then frequency is relaxed to 

every 2 years.

 40 CFR 60 subpart DDDD (CISWI MACT) section 60.2720 – testing frequency is annual unless 

emissions are less than the standard or 75 percent less than the standard (depending on the 

pollutant), then frequency is relaxed to every 3 years.

 40 CFR 60 subpart CCCC (CISWI MACT) section 60.2155 – testing frequency is annual unless 

emissions are less than the standard or 75 percent less than the standard (depending on the 

pollutant), then frequency is relaxed to every 3 years

According to the commenter, metals and HCI stack testing every other month is unnecessarily 

burdensome. Commenter suggests the frequency should be extended to every 6 months if two 

consecutive tests demonstrate compliance with the standard. The commenter states that if two 

consecutive semi-annual tests demonstrate compliance, frequency should be extended to annual testing, 

and frequency should be increased if a subsequent performance test indicates the emission standard is 

not being met or if more than 50 percent of the fuel has been switched to a different type of coal (e.g., 

subbituminous/bituminous, supply from different basin).

Comment 33: Several commenters (17681, 17870, 18034, 18428) question whether, because of the 

prescriptive testing deadlines, if a unit is not operated within the timeframes specified will the unit be 

required to start-up simply for testing purposes.

Response to Comments 17 - 33: See response to Comments 15 and 16.

Comment 34: Commenters (17800, 17886) state the start date of the performance tests under section 

63.10005 should be flexible to allow for monitor certification to be completed, operating conditions to 

be established, and shakedown of control devices to be performed.

Response to Comment 34: The Agency finds that the rule’s start dates of the performance tests are 

flexible and will allow for monitor certification and similar activities to occur.
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General Response to Comments 1 - 34: For stack test frequency, the EPA has modified the final rule 

to require quarterly testing if used to demonstrate continuous compliance and included an exemption for 

testing in quarters with low utilization (<168 operating hours). In addition, EPA agrees that testing 

should be required only for the emission limit that the source is complying with, and thus the final rule 

does not require testing of both the HAP and a separate surrogate standard (such as filterable PM for 

HAP metals).

2. HCl testing section 63.10006(j).

Comment 35: Commenter 17821 requests that the EPA clarify this section of the rule to indicate 

whether sources choosing to use the alternate method of compliance with the HCl limitations defined in 

Table 5 (use of a CEMS to measure SO2 emissions and limiting the emissions rate to less than 0.2 

lb/MMBTU) are required to conduct HCl performance testing every 2 months. With section 

63.10000(c)(1) defining a SO2 CEMS as an alternative to an HCl CEMS, the commenter recommends 

that the EPA should not require sources using this alternative to conduct performance testing for HCl

every 2 months. Rather, the commenter recommends that the frequency of performance testing for HCl, 

when utilizing the alternative method of compliance with a sSO2 monitor and a reduced SO2 emission 

rate, should be the same as for those sources choosing to utilize an HCl CEMS.

Response to Comment 35: The final rule has removed all requirements for duplicative testing of a HAP

and a surrogate standard (such as HCl and SO2). Facilities complying with a surrogate standard do not 

have to perform periodic testing for the corresponding HAP.

Comment 36: Commenter 17696 states that for coal-fired EGUs without an HCl emission control 

device, the key factor in determining maximum potential HCl emissions is the maximum coal chlorine 

input. For coal-fired EGUs with HCl control devices, states the commenter, a second key factor in 

determining maximum potential HCl emissions is the control device’s operating parameters, which 

under the proposed rule also must be continuously monitored to assure compliance, and as long as there 

is no change in coal type or coal mixture (or change in emission control device operations), there is no 

need to perform HCl stack testing every month or every other month - simply keeping the coal chlorine 

input below maximum allowable levels (and, as applicable, keeping the control device’s operating 

parameters within allowed ranges) is sufficient to ensure continuous compliance.

Response to Comment 36: The final rule has removed most of the options for fuel sampling and 

analysis as a compliance option. Sources choosing to not use HCl CEMS for uncontrolled sources must 

perform periodic performance testing. However, if you combust liquid fuels and you wish to 

demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel moisture content 

of each shipment of fuel in place of quarterly stack testing, you may develop a unit-specific approach 

utilizing fuel moisture content measurements, collect data necessary to support your approach, and 

petition the Administrator under 40 CFR section 63.7(f) for an alternative compliance testing approach.

Comment 37: Commenter 17725 requests that the final rule clarify that testing for HCl is not required if 

the site operator has instituted the alternate compliance method of percent water in fuel deliveries.

Response to Comment 37: The final rule has removed most of the options for fuel sampling and 

analysis as a compliance option. However, if you combust liquid fuels and you wish to demonstrate 

ongoing compliance with HCl and HF emissions limits by measuring fuel moisture content of each 

shipment of fuel in place of quarterly stack testing, you may develop a unit-specific approach utilizing 
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fuel moisture content measurements, collect data necessary to support your approach, and petition the 

Administrator under 40 CFR section 63.7(f) for an alternative compliance testing approach.

3. Reduced frequency criteria.

Comment 38: Commenter 17821 states that the reduced stack test provisions at section 63.10006(c) are 

too burdensome. Commenter believes that the threshold for extended testing frequency should be that 

the unit demonstrates 80% - 90% of the standard because the EPA is also requiring worst-case fuel 

conditions, full load, and other requirements intended to provide the absolute worst case test conditions 

for what are relatively short-term periods. In the real operating world, states the commenter, a unit will 

simply not continue to operate in worst-case conditions, rather, the average fuel concentration will be 

less, load will decrease, etc.

Comment 39: Commenter 17821 asserts that the requirement that a source must demonstrate 

compliance for 3 years is far too burdensome. The commenter notes that the EPA states “If a 

performance test shows emissions in excess of 50 percent of the emission limit, you must conduct 

performance tests at the appropriate frequency given in section (c) through (m) of this paragraph for that 

pollutant until all performance tests over a consecutive 3-year period show compliance”; in other words 

for the parameters where the EPA is requiring sources to test every month, or every other month, 

sources will have to conduct 18-36 individual test before they can qualify for reduced frequency. 

According to the commenter, this imposes a burden on the source and the permitting agency and it 

appears the EPA is attempting to ratchet the emission limit down by half.

The commenter recommends that the EPA make two important changes in the frequency of its required 

reference method testing: first, the EPA should require reference method testing that is no more often 

than quarterly for any pollutant and equipment configuration, and second, once a unit has successfully 

demonstrated emission levels that are at no more than 80% to 90% of an applicable standard for 2 

consecutive quarters, the testing frequency be reduced to semi-annually. The commenter states that then 

once a source has demonstrated compliance with the applicable standard for two additional tests, the 

frequency would be further reduced to annually. Finally, states the commenter, the EPA must address 

the issue of how a limit of detection is handled in the context of reduced testing frequency.

Response to Comments 38 - 39: The final rule has been amended to quarterly testing for all pollutant 

and equipment configurations. The EPA disagrees with the 80 to 90% criteria for reduced testing 

suggestion due to the option for use of CEMS instead of periodic testing and the removal of prescriptive 

parameter and fuel monitoring.

Comment 40: Commenters 1775 and 17800 state that the EPA should remove the 50% criterion for 

reduced testing as the EPA provided no reason for this restriction. According to the commenters, the 

EPA has not provided any data suggesting that any source could achieve 50% of the proposed limits 

some of which are at or near the detection limits.

Response to Comment 40: The EPA disagrees with the commenter and will retain the 50%

criteria. The emission standards in the final rule are at least three times the RDL, so any source below a 

typical detection limit would meet these criteria. In addition, the quarterly periodic performance testing 

is an option for sources choosing to not install CEMS or PM CPMS.

Comment 41: Commenters 17881 and 19033 state that section 63.10006(q) is unclear. According to the 

commenters, it seems the intent is to require that the more frequent testing frequencies must be met if a 
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performance test shows emissions greater than 50% of an allowable limit, yet the increased testing 

frequency is required until all performance tests over a consecutive 3-year period show compliance.

Response to Comment 41: The reduced frequency option is only available to sources that meet the 50%

criteria during the 3 years of periodic testing.

Comment 42: Commenter 17881 states that section 63.10006(o) allows for reduced frequency of testing 

from annual or more frequent to once every 3 years (i.e., no more than 37 months) after the previous 

performance test. The commenter states that in order to qualify for this reduced testing frequency, 3 

consecutive years of testing must show that emissions are at or below 50% of the applicable emission 

limit. In light of the very stringent emission limits, the commenter questions why results have to be less 

than 50% of threshold. For comparison, states the commenter, in the Boiler MACT, to qualify for 

reduced frequency, units had to demonstrate emissions at or below 75% of the emission limit. Also, 

states the commenter, it seems disproportional for units that are testing bi-monthly or monthly to have to 

conduct 18-36 tests to establish a pattern of compliance versus units testing annually to conduct as little 

as three discrete tests. According to the commenter, reduced frequency should be based on the number 

of passing consecutive tests; the RICE MACT utilizes this concept in that after compliance is 

demonstrated for two consecutive semi-annual tests, the testing frequency can be reduced to annually. 

The commenter suggests that for non-CEMS units there should be a tiered approach in regards to the 

number of passing tests based upon the original testing frequency; i.e., six passing tests for bi-monthly

tests and 12 passing tests for monthly tests.

Response to Comment 42: In response to comments, the final rule has been amended to reduce the 

frequency of testing from 1 or 2 months to quarterly testing. Also, the quarterly periodic performance 

testing is an option for sources not choosing to install and operate CEMS.

Comment 43: Several commenters (19536, 19537, 19538) asserts that the frequency of testing should 

depend upon the variability of each parameter. According to the commenter, when a parameter is 

variable, more frequent monitoring is required to assure continuous compliance; as a rule, where a 

parameter fluctuates significantly over a period of time shorter than the specified monitoring interval, 

the monitoring cannot assure continuous compliance. According to the commenter the proposed limits 

are heavily premised upon the claim that the regulated emissions are very highly variable and the EPA 

uses this justification in establishing extraordinarily aggressive statistical adjustments. The commenter 

states that the EPA’s calculations predict emissions from existing sources which range from 2 to 56 

times greater than the average data yielded from a test. For new sources, states the commenter, the 

EPA’s calculations predict emissions from 2 to 6 times greater than the average, and according to the 

EPA’s beyond-the-floor analysis (or lack thereof) there are no operational methods available to reduce 

that variability. Given the unavoidable variation, states the commenter, continuous compliance cannot 

be determined using the periodic testing proposed in the rule. According to the commenter, if emissions 

vary by a factor of 2 to 50 (or more), and there is no method available to reduce that variability, direct 

measurement of emissions every month (or every other month) with annual to every 5 year re-tests, will 

not ensure continuous compliance between those tests.

Response to Comment 43: The EPA believes the provisions of the LEE exemption provide adequate a 

level of assurance with compliance. For non Hg HAP, the sources must not show levels above the 

threshold for quarterly performance tests over a 3-year period. In addition, any change to the process 

that would result in an increase in HAP emissions would necessitate another performance test. These 

sources will also be subject to other rules containing provisions for parameter monitoring as discussed in 

5A05.
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Comment 44: Commenter 17718 requests that the final rule include a clarification to the proposed 

language at section 63.10006(o) regarding the criteria for reducing the frequency of performance testing; 

the final rule should clarify what constitutes “no change” and what information would be needed to 

successfully pass these criteria. For example, states the commenter, it is unclear whether the “no 

change” provision applies to the affected unit and is not inclusive of the entire facility.

Response to Comment 44: ”No change” would apply to the affected unit.

4. Comments related to “highest content” of HAP.

Comment 45: Commenters 17731 and 17881 state that the requirement to use worst case coal with the 

“highest content” of HAP in performance testing is not reasonably possible in part due to natural 

variability. According to the commenters, there is a very real possibility that even if the worst case coal 

could be identified, that coal very well may not be available for purchase. The commenters state that the 

proposed rule also fails to distinguish emissions testing requirements among regulated parameters. 

According to the commenters, the worst case coal is not likely to be the same relative to each of the 

regulated parameters under the proposed rules. Thus, according to the commenters, EGUs would have a 

nigh-impossible task of identifying a suite of worst case coals and procuring each of those in order to 

conduct the required testing. Commenter 17881 suggests defining a primary fuel and retesting on 

changes to the primary fuel. According to the commenter this approach was used in the CAMR rule 

under section 75.81(d)(4)(iv). Commenter further notes that even if an EGU is diligent in trying to 

determine the maximum HAP input levels based upon expected fuel(s), it is entirely possible that the 

actual HAP input will increase beyond the levels observed during the initial performance tests/fuel 

sampling and analysis simply due to fuel variability alone (and not a change in fuel type(s) or blends).

Comment 46: Commenter 17718 states that the proposed regulatory language (40 CFR 63.10007(c)) 

provides that performance tests must be conducted “while burning the type of fuel or mixture of fuels 

that has the highest content...” The commenter believes the EPA should clarify whether reference to 

“type of fuel” simply means that if bituminous coal is typically burned then bituminous coal is to be 

used during the test. According to the commenter, this section does not appear to require a determination

that the highest chlorine (or other constituent) content bituminous coal be used during the test. The 

commenter also suggests clarification that “special fuels” are not required or expected for the 

performance test.

Comment 47: Commenter 17781 states that for performance testing under section 63.10007(c) the EPA 

should specify that fluorine content is only relevant for liquid oil-fired EGUs, as no other category of 

EGUs are subject to HF emission limits. 

Comment 48: Commenter 19121 states that placing testing criteria on multiple fuels is burdensome, and 

close to impossible to include all fuel sources and blends within any single performance test. 

Additionally, the commenter utilizes bituminous and subbituminous fuel from multiple sources and fire 

as a blend. Fuel supply can be seasonal and based upon pricing, availability and access.

Response to Comments 45 - 48: Periodic performance test must be conducted using the fuel type or 

blending that would represent the highest HAP loading to the control devices for that period of testing. If 

the source is unsure which fuel would result in the highest HAP loading, they may perform multiple 

tests within that test period or opt to use CEMS to ensure continuous compliance with the standard.

5. Testing deadlines.
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Comment 49: Commenters 17725 and 18498 state that testing deadlines should be established based on 

time of the last test with no concern for the minimum amount of time since the last test. The commenters 

state that there is no value to establishing a minimum amount of time before conducting subsequent 

tests, and if a source completes the test before the applicable deadline, the future test schedule is simply

adjusted based on the completion date of the test.

Response to Comment 49: The final rule will be amended in order to remove the minimum amount 

time since the last test requirement.

6. Comments regarding performance testing and maximum Operating load.

Comment 50: Commenters 17730 and 17886 state that the proposed rule requires that sources conduct 

performance testing under the maximum normal operating load conditions when combustion is most 

efficient and emissions will be at their lowest. The commenters state that for EGUs using CEMS the 

performance test will run for 30 operating days. According to the commenters, it may not be possible for 

sources to maintain a “maximum” normal operating load for a full 30 operating days. The commenters

believe that the EPA should simply require representative operation of the unit during performance 

testing.

Comment 51: Commenter 17316 states that section 63.10007 indicates that performance testing must be 

conducted at “maximum normal operating load”; however this term is not defined. Commenter suggests 

that the rule allow sources to apply the Part 75 Appendix A, section 6.5.2.1 procedure to define three 

operating load ranges for a unit (low, mid, high), and allow a source to perform testing at any load 

within the “high” load range. According to the commenter, such an approach allows a source to test at a 

representative load, but ensures testing is conducted at a high load, and hopefully such an approach 

would reduce the need to perform multiple stack tests, while still basically satisfying the goal of 

conducting measurements under worst case conditions. The commenter notes that the preamble to the 

proposed rule indicates that load has little significant impact on HAP emissions (FR Page 25037).

Comment 52: Commenter 17881 states that specifying that the performance tests be conducted at 

maximum routine operating load is not appropriate, as the EGU should have the flexibility of conducting 

the test at whatever load is desired with the understanding that in those cases where compliance is 

demonstrated through performance testing, the average load observed during the performance tests will 

be used to set a maximum load restriction for all future operation (at 110 percent of the average load 

during the tests).

Comment 53: Commenter 18024 recommends that if compliance can be achieved by co-firing natural 

gas and oil at the same time, then a liquid fuel-only compliance demonstration would not be necessary

or appropriate so long as enforceable co-firing operating restrictions were implemented. Commenter

states that low load operation should be allowed as compliant operation if the mass emission rate of any

HAP is maintained below the equivalent full load HAP emission level calculated as the MACT Floor. 

The commenter requests that the EPA develop a compliance option that represents normal operation of a 

facility and eliminate testing in modes of operation that are rarely or never utilized.

Comment 54: Commenter 18444 states that the EPA should require that states set maximum allowable 

hourly heat inputs for each unit and that testing to determine compliance be conducted at these 

maximum rates. According to the commenter, this heat input limit is especially important for pollutants 

which do not have a continuous monitor and are tested infrequently (such as particulate HAP). The 

commenter notes that the proposed rule language on maintaining heat input within 10 percent of the heat 
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input when compliance testing was done is too much leeway; especially with an ESP. The commenter 

states that emissions can be about 50 percent higher with a 10 percent fuel gas flow rate increase through 

an ESP. According to the commenter, air pollution control systems are designed for a maximum flue gas 

flow rate which is directly related to heat input; ESPs are very sensitive to higher amounts of fuel being 

burned, and scrubbers are also affected as well. The commenter recommends testing within 5 percent of 

the maximum allowable hourly heat input.

Comment 55: Commenter 18023 states that not only do individual units see significant variability in 

steady-state full load stack test results, these measurements are not representative of the variability that a 

unit may experience on a continuous basis through all modes of operation, including startup, shutdown, 

and malfunction, as may be measured by a PM CEMS.

Comment 56: Commenter 17881 states that it may not be possible to meet operating limits set at the 

maximum routine operating load at other reduced loads and therefore the concept of conducting multiple 

sets of performance tests at different operating loads under section 63.10007(c) is unworkable. The 

commenter appreciates the EPA’s attempt at recognizing that it may not be possible to meet operating 

limits set at the maximum routine operating load at other reduced loads. For example, the commenter 

asks the following: if an EGU were to test at 50 percent and 100 percent of rated capacity and establish 

separate sets of operating limits, which set of operating limits would apply at any given time, and would 

the operating limits established at 50 percent load apply to all loads ≤ 50 percent capacity, ≤ 75 percent 

capacity (i.e., the mid-point between to two test conditions) or ≤ 100 percent capacity?

Comment 57: Commenter 17881 suggests that a more realistic approach is to specify that the operating 

limits only apply during those periods when the EGU is operating within a certain percentage of the 

average load condition associated with the performance test. The commenter states that this approach 

would be consistent with that taken by the EPA in 40 CFR 63, subpart ZZZZ – NESHAP for RICE. The 

preceding rule requires that performance testing be conducted at 100±10 percent of rated load (see Table 

1a of subpart ZZZZ), and the operating limits established during testing (i.e., pressure drop for oxidation 

catalysts) only applies when the unit operates at loads of 100±10 percent (see Tables 1b and 2b of 

subpart ZZZZ). Thus, states the commenter, this approach avoids the possibility of applying an 

operating limit established at a specific operating load to loads not evaluated during the concurrent 

performance test.

Comment 58: Commenter 17881 suggests another potential approach would be to use the performance 

test and associated operating parameter values as verification of a parameter value or range based upon 

control equipment vendor recommendations. For example, states the commenter, the vendor 

recommendation for the pressure drop across a wet PM scrubber may be 35” to 40” water column (w.c.); 

thus, the operating limit could be set at a minimum pressure drop of 35” w.c., and the performance test 

could be used to verify that PM emission rates and or non-Hg HAP Metals emission rates at pressure 

drops at or above the vendor recommendation comply with the applicable emission limits. According to 

the commenter, this approach is very similar to the approach taken in 40 CFR Part 75, Appendix E, 

which allows the use of a parametric monitoring approach for NOX emissions. Essentially, states the 

commenter, stack testing is conducted to establish a relationship between NOX lb/MMBtu emission rates 

and unit load; prior to conducting the stack testing, four parameters indicative of NOX emissions, along 

with the vendor recommended values or ranges for these parameters across the expected operating 

range, are identified. During testing, states the commenter, the actual parameter values must be 

consistent with the vendor recommended values or ranges, and the EGU must conduct ongoing 

monitoring of the parameters following emission testing and verify that they remain consistent with the 
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vendor recommend ranges or values. According to the commenter, operating outside the vendor 

recommended ranges or values results in a requirement to conduct additional testing. 

Comment 59: Commenter 17718 states that under section 63.10007(f) the EPA should clarify whether 

it will specify when and how performance testing is to be completed, beyond what is already proposed 

in other sections of the regulatory language. The commenter states that other sections of the proposed 

regulatory language specify when, how and under what conditions the performance testing is to be 

conducted, and therefore, the proposed section 63.10007(f) appears unnecessary and should be 

removed.

Comment 60: Commenter 19121 states that the proposed rule places limits on changing operating 

modes and equipment in configurations different than those configurations used during a performance 

test and that this would require sources to operate in every conceivable configuration during 

performance testing. The commenter states that this could mean that performance testing could literally 

take months to perform. As an example, states the commenter, the commenter enjoys high availability

due to redundancy of systems. For instance, states the commenter, the scrubber for each unit consists of 

six modules; four modules are required for full load, two or three modules for start-up and low loads. 

The commenter states that completing a performance test so that all operating configurations would be 

considered acceptable under the proposed rule would necessitate numerous individual test arrangements, 

and this would also be true for every burner configuration and baghouse compartment-in-service 

rotations. The commenter states that the rule is proposing a performance test every 5 years; taking 6 

months to complete a set of tests to meet the rule would be incredibly arduous and costly.

Response to Comments 50 - 60: We agree with commenters on the need for the regulation to define 

more clearly what constitutes representative process operating load during performance testing. There 

are generally three testing scenarios each with different definitions of representative operating 

conditions. First, if the source uses CEMS (Hg, HCl, or SO2) to determine compliance with the limit that 

applies over a 30-day averaging period, the rule need not specify any minimum process operating 

conditions. Compliance is based on a direct measure of emissions in units of the standard for the entire 

30-day averaging time for all periods the process operates regardless of load conditions.

The second scenario applies to the use of PM CPMS to demonstrate compliance with a PM or non-Hg 

metals emissions limit. This includes continuous compliance with an operating limit based on 

measurements from the PM CPMS rather than an emissions limit. That operating limit is derived from 

data collected during a short term (three test run) performance test for either filterable PM measured 

with Method 5 or non-Hg metals measured with Method 29. For the purposes of establishing a 

representative operating limit, the rule will specify that the unit be operated at maximum normal 

operating load conditions during the performance test period. We understand that actual maximum 

normal operating load for a particular facility is unit dependent but we expect it will be generally

between 90 and 110 percent of design capacity. The rule will require the maximum normal operating 

load condition be maintained during each test run only (e.g., a few hours at a time) allowing for some 

operational flexibility for a performance test period that extends over more than one day.

The third scenario applies if the source owner elects to conduct frequent performance testing in lieu of 

continuous monitoring. In such cases, the rule will specify that the unit be operated at maximum normal 

operating load conditions during each periodic (e.g., quarterly) performance test period. As noted above, 

actual maximum normal operating load for a particular facility is unit dependent but we expect it will be 

generally between 90 and 110 percent of design capacity. Maintaining this high load operating condition 
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need not be continuous during the time it takes to complete all of the performance testing but is required 

only during each test run.

7. SO2 CEMS issues.

a. Comments related to LEE (testing/monitoring).

Comment 61: Commenter 17800 states that in proposed section 63.10021(a)(11)(iv) and (v), the EPA 

proposes to require sources using PM CEMS to report “performance test data, except opacity data” and 

“relative accuracy test audit data” electronically using ERT starting January 1, 2012 (FR Vol.76, No. 85, 

p. 25,117) and section also requires the reporting of “performance test data, except opacity data” and 

“relative accuracy test audit data” for LEEs (FR Vol. 76, No. 85, p. 25,117-18). According to the 

commenter these provisions do not make sense because 1) EGUs using PM CEMS and LEEs do not 

conduct “relative accuracy test audits” (RATAs); 2) PM CEMS are subject to different tests (RCAs and 

RRAs); 3) LEEs comply by initially demonstrating applicability with emission tests and thereafter by

fuel analysis and therefore LEEs have no monitoring systems upon which to conduct RATAs; and 4) 

with respect to “performance test data,” the provisions are duplicative of a more general provision the 

EPA proposes. Commenter states that the EPA needs to reconcile this language so it makes sense

Response to Comment 61: The final rule does not contain the cited text. The recordkeeping and 

reporting provisions in the final rule have been clarified to streamline reporting under this rule.

Comment 62: Commenter 17881 states that section 63.10021(a)(17)(ii) makes no sense because the 

whole point of being a LEE is to avoid stringent monitoring requirements (i.e., CEMS) and therefore if 

not equipped with a CEMS how would one submit a CEMS performance test and RATA.

Response to Comment 62: The EPA agrees and the final rule has been amended to remove section 

63.100021(a)(17)(ii).

Comment 63: Commenter 17767 states that the qualifications for the Hg LEE status are egregiously 

costly because they would require stack testing company to sample for 28-30 days using Method 30(B). 

Moreover, the commenter states that the three 10-day runs wouldn’t be achievable at their stacks due to 

the scrubbed stacks’ high moisture content which can foul the sorbent traps at week-long sampling 

durations. The commenter strongly suggests the EPA revisit this portion of the proposed rule in 

consultation with experienced outside experts.

Response to Comment 63: Under the final rule, all Method 30B tests are to be run on a 30 day basis. 

The maximum run length for a sorbent trap is set at 15 operating days for both Method 30B and a 

sorbent trap monitoring system. As long as the criteria for sampling within the calibration range of 

Method 30B are met, the source may reduce the sampling runs to shorter than 15 days as long as the 

total sample time of all runs is 30 days.

Comment 64: Commenter 17868 states that it is unclear whether the EPA intended the fuel input limit 

on Hg, and additional operating limits on Hg controls and load apply to LEEs. The commenter states 

that they should not. .

Response to Comment 64: The operating and fuel limits have been removed from the final rule.

Comment 65: Commenter 17868 states that LEE status should be available to new units.
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Response to Comment 65: The final rule retains the proposed approach – no LEE for Hg for new units. 

Given the emission rates established for these units, EPA does not believe the LEE option is appropriate. 

Comment 66: Several commenters (17808, 17870, 18025, 18031) support the LEE approach but 

recommend less burdensome continuous compliance methods. Commenters 17870 and 18031 

recommend instead of monthly fuel tests provide an option to conduct annual Method 30B test to 

demonstrate emissions are less than 10% or the applicable limit or less than 22.0 pounds per year. If a 

LEE unit exceeds LEE limits, commenters propose that it revert back to more frequent performance tests 

(e.g., quarterly, as recommended below); the subsequent year, if the unit can, again, demonstrate LEE 

status through reduced utilization or a lower emission rate, it would return to annual stack tests under the 

LEE provisions.

Response to Comment 66: The final rule establishes a process similar to that suggested by this 

commenter. If a unit qualifies as an LEE for Hg, then annual testing is the only ongoing requirement. 

However, if the unit tests at above 10% of the standard, the LEE status is lost and the source must move 

to install, certify, operate and maintain an Hg CEMS or sorbent trap monitoring system. Specific testing 

requirements will apply in the interim prior to the CEMS or sorbent trap monitoring system being 

certified.

Comment 67: Several commenters (17808, 17870, 18025) also recommend allowing sources to 

schedule their annual performance tests at any time during a 12-month cycle. The commenters state that 

some of these LEEs may be smaller units with low capacity factors and may go several months without 

operating, and allowing flexibility in scheduling stack tests will avoid unnecessary air pollution 

emissions and reduce costs for these units operating well below the proposed standards. Additionally, 

state the commenters, this would allow companies to align testing under this rule with existing state 

testing requirements.

Response to Comment 67: The rule specifies a maximum interval between tests based on the cycle of 

testing required, but does not specify a minimum. Of course, if tests are conducted close together, the 

next scheduled test would be accelerated so that the maximum time between tests is not exceeded.

Comment 68: Commenter 17870 recommends that fuel testing be maintained as an alternate monitoring 

method for LEE units; it is suggested that the frequency of fuel testing be reduced to each shipment of 

oil received. According to the commenter, Hg concentration differences should be negligible in 

comparison of Method 3013 and fuel analyses for oil-fired units.

Response to Comment 68: The operating and fuel limits have been removed from the final rule.

Comment 69: Commenters 17808 and 17870 state that for non-Hg HAP, LEEs have the option of 

conducting an annual performance test to demonstrate that emissions are less than 50 percent of the 

relevant emissions standard.

Comment 70: Commenter 18025 states that the rule should clarify the requirements for oil-fired and 

coal-fired LEEs. The commenter believes this will help reveal where gaps may be occurring.

Response to Comments 69 - 70: The final rule eliminates the fuel sampling requirements. For LEEs, 

the rule requires annual Method 30B testing for Hg if the initial Method 30B test qualifies the unit as an 

LEE for Hg. To qualify as an LEE for a non-Hg pollutant, the rule requires 3 years of performance tests 

with each completed test below 50% of the emission standard for the applicable pollutant. If that occurs, 
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the source can switch to testing once per year for that pollutant but must revert to quarterly testing or 

other monitoring options if a performance test exceeds that 50 percent threshold.

Comment 71: Commenters 17808 and 179227 request clarification that LEE status is available to all 

subcategories and all HAP, not just Hg from coal units. According to the commenters, the discussion of 

LEE status in section 63.10005 and in the preamble of the rule suggest that the EPA intends the LEE 

provisions to apply to all subcategories, but monitoring requirements for other HAP and fuels are not 

specified in Table 5.

Response to Comment 71: The EPA will clarify that the LEE status is available to all subcategories 

and HAP.

Comment 72: Commenter 17927 asks whether if a source is determined to be a LEE and maintains its 

status as a LEE in accordance with the requirements of the rule, the source will be required to install a 

CMS if it does not have CMS for the applicable pollutants (e.g., PM, HCl, Hg).

Response to Comment 72: For Hg, the answer is no, assuming the source maintains its LEE status. For 

PM and HCl, a CPMS or CEMS is not required under any condition. It is an option, but a source can 

instead opt for quarterly testing.

8. LEE Applicability Threshold

Comment 73: Commenter 17785 recommends that for LEEs the EPA set fuel concentration standards 

for Hg that are, based on the demonstrated Hg control efficiency in compliance test, equivalent to 22 

lb/year of Hg emissions. According to the commenter, it does not seem appropriate to apply the fuel 

sampling criteria for determination of compliance of LEE units, if these fuel limits would represent 

emission lower than the LEE Hg threshold of 22 lb/year. The commenter believes their waste coal plants 

are expected to continue to emit less than 5 lb/year, so it is likely that the imposition of a fuel Hg limit 

based on average Hg or 90th percentile Hg would set an effective Hg emission limit that is likely less 

than 10 lb/year. According to the commenter, this is an unnecessarily strict emission limit and may 

cause a unit to lose its LEE status simply as a result of fluctuation of Hg in fuel.

Response to Comment 73: The final rule has removed the requirements for operational limits and fuel 

sampling and analysis for LEE units. Compliance with LEE status will be achieved through annual 

performance tests.

Comment 74: Commenter 17620 agrees that units that have demonstrated an ability to consistently limit 

emissions substantially below applicable limits should be eligible for reduced monitoring. However, the 

commenter recommends that the thresholds for reduced testing be based on a demonstrated record of 

performance over several years, be accompanied by parametric monitoring and/or compliance assurance 

monitoring and be set at more protective levels. The commenter states that the EPA has proposed to 

allow reduced testing for sources based on the results of a single test and has proposed to allow reduced 

testing where the source’s emissions are as high as 70% of the applicable limit, and the EPA’s proposal 

would allow a unit to qualify for reduced testing for Hg if the source’s emissions were either less than 

25% of the applicable limit or less than 22 lb/year. In contrast, states the commenter, in calculating the 

Hg MACT floor, the EPA asserts that even the best performing units can reasonably expect year-overyear stack test results to vary by a factor of 50 because of statistical variability, operational variability, 

measuring system variability and variability in fuel. The commenter states it is convinced that year-over-
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year compliance testing of well-performing units will demonstrate the variability that the EPA asserts in 

its MACT floor proposals but suggests that the EPA be consistent in its treatment of these issues.

Response to Comment 74: The LEE provisions demonstrate the Agency’s desire to provide incentives 

for owners or operators to provide additional emissions reductions. The provisions offer easy entry, as 

the initial performance testing results can be the basis for qualifying, but strenuous maintenance 

requirements, for the results of every test conducted for any reason must meet the qualifying 

requirements. Should those requirements not be met by just one subsequent test, LEE status is lost and 

the source owner must provide qualifying data from three years of results before becoming eligible for 

LEE status. LEE status for Hg is achieved through a 30-day performance test repeated annually, that 

documents emissions are less than 10% of the standard or less than 29 lb/year. If results from a single 

test are above that threshold, the source will have to use Hg CEMS or a sorbent trap monitoring system. 

For non-Hg LEE status, the source must demonstrate that test results are below 50% of the emission 

limit. As mentioned before, should test results from an EGU show emissions above the LEE threshold 

for any reason – including variability – LEE status is lost

Comment 75: Commenter 17873 asserts that the LEE standard for Hg (10% of the MACT standard) is 

low and impractical. According to the commenter, the proposed limit of 0.12 lb/MMBtu is near or below 

the in-stack method detection limit, and it will be very difficult to confidently prove compliance under 

any testing regimen. The commenter states that the LEE standards for other HAP are 50% of the MACT

standard. Commenter states that while it understands the heightened focus on Hg, the EPA has not 

sufficiently demonstrated the need for a LEE standard threshold less than that for other HAP, and 

therefore propose a consistent LEE Hg standard of 50% of the Hg MACT standard (or 0.06 lb/TBtu).

Response to Comment 75: The EPA disagrees with the commenter. Method 30B has been shown to be 

capable of measuring Hg catches down to 1 ng within QA/QC criteria of the method. With increased 

time as allowed in LEE testing, Method 30B is technically capable of demonstrating emissions at the 

LEE threshold. In addition, the mass alternative provides another option for demonstrating LEE status. 

Comment 76: Commenter 17767 states that the 22 lb/yr Hg threshold for LEEs was set using fifth 

percentile of the 1,091 operating units (5% of the total mass being determined as a “reasonable cut 

point” during the CAMR development process). Commenter presumes that, in light of the Hg 

calculation errors discovered in the proposed rule’s foundational data since its publication in the Federal 

Register, the agency will revisit the lb/yr cut-off calculation at the reasonable fifth percentile level.

Response to Comment 76: The agency disagrees with the comment, for the Hg LEE threshold was 

determined independently from the proposed rule’s Hg limit. The rule contains no change to the Hg LEE 

threshold. 

Comment 77: Several commenters (17754, 17812, 17838, 18963) state that LEEs with Hg emissions 

below 50% of either of the proposed LEE thresholds should be provided an option to demonstrate 

continuous compliance through annual stack testing, and should not be required to conduct monthly fuel 

analyses so long as the fuel supplier does not change. According to the commenters, annual testing could 

consist of three 120-minute test runs performed using EPA Method 30B. Sources emitting at very low 

Hg emission rates are highly unlikely to show emissions that would exceed the LEE threshold. 

Response to Comment 77: The final rule has been amended to remove the fuel sampling and analysis 

requirement of the LEE option. In lieu of fuel sampling, annual LEE performance testing will be 

required.
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Comment 78: Several commenters (17754, 17838, 18963) state that an alternative to LEE compliance is 

to use a fuel-factor based approach. According to the commenters, the EPA could revise the specific 

fuel-factor based approach currently required under the proposed rule. The commenters believes that the 

requirement to use the 90th percentile confidence level to determine the operating limit for Hg is 

improper, because the use of such value could cause a LEE to lose its LEE status, even though the unit’s 

actual Hg emissions remain substantially below the LEE thresholds. The commenters recommend a four 

step approach:

Step 1: Conduct an initial performance test (and every 5 years thereafter) to demonstrate the unit’s LEE 

status and during the performance test determine and record the average control efficiency achieved over 

the three test runs. The initial performance test (for demonstrating LEE status) would be conducted over 

a 28-30 day period; subsequent performance testing, on a 5 year cycle, should consist of three 120-

minute test runs, performed using Method 30B.

Step 2: Determine the Hg content in the fuel on a monthly basis.

Step 3: Calculate the average Hg content in the fuel on a quarterly basis (i.e., by averaging the Hg 

content levels measured during the 3 months comprising the quarter).

Step 4: Apply the control efficiency determined during the stack test to the quarterly average Hg fuel 

content. If the projected annual emission rate (calculated by multiplying the control efficiency

determined during the performance test by the Hg fuel content) is less than or equal to 50 percent of the 

22 lb/yr LEE threshold (i.e., 11 lb/yr), then the owner/operator remains subject to this process for 

demonstrating that the facility continues to qualify as a LEE. However, if the calculated fuel factor value 

is greater than 11 lb/yr, then the owner/operator shall conduct a stack test to demonstrate that the unit’s 

Hg emissions are in fact below the 11 lb/yr level. If the unit’s actual Hg emissions determined from such 

stack testing remain less than or equal to 11 lb/yr, then the owner/operator remains subject to this 

process for demonstrating that the facility continues to qualify as a LEE. If the unit’s actual Hg 

emissions are greater than 11 lb/yr, but less than 22 lb/yr, then the owner/operator shall thereafter 

comply with the continuous compliance demonstration requirements for LEEs with emissions below the 

22 lb/yr threshold for Hg (i.e., such unit would no longer qualify as a “very low emitting EGU”). To the 

extent that a facility thereafter demonstrates through performance testing that its projected annual Hg 

emissions are less than 50 percent of the LEE threshold of 22 lb/yr, then the facility could return to very 

low emitting EGU status, and demonstrate continuous compliance in accordance with the foregoing 

methodology. In other words, simply because a single stack testing result suggests that the facility’s 

annualized Hg emissions could exceed 11 lb/yr, the facility should not be perpetually precluded from reestablishing very low emitting status.

Response to Comment 78: The final rule has been amended to remove the fuel sampling and analysis 

requirement of the LEE option. In lieu of fuel sampling, annual LEE performance testing will be 

required.

Comment 79: Commenter 17927 questions whether an EGU that fires coal or solid-oil derived fuel that 

has not determined if it qualifies for LEE EGU status per the proposed rule have the option of any of the 

testing options listed in Table 5 (performance testing, Hg CEMs, sorbent trap monitoring system, or 28-

30 day LEE testing) for the initial performance test.

Response to Comment 79: Initial compliance for coal or solid-oil derived fuel may only use the Hg 

CEMS, sorbent trap monitoring system or LEE testing options.
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Comment 80: Commenter 17927 requests that the EPA clarify whether an existing coal or solid-oil 

derived fuel-fired unit the performs a 1-day performance test per Table 5 after the final rule is published 

and within the 3-year compliance deadline for affected units have the option of complying with the LEE 

requirements.

Response to Comment 80: LEE requirements for Hg must be met with a 30 day Hg performance test. 

For other pollutants, LEE status requires a series of periodic tests that show emissions are routinely 

below 50% of the standard for the applicable pollutant.

Comment 81: Commenters 17627 and 17718 believe that the EPA should reconsider the frequency and 

types of monitoring that are appropriate for various subcategories and provide an exemption for low 

capacity factor and LEE units.

Response to Comment 81: The EPA has reconsidered and amended the final rule to alter the frequency

and monitoring requirements for low capacity and LEE units.

Comment 82: Commenter 17781 states that while it is not unreasonable to set a qualification level, the 

EPA has provided no rationale for setting different thresholds for Hg (10%) and all other HAP emission 

limits (50%).

Response to Comment 82: As an incentive to obtain additional emissions reductions, the rule contains 

provisions that reward EGU owners or operators whose emissions reductions surpass the emissions 

limits. The agency maintains that it is reasonable to establish differing eligibility thresholds for different 

pollutants because different pollutants cause differing amounts of damage, harm, or other negative 

impacts. As mentioned elsewhere in this document and rule preamble, mercury is a powerful neurotoxin 

that persists in the environment indefinitely and its emissions warrant special attention.

Comment 83: Several commenters (17781, 17838, 17902) state LEE units that operating outside the 

operating limits established during the most recent performance test should disqualify the unit from LEE 

status. See section 63.10006. The commenters recommend that operating outside the operating limits 

established during the most recent performance test should trigger a requirement to conduct a timely 

LEE qualification re-test based upon an expanded operating limit (consistent with the original operating 

limit excursion). Commenter 17781 states that if the results of the LEE qualification re-test indicate that 

the unit continues to qualify for LEE status (i.e., meets section 63.10005(k)(1) and (2)), then the EGU

should maintain its LEE status; if the testing does not show that the EGU continues to meet LEE status, 

then the EGU should be subjected to enhanced monitoring (i.e., be required to meet the provisions of 

section 63.10006(c)(1) and (2)). 

Response to Comment 83: The final LEE provisions and other final monitoring requirements do not 

provide for this suggestion. The only parameter monitoring that applies is a PM CPMS, and the 

expectation if that I used is that a source is unlikely to opt for LEE status after the CPMS is installed.

Comment 84: Commenter 18014 states that the fuel sampling requirements for LEE units are 

ambiguous and provide no compliance value since the rule does not require the establishment of a fuel 

input operating limit. According to the commenter, the requirements do not address single-fuel units, 

changes in fuel type, or units that burn or co-fire multiple fuels, and presumably, LEE units would 

follow an analogous procedure to non-LEE units and reassess the ability to meet LEE status based on 

the new fuel type/blend. According to the commenter, this would require sources that burn multiple fuel 

types or blends to establish a fuel-input operating limit during the initial compliance demonstration. The 
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commenter recommends that consistent with the non-LEE requirements, the EPA should remove the 

arbitrary monthly sampling requirement and allow sources to conduct fuel sampling only when there is a 

change in the fuel type and that for single-fuel units, the EPA should specify that these units are not 

required to comply with any of the fuel sampling requirements.

Response to Comment 84: The final rule has been amended to remove the fuel sampling and analysis 

requirement of the LEE option. In lieu of fuel sampling, annual LEE performance testing will be 

required.

Comment 85: Several commenters (19536, 19537, 19538) state that the EPA should discard the 

proposed “Low Emitting Units” monitoring protocols. According to the commenter, because the EPA’s 

standards are based upon a 99% UPL a majority of plants should be able to generate test data sufficient 

to claim such “low emitting” status. The commenter states that as summarized in Table X-1, the EPA’s 

proposed MACT standards exceed the tested emissions of the plants for which the EPA has data by the 

ratio greater than 2 for all non-Hg HAP (i.e., the tested emissions are below 50% of the standard), and 

greater than 10 for Hg (i.e., tested emissions are less than 10% of the standard). As a result, states the 

commenter, almost all existing and new units will likely be able to exempt themselves as LEEs; in 

combination, the EPA’s variability adjustments and LEE exemption allow most units to avoid any

significant monitoring of emissions.

Comment 86: Commenter 18487 urges the agency to either discard its “Low Emitting EGU”

provisions, or to substantially revise them; if the emissions variability asserted by the agency exists, the 

threshold conditions required for qualification as a “low emitting” unit provide no significant assurance 

that emissions will remain below the proposed standards.

Response to Comments 85 - 86: The agency disagrees with the comment to discard the incentive for an 

EGU owner or operator to seek LEE status. While emissions data collected as a result of the ICR and 

adjusted using the UPL calculation shows an EGU’s potential variability, well-operated EGUs – such as 

those qualifying for LEE status - are expected to have much less variable emissions. The Agency

believes that the requirement to revert to the original monitoring frequency should subsequent emissions 

testing show the EGUs no longer meet LEE status will keep source owners or operators interested in 

maintaining LEE status. 

Comment 87: Commenter 17402 supports the LEE alternative compliance with some modifications. 

The commenter recommends that any facility that either significantly over-complies with the emissions 

standards, or is overall a low emitter by mass in the case of Hg, should be afforded significant leeway in 

terms of performance testing and fuel analysis. Most of the commenter’s Illinois facilities installed ACI

controls in years 2008 and 2009, and have reduced Hg emissions below 22 lb/yr. The commenter states 

that such plants conduct semiannual performance stack tests utilizing Method 30B for compliance, and 

use sorbent traps for tracking ACI effectiveness. According to the commenter, the rule should be clear 

that low emitters can use Hg monitors to track performance, rather than for compliance. The commenter

notes that this approach is consistent with the EPA’s long history of exempting low-emitting sources 

from monitoring or allowing those sources to use less rigorous and lower cost monitoring technology, 

rather than requiring continuous monitoring. The commenter states that the EPA first used a de minimis

exemption to exempt certain units from Acid Rain CEMS monitoring regulations in 1993 and that 

similarly, in 1998 the EPA included low emitter provisions with inventory-based “cutoff points” for SO2

and NOX emissions.
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Response to Comment 87: The Agency believes the rule provides owners or operators of LEEs with 

significant leeway concerning maintaining LEE status, given that Hg emissions testing need only occur 

annually and non-Hg emissions testing need only occur once every 3 years. With that incentive for 

reduced testing frequency comes the responsibility for ensuring units continue to meet LEE status. 

While the agency expects owners or operators will want to ensure proper operation by monitoring 

control device effectiveness, along with other relevant items, the agency also expects adherence to LEE 

status requirements, meaning that should measured emissions exceed the LEE threshold, LEE status 

would become revoked.

Comment 88: Commenter 17902 recommends that the EPA should clarify that for LEE qualifiers it 

exempts units from a CEMS requirement as well as bi-monthly performance testing. Also it should not 

require monthly fuel analysis- this should only be required when there is a fuel switch or allow for 

obtaining the data from the fuel supplier. For example, states the commenter, a unit could qualify for 

LEE for non-Hg metals by being less than 50% of the total PM limit (even if HCl or Hg emissions are 

not LEE status). According to the commenter, this unit would not be required to install a PM CEMS and 

would require fuel analysis only when there is a fuel change plus repeat the performance test every 5-

years.

Response to Comment 88: LEE status is unique to each regulated HAP. A source may achieve LEE 

status for one HAP while not for another.

9. LEE fuel sampling issues.

Comment 89: Commenters 17767 and 17807 express concern over the fuel sampling and the potential 

for variability. Commenter 17767 states that there is no discussion of allowable tolerances to the Hg, 

chlorine, and HAP Metal content limits set for ongoing qualification for LEE status. The commenter 

states that it is unreasonable to assume that, given the natural variability within even the same coal seam 

as well as the error of the analysis methods, the constituents will be consistently below the 

concentrations observed during the performance testing; this would make the LEE methodology

undependable and functionally unworkable. Commenter 17807 states that a single date point is not 

sufficient to demonstrate emissions in excess of the LEE. Commenter notes that in order to provide 

assurance that the fuel profile is meeting the limits set during the initial compliance test, coal would 

need to be stored for some period of time prior to burning. According to the commenter, it would be 

impractical and environmentally imprudent to store coal for extended periods of time just to wait for 

laboratory analytical results.

Comment 90: Commenter 17928 states that under the LEE an oil analysis required to comply with the 

input-based standards requires very low detection limits not typically available in national labs. 

According to the commenter, there are a limited number of laboratories that do these tests to the limits 

of detection needed; these analyses are too costly to have performed on the regular basis proposed in the 

rule; and the oil-fired units typically have low capacity factors, another factor that argues against regular 

oil testing.

Comment 91: Commenter 17800 states to qualify for LEE status for Hg emissions the test Method 30B

is a vapor phase only test method and does not account for any particle bound Hg emissions. The 

commenter recommends that an initial performance test for Hg emissions include an accounting of any

particle bound Hg; an option would be to demonstrate that total Hg emissions is less than 10% of the Hg 

emission limit or less than 22 lb/yr using a test method that measures total Hg. The commenter states 

that if the particulate bound Hg is 5% or less than the total, subsequent testing could measure only the 
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vapor phase Hg emissions; if EPA Reference Method 29 or ASTM Method D6784-02 (2008) is used to 

determine total Hg emissions, only three 1-hour test runs would be required.

Comment 92: Commenter 17805 does not believe it is necessary to sample larger volumes during stack 

testing to comply with LEE status. The commenter states that current stack test methods should be 

sufficient for determining compliance with LEE status and a unit is still required to conduct monthly

fuel sampling per section 63.1 0006(c) that would serve to demonstrate coal variability. Commenter

believes it is burdensome to require parametric limits to be applied to LEE units as well, since existing 

controls for other pollutants, such as SO2 in consideration of a potential HCl LEE unit, would be 

adjusted as appropriate for the pollutant emissions that are monitored by the CEMS. According to the 

commenter, this would serve to keep HAP emissions consistent, and again, fuel analysis is conducted 

monthly for LEE units to evaluate potential increases in constituents that might result in higher 

emissions.

Comment 93: Commenter 18539 is concerned that the proposed rule does not adequately address the 

operating characteristics of fuel-flexible units. According to the commenter, the nature of monitoring

requirements, both initial and every 5 years, in addition to parametric monitoring, will hinder many sites 

from using multiple fuel sources and types where there was not a restriction before this rule. The 

commenter states that this aspect will not only diminish the operational and financial flexibility of the 

facility, but it has the potential to virtually prohibit large segments of fuel suppliers that have elevated 

metals and other HAPS, and all the while there may not be any economical substitute for the unusable 

fuel, thus causing extreme localized economic and employment losses.

Response to Comments 89 - 93: The final rule has removed the requirements for operational limits and 

fuel sampling and analysis for LEE units. Compliance with LEE status will be achieved through 

performance tests. Increased sampling volumes may not be necessary, but must be sufficient during LEE 

testing such that the in stack detection limit is less than the LEE threshold.

10. Belt sampling.

Comment 94: Commenters 17730 and 17775 state that section 63.10008 includes very specific 

requirements for collecting composite fuel samples. The commenters state that for belt sampling, the 

rule requires that the belt be stopped. Commenters believe that this requirement is unreasonable because 

it would not allow for the use of continuous belt samplers; many belts cannot be restarted with coal on 

them because the belt is too heavy for the motor to start. The commenters state that for sampling piles or 

trucks, the rule requires (among other things) use of a “square shovel,” collection of samples at a depth 

of exactly “18 inches,” collection at five locations “uniformly spaced over the surface of the pile,” and 

breaking of pieces larger than exactly 3 inches (proposed in section 63.10008(c)(2)(ii) and (d)). The 

commenters note that they do not object to the intent behind these proposed requirements, representative 

samples can be taken with shovels of other shapes, at depths greater or less than 18 inches, and without 

measuring the actual size of individual coal pieces. The commenters believe these requirements are 

excessively prescriptive and that the EPA should remove the prohibition on moving belt samplers, and 

re-examine and moderate the pile sampling requirements to provide more realistic criteria (e.g., use the 

same shovel for all samples, collect samples at a uniform depth of approximately 18 inches, and break 

apart large pieces (e.g., pieces greater than 3 inches).

Response to Comment 94: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.
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11. Sorbent trap.

Comment 95: Commenter 17870 supports the use of sorbent traps for units not equipped with CEMS.

Response to Comment 95: The EPA thanks commenter for its comment.

Comment 96: Several commenters (17696, 17775, 17868, 17800) state that the EPA should provide an 

explanation for the difference in the days the sorbent trap is used. According to the commenters the rule 

provides 14 days for non-LEE units and 10 days for LEE units.

Response to Comment 96: The final rule will be amended to allow 15 days for LEE unit performance 

tests.

Comment 97: Commenter 17696 does not believe that there should be any limit on the number of days 

that sorbent traps may be used to sample Hg. The commenter has periodically used sorbent traps over 

the past 2 years at five facilities in preparation for continuous Hg emissions monitoring requirements 

that will become effective next year under the Illinois Mercury Rule, 35 Ill. Admin. Code part 225, 

subpart B. In the commenter’s experience, while sorbent traps are routinely changed out within 14 

operating days, there is no reason to invalidate a pair of sorbent traps simply based on the duration of 

their use in the event unforeseen circumstances prevent removal of the traps on schedule. The 

commenter states that notably, the Illinois Mercury Rule does not restrict the number of days a sorbent

trap may be used. (See 35 Ill. Admin. Code Part 225, Subpart B, App. B, Continuous Emission 

Monitoring Systems for Mercury, Exhibit D, Quality Assurance and Operating Procedures for Sorbent 

Trap Monitoring Systems.) Commenter states that such a prescription on the duration a trap may be used 

is unnecessary because the length of time a trap may sample varies from stack to stack based on SO3

concentrations and other miscellaneous factors.

Comment 98: Commenter 17696 states that the determinative factor for the validity of sorbent traps 

should be the QA/QC criteria already in place for the sorbent trap monitoring method, and not the 

duration of use. If a trap samples for too long, states the commenter, it will either fail the breakthrough 

or spike performance criteria (see proposed App. A, 1.5.2.1 (requiring compliance with 40 CFR Part 60

PS 12B QA/QC criteria, which includes spike recovery and vapor phase breakthrough specifications)). 

According to the commenter, those QA/QC criteria are, by themselves, a powerful incentive not to 

sample for too long. However, states the commenter, if an EGU is forced to use a sorbent trap to sample 

for a longer duration than expected because of, for example, bad weather or mechanical problems with 

the stack elevator, the EGU should still be able to use the trap data if the QA/QC criteria are met; the 

duration of use does not itself adversely affect the performance of the trap or the validity of the 

monitoring result. However, states the commenter, if the EPA does not eliminate the proposed duration 

limit on use of sorbent traps, the EPA should revise section 63.1 0005(k)(3) to allow use of sorbent traps 

for up to 14 operating days consistent with Appendix A, 5.2.1.

Response to Comments 97 - 98: The final rule has been amended to allow 14 days for Hg LEE 

testing. Issues extending the sample time by a day such as bad weather or mechanical issues can be 

handled on a case-by-case basis through a minor alternative monitoring requests.

Comment 99: Commenter 17927 requests clarification as to whether an existing coal or solid oilderived unit that is found not to be an LEE is required to install a sorbent trap monitoring system to 

demonstrate continued compliance.
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Response to Comment 99: The source would be required to install sorbent trap monitoring system or 

Hg CEMS.

12. Oil-Fired testing.

Comment 100: Commenter 17818 states that they agree with the EPA’s proposed requirement for units 

firing residual liquid oil fuels. However, the commenter believes that the testing requirements are 

excessive for units that utilize distillate liquid oil fuel, and that fire no residual fuel oil; after the initial 

performance test such units should be eligible for compliance through fuel testing and monitoring

requirements similar to that proposed by the EPA for “limited-use liquid oil combustion units.” The 

commenter states that that there are relatively few variables in distillate oil combustion practices for a 

given unit design and that there is relative consistency in distillate fuel oil quality and chemical 

composition such that there would be little variability in the emission of HAP metals, HCl, or HF.

Comment 101: Commenters 17716 and 18498 state with respect to the EPA solicitation of comment on 

“a limited-use subcategory to account for liquid oil-fired units that only operate a limited amount of time 

per year on oil and are inoperative the remainder of the year” (76 FR 25027/3) that limited operation 

may preclude the ability to conduct stack testing. According to the commenters, limited operation that 

precludes the ability to conduct stack testing is not a phenomenon limited to only liquid oil-fired units; 

timelines for completing subsequent performance tests for all units should be adjusted to account for the 

operating status of the unit.

Comment 102: Commenter 18444 states that new and existing EGUs using distillate oil, especially

ultra-low sulfur oil, which is almost as clean as natural gas, do not need a particulate emission limit or 

testing to demonstrate compliance. According to the commenter, periodic opacity testing is not needed 

either; a no visible emission standard is achievable and reasonable for ultra-low sulfur distillate oil.

Response to Comments 100 - 102: The final rule has been amended to reduce all liquid oil-fired EGU 

performance testing to quarterly and to subject limited use (annual capacity factor less than 5 percent) 

sources to work practice standards in lieu of numeric emission limits. In addition, the fuel sampling and 

analysis requirements have been removed. The only fuel-related provision is an option for liquid oilfired units to demonstrate compliance with the acid gas standards by documenting that fuel moisture 

content remains no greater than 1.0 percent. This demonstration is based on monitoring results or fuel 

supplier certifications.

13. Measurement issues.

Comment 103: Commenters 17724 and 17729 state that for new units the limits are so low that 

adequate test methodologies to demonstrate compliance do not exist. According to the commenters, 

without accurate testing methodologies, contractors will not guarantee that potential emission control 

technologies will meet the proposed standards; without accurate test methodologies and vendor 

guarantees, financing of new facilities will be virtually impossible to secure; and this will effectively

preclude the construction of any new coal-based units. Commenter 17729 notes that this will affect the 

balance of fuel diversity in the energy supply.

Response to Comment 103: The final rule new source emission limits have been adjusted to three times 

the RDL to ensure the required test methods can demonstrate compliance.
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Comment 104: Commenter 17716 states that in section 63.7520(d) the EPA specifies a minimum 

sampling time of four hours for each test method, following the procedures used to establish the MACT 

floor data. Commenter asserts that 4 hours seems excessive for certain pollutants. According to the 

commenter, the required sampling times should be reevaluated and/or alternative minimum sample 

volumes should be provided for each method, taking into account representative analytical detection 

limits and emissions standards that are fully adjusted for non-detect values.

Response to Comment 104: The EPA has reviewed the final emission limits, sample volumes and RDL

to ensure that a realistic sample volume and duration is provided. Sources may also request alternative 

sample volumes as outlined in 40 CFR 63.7.

Comment 105: Commenter 17718 states that the EPA should clarify the specific testing (initial and 

subsequent) and monitoring requirements for a unit with bypass capability. Specifically, states the 

commenter, the EPA should clarify whether initial testing of the bypass emissions need to be tested 

within the 180-day timeframe described in the proposed language. Alternatively, states the commenter, 

setting a firm testing timeframe on bypass stack emissions seems overly burdensome. According to the 

commenter, creating emissions (and incurring costs) by switching a unit into bypass mode that would 

not otherwise have been used simply in order to perform emission testing appears to create unnecessary

burden.

Response to Comment 105: Due to the potential for technical issues with the use of CEMS or a PM 

CPMS on the bypass stack, the final rule provides the option to either install and operate a CEMS or PM 

CPMS in the same manner as a main stack, or to treat hours in which the bypass stack is used as monitor 

downtime.

14. Fuel sampling issues.

Comment 106: Commenter 17716 suggests that the fuel sampling, analysis and calculations proposed in 

section 63.10021 could be applied for uncontrolled units and believes that for controlled units, annual 

testing is sufficient to demonstrate proper operation of control devices. Commenter 17716 believes the 

provisions for fuel sampling, analysis, and calculation of expected emission rates proposed in section 

63.10021 should apply to liquid oil-fired sources.

Comment 107: Commenter17402 states the EPA should allow compliance through annual performance 

testing rather than bimonthly or monthly, when combined with monthly fuel sampling for facilities that 

use a single fuel type. According to the commenter, data in the docket indicate that over the long term, 

facility compliance is fairly consistent despite the potential for variability in fuels and operations to 

affect emissions levels. The commenter states that the EPA should allow facilities to comply with the 

performance testing requirements on an annual basis by coupling the less frequent stack testing with 

more frequent fuel sampling.

Comment 108: Commenter 17402 states that the EPA should clarify when fuel sampling requirements 

apply. For example, states the commenter, fuel sampling should not be required for units that employ

CEMS. According to the commenter, for units that only burn one type of fuel, sampling should only be 

required monthly if being used as part of a continuous compliance program, as the variability impact is 

limited. Most importantly, states the commenter, the EPA should not penalize units that burn low 

contaminant fuel by setting their fuel limits based on their average fuel content during the performance 

tests. According to the commenter, instead, the EPA should set the fuel limit based on HAP reduction 
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performance of the unit, and set the fuel contaminant level at one that guarantees compliance with the 

fuel limit taking into account the standard variability of HAP in that source’s fuel.

Comment 109: Commenter 17730 states that the EPA should moderate the alternative procedures in 

proposed section 63.10008. The commenter states that all fuel analysis under the rule must be conducted 

according to an approved site-specific plan and according to specific procedures for sampling, 

preparation, and analysis. According to the commenter, the EPA’s proposed requirements are in many

instances overly prescriptive; the primary objective should be to obtain fuel samples that are 

representative of the fuel that is being combusted. According to the commenter, because there is so 

much diversity in how fuel is received, stored, and processed at individual facilities, as well as what is 

actually contained in the mine, the EPA needs to allow more flexible procedures to accomplish the 

primary objective. The commenter states that under proposed section 63.10008(b)(l), the proposed plan 

must be submitted to the Administrator at least 60 days before the fuel analysis. Because some of the 

information required to be included may change from analysis to analysis the commenter assumes the 

EPA will require a new plan. For example, states the commenter, the plan must include identification of 

all fuel types anticipated to be combusted and whether the source or fuel supplier will conduct the 

analysis (proposed in section 63.10008(b)(2). The commenter states that although it might be possible to 

submit that information 60 days in advance of the initial demonstration and receive approval before 

conducting the analysis, it may not be possible for subsequent analysis in response to changes in fuel 

type or fuel mixtures (since those might occur with less notice or planning). According to the 

commenter, the requirement to submit a new or revised plan also makes little sense if monthly analysis 

is required. The commenter believes that the EPA should either remove the requirement for advance 

submittal and approval of a plan after the initial compliance demonstration, or remove the requirement 

to include in the plan information that might change.

Response to Comments 106 - 109: The final rule has removed the requirements for operating and fuel 

limits with the exception of a PM CPMS. Compliance with emission limits will be shown with periodic 

(quarterly) performance testing, CEMS, or a combination of annual emission testing and PM CPMS.

15. Fuel limits.

Comment 110: Commenter 17705 encourages the EPA to limit the requirement to establish maximum 

fuel inputs to sources that are uncontrolled and solely relying on fuel analysis to demonstrate 

compliance with a numeric standard. The commenter states that the characteristics of fuel, in particular 

coal fuel, can vary between shipments, so it is problematic to establish any type of maximum value 

based on a one-time, short-term performance test, and further, for units that are controlled, relying on a 

fuel input limit does not adequately account for emissions reductions achieved by the control devices. 

According to the commenter, for controlled units that do not elect to use CEMS to demonstrate 

compliance, it would be more appropriate to establish parametric monitoring for the control devices 

(coupled with period performance testing) than unnecessarily constrain fuel supplies through nonrepresentative “maximum” fuel inputs.

Response to Comment 110: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS. Compliance with emission limits will be shown with periodic 

(quarterly) performance testing, CEMS, or a combination of annual emission testing and PM CPMS.

16. CEMS only.
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Comment 111: Commenter 17715 states that it is not clear in the proposed rule that installing and 

operating CEMS for the regulated HAP and surrogates will relieve a source of the burden of also 

monitoring compliance with operating limits on control equipment based on a performance stack test. 

According to the commenter, the EPA should require no additional proof of compliance than a properly

calibrated and installed CEMS would provide, and the EPA should format both the language and tables 

in the rule to clarify its intent as it relates to CEMS used for demonstrating compliance.

Response to Comment 111: No other monitoring is required if a source uses a CEMS to demonstrate 

direct compliance with an emission limit (including the SO2 surrogate limit for HCl). 

17. Section 63.10007(a) Site Specific Test Plan.

Comment 112: Commenter 17718 states that the EPA should provide guidance on what should be 

included in a site specific test plan as mentioned in proposed regulatory language of 40 CFR

63.10007(a) and referenced to 40 CFR 63.7(c). According to the commenter, the development of 

external QA programs with testing firms and laboratories (especially if multiple testing firms and 

laboratories are needed) has the potential to become extremely burdensome without clearer guidance.

Response to Comment 112: The EPA has already issued a guideline document for the preparation of 

site specific emission test plans. The document can be found at http://www.epa.gov/ttn/emc/guidlnd/gd042.pdf

18. CPMS comments.

Comment 113: Commenter 1775 states that section 63.10010(h) sets out requirements for CPMS and 

the previously proposed PS 17 would apply to CPMS. 73 FR 59,983 (Oct. 9, 2008). The commenter

objected in the PS 17 rulemaking to the proposed application of that specification to future performance 

specifications without revision of the individual subpart. See UARG Comments on Proposed 

Performance Specification And Quality Assurance Requirements For Continuous Parameter Monitoring 

Systems (February 5, 2009), EPA-HQ-OAR–2006–0640-0064. The commenter states that whatever 

specifications are necessary to support this rule, they must be proposed and promulgated in this 

rulemaking.

Response to Comment 113: This is no longer applicable except to the extent PS 17 would apply to a 

PM CPMS under this rule. Given that PS 17 is not yet final, this issue is best addressed in the response 

to this concern in the context of the PS 17 rulemaking, not in this rulemaking, given that the issue 

extends to all promulgated NESHAP standards with a parametric monitoring system potentially subject 

to PS 17.

Comment 114: Commenter 17775 states that the rule proposes various installation operation and 

maintenance requirements for “flow monitoring systems,” “pressure monitoring systems,” and “total 

secondary power monitoring systems.” According to the commenter, several of these proposed 

requirements are unnecessary or unclear: first, with respect to flow monitoring systems, depending on 

the fluid being measured, many systems do not use flow meters due to reliability issues, corrosion, or 

composition. Instead, these processes frequently use constant rate pumps. The commenter states that 

these pumps have a known capacity given their specific application and are either “on” or “off.” As an 

example, states the commenter, scrubber module slurry pumps operate in this manner; the reported 

scrubber slurry flow rate is simply based on the number of pumps in service. According to the 

commenter, the EPA should make clear that flow monitoring systems are not required for any CPMS 
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and that systems that use constant rate pumps are not subject to performance specifications (see 

Technical Memorandum from Richard McRanie, McRanie Consulting, “Comments on the Proposed 

Utility MACT Rule - Operating Parameters” (July 2011) (Attachment 11) at 18).

Response to Comment 114: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.

Comment 115: Commenter 17775 states that the section 63.10010(h)(2)(i)(C) requirement to 

“Minimize the effects of swirling flow or abnormal velocity distributions due to upstream and 

downstream disturbances” is unnecessary and extremely vague. According to the commenter, the 

requirements in proposed subsections (A) and (B) - to properly locate the flow sensor and to use a sensor 

with a sensitivity no greater than two percent of the expected flow rate - are adequate. The commenter 

states that the term “minimize” is not sufficiently objective to be meaningful in this context, and more 

objective requirements (e.g., some number of diameters downstream of a flow disturbance) might not be 

possible to meet.

Response to Comment 115: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.

Comment 116: Commenter 17775 states that the evaluations under section 63.10010(h)(2)(i)(D) should 

specifically allow for procedures that include process trending and comparisons that can indicate the 

flow monitor is performing properly (similar to the fuel flow to load concept in Part 75, Appendix D 

section 2.1.7). According to the commenter, operators should not necessarily be required to ship meters 

off to get NIST traceably certified each year.

Response to Comment 116: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.

Comment 117: Commenter 17775 stated that with respect to pressure monitoring systems in section 

63.10010(h)(2)(ii)(B), the requirement will be difficult to interpret as a regulatory requirement. The 

commenter states that the requirement in subsection (A) to provide a representative location is sufficient; 

however, the EPA also proposes to require that EGUs “Use a pressure sensor with a minimum tolerance 

of 1.27 centimeters of water, or a minimum tolerance of 1 percent of the pressure monitoring system 

operating range, whichever is less” (proposed section 63.10010(h)(2)(ii)(C). According to the 

commenter, this should read, “whichever is less restrictive.” If a source is using a 0 to 30 psig gauge for 

some purpose, the 1.27 cm requirement would be the lesser error, states the commenter, but it would be 

a 0.06 percent error. The commenter does not believe this is what the EPA intended.

Response to Comment 117: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.

Comment 118: Commenter 17775 states that under section 63.10010(h)(2)(ii)(D) there is a requirement 

to “[p]erform checks at least once each boiler operating day to ensure pressure measurements are not 

obstructed (e.g., check for pressure tap pluggage daily).” According to the commenter, daily checks are 

not warranted; pressure sensors are used in a variety of process functions (e.g., to monitor baghouse and 

scrubber pressure drops, slurry tank liquid levels, etc.) and have design features that ensure the pressure 

taps do not get plugged. The commenter states that for pressure sensors that are exposed to gases (e.g., 

boiler exhaust gases), the pressure taps have purge air to periodically clean them; the purges can be 

varied to ensure that key pressure measurements are very reliable. For pressure sensors that are exposed 
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to liquids (e.g., scrubber slurry), states the commenter, redundant taps and a water cleaning system is 

frequently used; while one tap is being cleaned with water, the other tap is being used for process 

control. According to the commenter, while the EPA might believe it is reasonable to expect pluggage 

problems with pressure taps, these types of problem rarely exist, and it would be unnecessarily

burdensome to expect technicians to check each pressure tap for pluggage every day.

Response to Comment 118: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS.

19. ASTM methods.

Comment 119: Commenter 1775 states that the in addition to the use of ASTM D3173 for 

determination of moisture content in fuel the EPA also should allow use of (1) ASTM D7582 “Standard 

Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis,” or (2) 

ASTM D5142 “Standard Test Methods for Proximate Analysis of the Analysis Sample of Coal and 

Coke by Instrumental Procedures,” which are equivalent to ASTM D3173, except that they are 

automated. The EPA should reference ASTM D3302 “Standard Test Method for Total Moisture in 

Coal,” and ASTM D3180 “Standard Practice for Calculating Coal and Coke Analysis from AsDetermined to Different Basis.” The commenter states that both ASTM D3302 and ASTM D3180 are 

referenced in ASTM D3173, and in addition, the following methods are currently used by EGUs for Hg, 

metals, and chlorine in coal and should be evaluated for inclusion without an equivalency analysis:

 EPA Method 7473 - “Mercury in Solids and Solutions by Thermal Decomposition, 

Amalgamation, and Atomic Absorption Spectrophotometry”;

 ASTM D4326 - “Standard Test Method for Major and Minor Elements in Coal and Coke Ash By

X-Ray Fluorescence”;

 ASTM D6357 - 04 - “Test Methods for Determination of Trace Elements in Coal, Coke, & 

Combustion Residues from Coal Utilization Processes by Inductively Coupled Plasma Atomic 

Emission, Inductively Coupled Plasma Mass, & Graphite Furnace Atomic Absorption 

Spectrometry.”

Finally, states the commenter, a number of methods that were identified in Table 2.3 of the 2010 ICR 

are not included in the rule. According to the commenter, the EPA should include these methods or 

explain why they were excluded.

Response to Comment 119: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS. The only fuel-related provision in the final rule is an option for 

liquid oil-fired units to demonstrate compliance with the acid gas standards by documenting that fuel 

moisture content remains no greater than 1.0%. This demonstration is based on monitoring results or 

fuel supplier certifications.

Comment 120: Commenter 17808 recommends the EPA set a percent water content limit for oil, rather 

than setting HCl and HF emissions limits for liquid oil-fired EGUs. The commenter states that ASTM 

test methods are available for measuring the percent water content of fuel oil (D95 and D473) and that 

plant operators would test each shipment received to ensure compliance with the proposed limit.

Response to Comment 120: The EPA agrees. The only fuel-related provision in the final rule is an 

option for liquid oil-fired units to demonstrate compliance with the acid gas standards by documenting 
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that fuel moisture content remains no greater than 1.0%. This demonstration is based on monitoring 

results or fuel supplier certifications.

20. Miscellaneous.

Comment 121: Commenter 18025 requests clarification with respect to demonstrating compliance 

when using a new or changed blend of fuel that was not initially considered in compliance 

demonstrations. The commenter’s understanding is that any time a unit burns a new fuel (type, mix, 

etc.), it has to be tested for relevant constituents (Hg, chlorine, etc.). The commenter states that if these 

are within the parameters established during initial compliance testing, the fuel may be used, and if not 

(for example, the chlorine is higher than established during initial testing), the unit must conduct new 

testing to demonstrate compliance before using the new fuel. The commenter would like confirmation 

that the proposed rule is flexible enough to accommodate shifts in fuel blends after 2015.

Response to Comment 121: The final rule has removed the requirements for operating and fuel limits 

with the exception of a PM CPMS. 

Comment 122: Commenter 17821 states that in some cases the only viable option is to utilize stack 

testing. According to the commenter the use of total PM proposal using filterable PM as an operating 

limit and PM CEMS as a compliance option is flawed; the viability of HCl CEMS make this option 

unrealistic; and sources using dry sorbent or have older FGD may not be capable of maintaining SO2

emissions below 0.2 lb/MMBtu.

Response to Comment 122: The agency disagrees with the commenter’s suggestion that the use of PM 

CEMS as a compliance option is flawed. The final rule has been revised to use a filterable PM standard, 

with a PM CPMS option available to monitor continued performance and compliance with an operating 

limit established in terms of the raw output of the monitor. For sources unable to meet the SO2 standard 

or use HCl CEMS, the frequency of required testing has been changed to quarterly.

Comment 123: Commenter 17808 recommends the use of Hg as a surrogate for Se and, thus, filterable 

PM alone may be a surrogate for other HAP metals. The commenter states that in the preamble, the EPA 

states that selenium is captured by controls for Hg and acid gases. In fact, states the commenter, 

commenter’s initial correlation analysis indicates that selenium emissions are in fact better-correlated to 

Hg and acid gas emissions than CPM (r=0.44 for Hg or 0.60 for HCl, versus 0.32 for condensable PM (r 

> 0.2 implies significance at 5 percent level with 60 units)).

Response to Comment 123: The EPA has removed the requirement of total PM as an alternate 

equivalent standard for HAP metals. For more detailed discussion and response, please see section 

4F01A.

Comment 124: Commenter 17808 recommends PM CEMS combined with a separate Se standard. Se

emissions could be confirmed by quarterly or annual stack testing limited to Se. According to the 

commenter, similar to the treatment of limited use units, this requirement could be scaled such that units 

emitting Se well below the standard were subject to less stringent monitoring requirements than those 

units emitting very close to the standard. Alternatively, states the commenter, at a minimum, the 

commenter recommends that the EPA base the filterable PM limit on the facility-specific ratio to the 

total PM standard, rather than the initial numerical performance. Commenter also recommends that this 

facility-specific limit remain constant for a longer period of time, such as annually, to provide a measure 

of regulatory certainty.
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Response to Comment 124: The final rule does not use a total PM standard as a surrogate for non-Hg 

HAP metals, but instead uses a filterable PM limit. The PM CEMS monitoring will in fact be a 

parameter monitor (PM CPMS) which is not intended to produce results in terms of the standard. These 

changes address the concerns at issue in this comment.

Comment 125: Comment 18428 ask for clarification as to whether the purpose of operating limits is to 

ensure compliance between performance tests.

Response to Comment 125: Yes. Operating limits are part of the compliance monitoring and assurance 

provisions in the rule. In the final rule, the only operating limits that apply are for a PM CPMS and, in 

certain situations, for liquid oil-fired units. See further discussion elsewhere in this document and in the 

final preamble.

Comment 126: Commenter 17655 recommends clarification of section 63.10005 that allows 

exemptions from the PM testing and testing for specific metals, but only for single fuels. According to 

the commenter, the rule should be clarified to allow similar provisions for units that co-fire (e.g., coal 

with natural gas). The commenter also notes that units testing for PM should not have to test for HAP

metals because there is no HAP metals limit. The commenter believes testing for metals is simply an 

extension of the ICR. 

Response to Comment 126: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and an alternate equivalent standard. Facilities complying with an alternate 

equivalent limit do not have to perform periodic testing for the corresponding HAP or vice versa.

Comment 127: Commenter 17655 encourages the EPA to consider opacity as an acceptable measure of 

PM. Contrary to manufacturers’ claims, the commenter does not regard stack-mounted PM monitors to 

be sufficiently accurate, reliable, or durable to yield significantly more or better compliance data than 

opacity monitoring currently does. The commenter notes that PM monitoring is a direct measurement of 

PM, which is the limit for EGUs. The commenter states that although PM is itself a surrogate for nonHg metals, it is the primary standard expressed in the regulation – compliance with specific metals limits 

would be regarded as an alternative compliance option rather than a primary option under this rule. 

According to the commenter, the surrogate continuous monitoring method for PM emissions has always 

been, and should continue to be, opacity measurement.

Response to Comment 127: The EPA disagrees that opacity would be considered accurate or sensitive 

to the concentration levels of PM required by the final rule.

Comment 128: Commenter 17730 states that they appreciate the EPA setting the performance testing 

requirements for all pollutants at the 5-year interval. The commenter believes that for sources that 

choose to use CEMS to demonstrate ongoing compliance with the standards, the performance testing 

requirements could be even further streamlined given that sources will be required to report 

electronically and that CEMS users will undergo annual certification via RATA.

Response to Comment 128: The final rule has been revised so sources electing to use CEMS for Hg, 

SO2, or HCl will not be required to perform performance testing every 5 years.

Comment 129: Commenter 17761 states that if PM CEMS are required, the commenter recommends 

providing for an annual PM stack testing compliance alternative as the basis for determining compliance 

with the limits established under this rule. According to the commenter, an annual PM stack test is 
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effective in determining compliance because operating units under existing CAM plans have prescribed 

methods to verify PM to include bag leak detection and opacity readings.

Response to Comment 129: The final rule requires quarterly performance testing or PM CPMS with 

annual performance testing.

Comment 130: Commenter 17775 states that the EPA’s proposal contains nothing to indicate at what 

point a monitoring system is deemed “certified” and if the EPA were to attempt to define that point, 

sources likely would arbitrarily attempt to postpone some part of the required testing in order to control 

when the “performance test” begins. According to the commenter, the EPA should allow EGUs to 

complete required testing (or designate a CEMS that previously has completed the required testing”) and 

to notify the Administrator of the date upon which its “performance test” will begin. The commenter 

states that this will ensure consistency between EGUs and allow EGUs to confirm that their controls are 

working properly, and that they are operating at an appropriate load and combusting appropriate fuel, 

before the “performance test” begins.

Response to Comment 130: That approach is allowed for under the final rule. The notification of intent 

will indicate the date for commencement of a performance test.

Comment 131: Commenter 17886 states that the EPA should not set unit “operating limits” based on 

performance measured during short term tests. According to the commenter, if the EPA retains the total 

PM requirement, one preferable option would be to ratio the performance test results to the MACT limit, 

and set the “operating limit” at the level that (based on the test results) would be equal to the MACT 

limit.

Response to Comment 131: The final rule does not maintain the total PM requirement.

Comment 132: Commenter 19120 requests clarification as to whether the EPA intends to require 1/5 

year stack testing for all surrogates. For example, states the commenter, section 63.100005(d)(4) states 

that initial compliance for coal-fired EGUs with FGD technology using SO2 CEMs is determined using 

the average hourly SO2 concentrations obtained during the first 30-day operating period, and section 

63.10005(d)(5) states the same for PM CEMS. However, notes the commenter, pages 423 and 425 of the 

preamble and section 63.1 0005(a) indicate that PM and metals and SO2 and HCl testing includes testing 

initially and every 5 years; section 63.10005(a) states that “If you use a continuous monitoring system 

that measures a surrogate for a pollutant (e.g., an SO2 monitor), you must perform initial emission 

testing during the same compliance test period and under the same process (e.g., fuel) and control device 

operating condition of the pollutant and surrogate, in addition to conducting the initial 30-day

performance test.” Additionally, states the commenter, section 63.10006(a) and (b) state, that PM and 

non-Hg metal HAP, and SO2 and HCl emissions testing, respectively, is required at least every 5 years.

Response to Comment 132: In response to comments, the final rule has removed all requirements for 

testing of both the HAP and the corresponding surrogate(s). Facilities complying with a surrogate limit 

do not have to perform periodic testing for the corresponding HAP or vice versa. 

Comment 133: Commenter 17785 states that the proposed rule requires fuel analysis monthly in order 

to assess continuous compliance. The commenter states that the portion of the draft rule that addresses 

this (section 63.10011) is unclear. According to the commenter, equation 13 of this section seems to 

suggest that the Hg concentration in a monthly sample must be less than the 90th percentile 

concentration based on the Hg content measured during demonstration of initial compliance; equation 
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13 refers to the 90th percentile of Hg concentration as calculated according to Equation 8, but the 

referenced Equation 8 calculates the average fuel Hg content, not the 90th percentile. The commenter 

states that the EPA needs to clarify these equations so it is clear how they intend the 90th percentile Hg 

concentration to be calculated.

Response to Comment 133: The fuel sampling and analysis requirements have been removed from the 

final rule.

Comment 134: Commenter 17696 states that if the EPA does not limit the rule to Hg, the EPA should 

provide additional flexibility in the emissions monitoring and compliance determination requirements. 

Commenter believes certain of the proposed requirements are unreasonable in light of available 

alternatives that are more cost-effective and provide sufficient assurance of continuous compliance. The 

commenter states that revisions are also needed concerning Hg monitoring and to make the compliance 

determination requirements clearer and easier to understand.

Response to Comment 134: The EPA believes that the final rule streamlines the continuous compliance 

monitoring requirements, and does so in a way that is clearer and easier to understand as requested by

the commenter. The EPA disagrees with limiting the rule to Hg as explained in response to other 

comments concerning this issue.
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5B01 - Recordkeeping/Reporting: Data reporting requirements

Commenters: 17402, 17655, 17677, 17681, 17772, 17821, 17881, 17902, 18023

1. Reporting requirements for deviations.

Comment 1: Commenter 17402 opposes the EPA’s proposed definition of “deviation” and the EPA’s 

reporting requirements for deviations. The commenter states that in the proposed rule, the EPA defines 

“deviation” to include (but the definition is not limited to) any failure to meet “any emission limit, 

operating limit, work practice standard, or monitoring requirement,” or any failure to meet a term or 

condition to implement a related requirement included in an operating permit. The commenter states that 

should a deviation occur, the EPA proposes specific reporting requirements, that in the case of an 

exceedance of an emission limit during a malfunction, the owner or operator of the facility must notify

the EPA within two business days to avail itself of an affirmative defense to civil penalties for the 

malfunction and submit a report of the malfunction within 45 days, and that all deviations must also be 

reported in the source’s semiannual compliance report.

Comment 2: Commenters 17402 and 17902 state the EPA’s proposed definition of “deviation” is 

overbroad and should not include operating limits. Commenter 17902 suggests that on-site records be 

maintained that document operating limit deviations, associated investigation and appropriate corrective 

action if deemed necessary. Commenter 17402 recommends that operating limits and monitoring 

requirements should not be a reportable deviation since they are indicators of compliance and not 

emission limitations. As an example, the commenter states that the EPA’s proposal requires that for an 

ESP, the parameter operating limit is calculated by the total secondary power input as measured during 

the performance test. Commenter respectfully submits that operating parameter exceedances, such as 

this ESP power limitation or CEMS downtime (failed calibration error test, power outages, data 

acquisition and handling problems, etc.), are compliance indicators and, therefore, inappropriately 

categorized as deviations.

Comment 3: Commenter 17402 states a further reason to exclude operating limits from the definition of 

deviation is that these parameter operating limits do not account for variability due to normal operation 

in some cases. As an example, the commenter states that the requirement of a minimum pressure drop 

and liquid injection rate on a wet PM scrubber will result in the reporting of deviations during low-load 

operation. Similarly, according to the commenter, the requirement to maintain sorbent injection rate at 

the rate established during the compliance test might result in the unnecessary reporting of deviations 

when these units fire lower pollutant containing fuels. The commenter asserts that since these 

parameters do not take into account variability, it would be arbitrary and inefficient to characterize any

exceedance of the operating limit (or failure to meet the operating limit in the case of a minimum 

operating limit) as a deviation.

Comment 4: Commenter 17402 further urges the EPA to reconsider its proposed reporting requirements 

for deviations. Specifically, commenter opposes the EPA’s proposal to require the owner or operator of 

the facility to notify the EPA of an exceedance of an emission limit during a malfunction within two 

business days to avail itself of an affirmative defense to civil penalties for the malfunction. Commenter

submits that such a requirement is excessive and recommends that if the EPA requires a notification for 

exceedances of an emission limit during malfunctions, it should be in semiannual compliance reports.

Comment 5: Commenter 17881 states that in regard to requirements for reporting monitor downtime 

deviations in section 63.10031(e)(5), the commenter asks that the rule needs to specify how the 
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calculations for these deviations should be conducted. The commenter notes that calculations could be 

based on the number of block averages in the reporting period, total operating time during the block 

period associated with the deviation, etc.

Response to Comments 1 - 5: The EPA believes the rule was accurate as proposed in delineating what 

is a deviation. Under most MACT standards, a deviation includes any failure to meet an emission limit, 

work practice requirement, operating limit, or monitoring requirement. The final rule does not alter this 

approach. Deviations are reported in semiannual compliance reports. The compliance reports require the 

information in the General Provisions 63.10(e) section and some additional source specific information 

which is typical of reporting. In addition, for malfunctions, additional reporting requirements apply.

2. Reporting requirements for malfunctions

Comment 6: Commenter 17681 states that section 63.10001(iii)(9) of the proposal appears to require 

notification to the EPA Administrator of a malfunction within two business days of the event if the 

malfunction may cause an exceedance of the 30-day average. According to the commenter, facilities 

may not be aware that the malfunction will cause an exceedance of the 30-day average until more than 

two days have passed. The commenter states that the reporting time should be at least as long as the 

averaging time, which in this case is 30 days. In addition, the commenter questions whether facilities 

may report to their local compliance office if the state is delegated under the CAA instead of reporting to 

the EPA Administrator.

Commenter 17681 states this section (63.10001(iii)(9)) also requires a calculation of emissions during 

the malfunction. The commenter questions whether this calculation has to be prepared and sealed by a 

professional engineer.

Response to Comment 6: The commenter is correct in terms of the timing for reporting a malfunction. 

This requirement for prompt reporting was proposed to ensure that reporting of a malfunction incident 

occurs promptly after the event occurs to enable effective oversight and follow-up by the EPA and 

delegated authorities. All of the 30-day averages are rolling averages, such that every operating day is a 

new compliance period, and the malfunction will not just influence the 30th day after the malfunction but 

all the rolling compliance periods in between. The EPA disagrees with the commenter and has 

maintained the reporting requirement as proposed. With respect to reporting to delegated state agencies, 

that would occur in accordance with delegation of this subpart, if applicable. With respect to preparation 

and signature by a professional engineer, the answer is no. The rule plainly states: “The analysis shall 

also specify, using best monitoring methods and engineering judgment, the amount of excess emissions 

that were the result of the malfunction.”

3. Quarterly reporting of hourly data.

Comment 7: Commenter 18023 believes the quarterly submittal of electronic hourly data is 

inappropriate for an emission limit-oriented rule, is highly burdensome on the emission source operator, 

and should be removed from the proposed rule requirements. Commenter states that section 7.2.5, 

Quarterly Reports, is written to reflect the quarterly submittal of electronic hourly data that is 

appropriate for a trading program-related rule, most likely because these requirements were copied out 

of the vacated CAMR rule.

Comment 8: Commenter 17655 agrees that hourly data records are unnecessary for demonstrating 

compliance. Commenter states that in evaluating the cost of hourly reporting, the EPA consulted with 
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DAHS vendors and was told that the cost of collecting hourly data would be minimal. However, 

commenter believes the agency failed to consult with users to ascertain the time requirements and costs 

for reviewing hourly data, as opposed to records compressed to daily, weekly, or even monthly 

averages. Commenter submits that there is no need for hourly data, as there are no hourly compliance 

standards. Further, ECMPS could be easily adapted by the EPA to accommodate records in other than 

hourly increments (daily or monthly). According to the commenter, this would provide considerable 

savings to the industry and would not impact compliance or public health in any way.

Comment 9: Commenter 17772 states that the EPA should modify the requirements for submitting 

extensive new continuous data sets for compliance purposes. According to the commenter, the approach 

taken in the proposed rule may be appropriate for an allowance trading program where there is a market 

function that is facilitated by the collection and public posting of emissions data. The commenter asserts 

that that approach is unnecessary and unduly burdensome in the context of a regulatory regime where 

the focus is on demonstrating technology compliance.

Commenter 17772 states that in an age of electronic recordkeeping, there is a natural tendency to ask for 

“all the data that is available.” According to the commenter, however, in industrial America and in the 

utility sector, routine reporting of massive amounts of hourly data to the EPA is an unwarranted use of 

manpower for both the transmitters and recipients, not to mention bandwidth and storage considerations.

Commenter 17772 states that the industry has grown accustomed to electronic data reporting in SO2 and 

NOX trading programs. According to the commenter, in such a program, where there is a national market 

in allowances, a case can be made for submitting hourly data on a quarterly basis so that it can be posted 

on a national website. The commenter states that this creates a transparent database for economic 

decisions and trading.

Commenter 17772 states that demonstrating that a facility has installed MACT level controls and is 

operating that equipment appropriately is an entirely different type of regulatory approach and the 

reporting requirements should be consistent with that regulatory approach. The commenter requests that 

the EPA modify its approach as follows: (1) The related limits will be specified in the Title V permit. (2) 

The responsible entity is required to certify each year as to full compliance or intermittent compliance. 

(3) Records should be kept and made available as necessary to the EPA. (4) Exception reporting should 

be performed quarterly.

Commenter 17772 states that this recommendation is a proven approach used by the EPA for other 

industries and in other contexts and there is no need for EGU compliant facilities to transmit massive 

MACT-related databases to the EPA every quarter.

Commenter 17772 states that this proposal is consistent with past EPA MACT requirements imposed on 

other industries. According to the commenter, for example, the MACT program applied to the steel 

industry does not require multiple CEMS and quarterly reporting of all hourly data; that would be 

unwarranted and unwieldy. The commenter states that the same can be said about the pulp and paper 

industries, etc., and that the utility sector should be treated similarly - exception reporting, but not 

massive transfers of compliant hourly data. According to the commenter, it is arbitrary and capricious to 

single out the utility industry for a level of MACT reporting that is far in excess of other important U.S. 

industries.

Response to Comments 7 - 9: The EPA has retained in the final rule that CEMS data be provided on an 

hourly basis. We believe this approach simplifies compliance with the rule by harmonizing its 
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monitoring and reporting requirements, to the extent possible, with those of 40 CFR Part 75. With a few 

exceptions, the utility industry is already required to monitor and report hourly emissions data according 

to Part 75 under the title IV ARP and other emissions trading programs. The Hg monitoring 

requirements are consistent with Part 75 and similar to those that had been promulgated for the vacated 

CAMR regulation. Integrating Hg emissions data and QA test results into the existing Part 75 –

compliant DAHS that is installed at the vast majority of the coal-fired EGUs is an appropriate approach 

for addressing submission of emissions and QA data under this rule. We obtained feedback from several 

DAHS vendors indicating that the cost of modifying the existing Part 75 DAHS systems to 

accommodate hourly reporting of Hg CEMS and sorbent trap data would be similar, and in some cases, 

less than the cost of the first proposed option. Also, there is little or no cost to industry for the flow rate, 

CO2, or O2, and moisture monitors needed to convert Hg concentration to the units of the standard, 

because, as previously noted, almost all of the EGUs already have these monitors and the associated 

reporting mechanisms in place. In view of these considerations, we have decided in favor of this second 

option for Hg.

Requiring the reporting of hourly Hg emissions data from EGUs is advantageous, both to the EPA and 

industry. The DAHS can be automated to demonstrate compliance with the standard on a continuous 

basis. The data can then be submitted to the agency electronically, thereby eliminating the need for the 

agency to request additional information for compliance determinations and program implementation. 

The rule also requires quarterly electronic reporting of hourly SO2 CEMS data and HCl CEMS data (for 

sources electing to demonstrate continuous compliance using those certified CEMS). Those are included 

for the same reasons as the Hg monitoring data.

The comments seem to assume that the costs for adding new parameters to the system would be directly

proportional to the number of parameters collected. This neglects to recognize that the ECMPS and 

DAHS frameworks do not need to be re-engineered if the new data requirements are adopted in a 

manner that harmonizes requirements. Also, reducing the computer output to daily or monthly values 

does not necessarily save the user any significant (if any) effort. In fact, it may cost the source more 

effort or cause them to miss data problems that in the end may affect their compliance determination. 

Once data collection is automated (and given that the industry and the EPA has already invested in the 

automation process that is ECMPS) the burden on the operator is minimized. The systems can (and 

have) been programmed to do data analysis and QA evaluations automatically, giving a user a report of 

hours that might be in question. The environmental managers at facilities can, and have, designed 

custom checks into their systems to streamline their data reporting responsibilities. These advantages 

need to be recognized when evaluating the electronic reporting option as a means for data QA.

4. Recordkeeping requirements for liquid oil-fired units.

Comment 10: Commenter 18023 states that the recordkeeping requirements for liquid oil-fired units are 

unreasonable. The commenter states that the EPA requires “for each 30 boiler operating day period . . . a 

description of the fuel, the total fuel usage amounts and units of measure, and information on the 

supplier and original source of the fuel” (76 FR 25035). According to the commenter, other than total 

usage amounts, these records are, and should be, kept by shipment and if all shipments are in 

compliance, additional information is unnecessary. The commenter asserts that it is not possible to 

collect this information in the format requested by the EPA – fuel cannot be separated on a per-shipper 

basis after it has been put into a storage tank – but only by shipment and that to avoid the burden of 

having to convert shipment-based data into operating-day data, the EPA should base any recordkeeping 

requirement on shipment data.
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Response to Comment 10: With the changes in the final rule that eliminate the fuel analysis 

requirements, this comment is largely moot. The only fuel data that must be retained is a record of fuel 

use by operating hour, in order to determine if the EGU meets the low use exemption. Also, if a source 

opts to monitor fuel moisture in each fuel shipment for a liquid fuel unit and demonstrates that this 

alternative monitoring is acceptable under the part 63 general provisions (in lieu of other monitoring for 

acid gases), then the source must keep records of the fuel moisture of each fuel shipment.

5. Semi-annual compliance dates.

Comment 11: Commenter 17681 states that section 63.10031(b)(2) of the proposed rule appears to 

require semi-annual reports on January 31 and July 31 and that the beginning of the year is very busy

with reports required to state and federal agencies. The commenter states that the EPA should push these 

dates back to March 1 and September 1 respectively. For the same reasons, commenter 17821 requests 

that the EPA should allow sources at least 60 days to submit reports, and the EPA should allow local 

permitting agencies the flexibility to grant sources 60 days to file their semi-annual reports.

Response to Comment 11: The semiannual compliance dates are consistent with other EPA reporting 

requirements and are necessary to ensure timely reporting and allow any identified issues to be 

addressed in a timely manner. These dates do not apply to the quarterly reporting to ECMPS of CEMS 

data.

6. Annual documentation.

Comment 12: Commenter 17677 states that the regulation includes documentation for an annual report 

on emission tests, inspection, repairs, adjustments, findings and corrective actions. Commenter believes 

this additional documentation burden seems to do nothing more than increase non-productive work load 

for our personnel.

Comment 13: Commenter 17681 also notes that section 63.10031(c)(5) of the proposed rule appears to 

require a summary of the annual performance tests in the compliance report which is submitted to the 

EPA. If the testing data is reported electronically to the EPA within 60 days after each test through 

CDX, why does the EPA need this data sent to them again?

Response to Comments 12 - 13: The final rule contains compliance and deviation reporting 

requirements that are typical of most NESHAP. These summary reports are in addition to the detailed 

performance test results reported electronically and will be used by the permitting authority for effective 

compliance oversight. 

7. Other data reporting requirements.

Comment 14: Commenter 17881 states that the requirement in section 63.10031(c)(4) to report monthly

fuel use is not relevant, as it is the fuel type and heat input fraction that matters in determining 

compliance. The commenter suggests that the section 63.10032(d)(1) requirement to maintain such 

records should be deleted, or at a minimum, revised to require records of the types of fuel which are 

burned and the maximum percentage or fraction of each fuel type (on a heat input basis).

Comment 15: Commenter 17881 states that the waste determination information should only be 

required if a new fuel type is introduced following the initial compliance demonstration report.
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Response to Comments 14-15: Apart from those EGU owners or operators who choose to use 

emissions averaging, monthly fuel use information need not be reported given the changes in the final 

rule, although records of fuel use by operating hour must be maintained, as noted above. Moreover, 

EGU owners or operators who self-determine or have the EPA determine via petition that their fuel is a 

non-waste under 40 CFR 241.3 or who combust fuel processed from discarded non-hazardous secondary

materials have additional emissions testing, notification, reporting, and recordkeeping requirements as 

discussed in the rule.
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5B02 - Recordkeeping/Reporting: Records that must be retained

Commenters: 17681, 17775, 17881

1. Objection to retaining records on-site.

Comment 1: Commenter 17681 states that section 63.10033(c) of the proposed rule appears to require 

that records be kept on site. Commenter believes it is much better to keep records electronically or at 

least not congregated at each site and if the EPA wants a copy, the facility can produce a copy within a 

reasonable time.

2. Objection to requirement to retain records for five years.

Comment 2: Commenter 17775 states that the EPA proposes to require retention of all data, including 

reports, records of measurements, maintenance, corrective action, and “other information,” for 5 years. 

(Proposed section 63.10033 and Appendix A section 7.1.) Commenter objects to these requirements. To 

mandate a retention period longer than 3 years, the EPA must justify the requirement under the PRA. 

See 5 CFR section 1320.5(d)(2)(iv) (requiring a showing of substantial need or statutory mandate to 

require retention of records for more than 3 years). The commenter states that the EPA’s statement in the 

supporting statement for the February 2011 proposed ICR291 that “None of the guidelines in 5 CFR

1320.5 are being exceeded,” is simply false. The EPA-HQ-OAR-2009-0234-3031 at 4.

Response to Comments 1 - 2: The agency believes the record keeping and retention requirements are 

consistent with other requirements already in place, specifically 40 CFR part 63.10 (b) “General 

recordkeeping requirements. (1) The owner or operator of an affected source subject to the provisions of 

this part shall maintain files of all information (including all reports and notifications) required by this 

part recorded in a form suitable and readily available for expeditious inspection and review. The files 

shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, 

corrective action, report, or record. At a minimum, the most recent 2 years of data shall be retained on 

site. The remaining 3 years of data may be retained off site. Such files may be maintained on microfilm, 

on a computer, on computer floppy disks, on magnetic tape disks, or on microfiche.” In addition, the 5-

year retention period is the general rule for all recordkeeping for all sources under the part 70 operating 

permits program. Given that the general provisions for part 63 and part 70 already establish a 5-year 

retention period, the EPA believes it is justified in using those precedents for the retention periods under 

this subpart. If the EPA stayed silent on retention period in this subpart, the general provisions would 

provide for the 5-year retention as would the part 70 requirements. Thus, this action does not establish 

any new retention requirements, but merely confirms that the existing retention requirements apply.

3. Objection to requirement to maintain mercury mass emission records.

Comment 3: Commenter 17881 states that section 7.1.8 requires Hg mass emission records for those 

units complying with the Hg lb/GWh emission limit. According to the commenter, this section is based 

on the misguided premise that the Hg mass emissions, as pounds per clock hour, are required in order to 

perform the lb/GWh Hg emission rate calculations. The commenter states that as noted in relation to 

section 6.2.2, only the Hg emission rates, as lb/hr, and average electrical generating rate, as MW, are 

needed in order to calculate the lb/GWh emission rate. Thus, according to the commenter, this section 

should be re-written on a Hg mass emission rate versus integrated mass emissions basis.
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Response to Comment 3: The EPA has retained the language as is, given the formulas that are used for 

determining lb/GWh.
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5B03 - Recordkeeping/Reporting: Electronic reporting of CEMS data

Commenters: 17715, 17716, 17725, 17730, 17740, 17775, 17795, 17796, 17800, 17805, 17820, 17821, 

17873, 17877, 17886, 17909, 18014, 18039, 18449, 18498, 18831, 19114, 19121, 19122, 19679

1. ECMPS reporting.

a. Support for ECMPS reporting.

Comment 1: Commenters (17715, 17740, 17796, 17805, 17877, 17909, 18039, 18449, 19122) support 

using ECMPS.

Comment 2: Commenter 17796 believes all CEMS collected data should be required to be submitted to 

a modified ECMPS so this data can be assembled in one area which can be accessed by all users.

Comment 3: Commenters 17805 and 19122 also agree that ECMPS could be used for submittal of 

compliance data as required in the proposed rule. The commenters note that his system is currently used 

successfully to report Acid Rain Program emissions from utility units.

Comment 4: Several commenters (17740, 17873, 18039, 18449, 18831) support the EPA’s proposal to 

handle reporting for PM, HCl, and Hg through ECMPS. According to the commenters, the ECMPS

system simplifies the reporting process by evaluating continuous monitoring data and other information 

in an electronic format in preparation for submittal to the agency. The commenters note that ECMPS is 

used by Part 75 and emissions trading programs and is a well-established data reporting tool.

Comment 5: Several commenters (17715, 17877, 19114) state that ECMPS is currently being used 

successfully by industry and the infrastructure is already in place, thereby reducing costs. According to 

the commenters, industry personnel have been trained for the constituents that are already being reported 

by ECMPS so the learning curve will be very short and will allow a rather seamless transition to HAP

reporting. One commenter proposes that the EPA take advantage of the work that has already been done 

for the ECMPS process by extending it to the HAP rule.

Comment 6: Commenter 19121 recommends that ongoing monitoring data collected under the 

requirements of NESHAP be reported into the ECMPS system. Commenter recommends that episodic 

data, such as performance and stack testing be reported using the ERT.

b. Support for ECMPS reporting, but with supplemental rulemaking and public comment.

Comment 7: Commenters 17715 and 19114 state that the EPA should use ECMPS for all reporting. 

Commenters state that reporting associated with the proposed rule should be handled by ECMPS, but 

should be the subject of a supplemental rulemaking in order to fully address all of the software issues 

that arise with electronic reporting. According to the commenters, the EPA should invite industry

involvement as was used during the initial development process of ECMPS. The commenters note that 

utility involvement during development will enable a smooth transition in dealing with the numerous 

monitoring requirements that will impact every EGU stack at the same time.

Comment 8: Commenter 17730 supports the use of ECMPS for the reporting of data and summary

reports as a part of the EGU MACT proposed rule but believes that if the EPA wants to require the use 

of ECMPS, the EPA will need to publish for public comment (1) additional reporting provisions to 
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cover information to be reported for SO2 CEMS, PM CEMS, HCl CEMS, and any other test or 

parameter the EPA intends to include; and (2) its reporting formats and instructions for all data to be 

reported. Commenter states that the EPA has not published reporting requirements in sufficient detail for 

any parameter other than Hg. According to the commenter, although the EPA previously developed a 

reporting format for Hg, that format was developed to meet reporting requirements under the nowvacated CAMR. Commenter states that the EPA cannot use a reporting format to specify substantive 

reporting requirements but that the rule must identify each piece of information to be reported. 

Commenter adds that the EPA must submit its desired format and instructions to an open public 

comment process so that the regulated community and members of the public can confirm that the EPA 

is not attempting to use the format to create new, or alter existing reporting requirements.

Comment 9: Commenter 17800 states that should the EPA require use of ECMPS, the EPA would at a 

minimum need to publish for comment (1) additional reporting provisions to cover information to be 

reported for SO2 CEMS, PM CEMS, HCL CEMS and any other test or parameter the EPA intends to 

include, and (2) its reporting formats and instructions for all data to be reported.

Comment 10: Commenters 17775 and 17800 in disagreeing with the reporting format requirements in 

Appendix A, note that the EPA is obliged to subject that format to notice and comment rulemaking and 

review by OMB. According to the commenters, the EPA electronic reporting formats specified to date 

by the Administrator have been sufficiently complex and substantive that it is not appropriate to totally 

exempt them from rulemaking. The commenters state that as implemented, the EPA’s electronic formats 

are substantive requirements that impose significant burdens and impact on EGU’s compliance status. 

The commenters state that to the extent some flexibility is needed to make adjustments to the format, 

that flexibility can be provided by rule.

Comment 11: Commenter 19114 recommends that the EPA invite industry involvement as was used 

during the initial development process of ECMPS, to enable a smooth transition in dealing with the 

numerous monitoring requirements that will impact every coal- or oil-fired EGU stack as a result of the 

EGU-MACT proposal. According to the commenter, the EPA should develop the tool, then propose its 

use in a separate rulemaking. The commenter states that numerous times industry has been stuck with 

software implementations that are not ready and that issues with software should be handled in advance 

of it being required for compliance with a rulemaking.

c. Opposition to ECMPS reporting.

Comment 12: Multiple commenters (17716, 17725, 17795, 17820, 17821, 17886, 18014, 18498) state 

that reporting hourly CEMS data electronically should not be required. The commenters state that the 

EPA proposes to require quarterly reporting of hourly emissions data as well as results of all required 

certifications and QA tests through the CAMD ECMPS software and that summaries of the emissions 

test results and semiannual deviation reports would also be required for SO2 CEMS, PM CEMS, and 

HCl CEMS. The commenters believe there is no need for this requirement; the hardcopy deviation 

reports and data assessment reports are adequate and consistent with the requirements of other MACT

and NSPS compliance rules.

Comment 13: Multiple commenters (17716, 17725, 17775, 17795, 17820, 18014, 18498) state the EPA 

has not justified the burden of requiring the ECMPS reporting. Several commenters (17716, 17725, 

17775, 17820, 18014, 18498) state that the data reporting requirements in Appendix A for Hg go far 

beyond what is necessary for this rule. The commenters state that the EPA portrays this proposed 

reporting requirement as easy – that sources would “simply integrate Hg emissions data and QA test 
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results into the existing Part 75-compliant DAHS,” under one of two options. One commenter states that 

after presenting these two options, the EPA states that it obtained “feedback from several DAHS

vendors” who suggested the cost of the second option was “similar, and some cases, less than the cost of 

the first option.” According to the commenter, any software under Option 2 would have to provide the 

same information required by Option 1; The commenter states that sources would likely integrate the 

new requirements within the DAHS that they currently use for Part 60 and Part 75 reporting, but this 

does not mean that the proposed reporting scheme would be simple or cheap to implement. According to 

the commenters, adding the requirement to report hourly emissions data and other QA/QC data would be 

burdensome both to utilities as well as the EPA, especially given differences between Part 75 and 

MACT reporting (such as bias adjustment factors and missing data substitution). The commenters assert 

that CMPS was developed for emissions trading purposes, not for demonstrating continuous compliance 

with emission limits. The commenters conclude that reporting information via ECMPS under this rule 

would be a costly exercise that is both unnecessary and unjustified.

Commenter 19679 asks for clarification on whether the Hg CEMS data to be integrated into the Part 75

compliance DAHS will be subject to the on-going QA requirement of Part 75 or if it would be subject to 

the QA requirements of Part 60 Appendix F and PS-12A as is indicated for the “first option”. According 

to the commenter, specifically relevant to this distinction is the requirement listed in Part 75, appendix A 

section 7.6.5 to apply a bias adjustment factor to CEMS data as part of a RATA. The commenter states 

that due to the low Hg concentrations present in a well controlled coal fired utility boiler stack, without 

the requirement for a bias adjustment factor the low emitter exemption of Part 60, PS-12A section 13.3 

could allow a Hg CEMS to pass the required RATA while under reporting emissions relative to the 

emission standard.

Comment 14: Commenters 17775 and 17795 object to the EPA’s proposal to submit hourly Hg data. 

Commenter 17775 states that the EPA has not justified or prepared an ICR for the proposed 

requirements for quarterly reporting of hourly Hg emissions data. The commenter disagrees with the 

EPA’s assumptions regarding hourly Hg data and QA reporting.

Comment 15: Commenter 17775 states that the EPA could develop an electronic reporting scheme as 

an alternative to ECMPS or ERT that might more easily accommodate the kinds of information the EPA 

seeks to collect. According to the commenter, whatever scheme the EPA uses, it still would need to be 

supported by a rule, and new ICR, that identifies each piece of information to be reported and a format 

that has been subject to review and comment. The commenter notes that the supporting statement for the 

February 2011 proposed ICR for the proposed rule does not mention reporting of hourly Hg emissions 

data, or of the QA and certification data for Hg monitoring systems. The commenter states that the 

proposed ICR also makes no mention of the EPA’s development and maintenance of schema and 

software for collection or review of those data, or an accounting of their costs. According to the 

commenter, if the EPA were to move forward with a requirement to report other information using 

ECMPS, the EPA would need to issue a rulemaking proposal and ICR that identifies (similar to 

Appendix A) each piece of information required to be reported, and the specific format for that 

submission and would need to provide a justification for requiring reporting of that information.

Commenter 17775 objects to the EPA’s proposal to submit hourly Hg data. The commenter states that 

the EPA has not justified or prepared an ICR for the proposed requirements for quarterly reporting of 

hourly Hg emissions data.
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Commenter 17775 states that Part 75 reporting is unsuitable for the reporting proposed under Appendix 

A and the revisions required to the EPA’s and EGU’s software to implement the reporting proposed 

under Appendix A would be significant and costly.

Commenter 17775 states that in addition to the compliance report, deviation report, performance tests 

and monitoring system performance evaluations, the EPA proposes to require quarterly reporting of 

hourly Hg data (e.g., emissions, certification and QA, and monitoring plan data) using the EPA’s 

ECMPS. According to the commenter, although the proposed rule does not mention ECMPS, Appendix 

A includes detailed recordkeeping requirements similar to what had been included in CAMR, and 

requires quarterly electronic reporting of much of that information “in a format specified by the 

Administrator.” Commenter 17775 states that all of the information needed to determine an EGU’s

compliance status already must be reported under the part 63 general provisions. The commenter finds 

these additional requirements to be redundant and burdensome. If the EPA requires additional detail, the 

EPA should provide that additional detail in proposed section 63.10031 and, if the provisions overlap, 

make clear that the more detailed requirements are in lieu of the more general requirements.

Commenter 17775 states that in the EPA’s discussion of modifications to ECMPS, the EPA suggests 

that ECMPS also could be modified to allow electronic submission of “30-day averages of parametric 

data, 30-day average fuel content data, stack test results, and performance of tune up records.” The 

commenter notes that the EPA’s proposed rule does not contain any requirements to record, let alone 

report, 30-day averages of parameter and fuel data.

Commenter 17886 states that the EPA needs to define what constitutes a valid 30-day rolling average, 

suggesting that the EPA should use a specific number of hours (i.e., 540 hrs or 75 percent of the month) 

in that period to qualify it for a valid period. 

Commenter 17775 disagrees with the EPA’s proposal for data reporting in Appendix A. The commenter

observes that the EPA has not required hourly data reporting or the sorts of QA data identified in 

Appendix A in a MACT, and this information is not necessary for sources or the EPA to determine 

compliance with MACT standards. The commenter states that this information does not enhance the 

quality of MACT compliance demonstrations. 

Commenter 17775 objects to the EPA’s requirement in Appendix A to require submission of Hg 

monitoring information in quarterly reports to the Administrator “in a format specified by the 

Administrator.” The commenter notes that the commenter has challenged similar provisions for use in 

other programs judicially. The commenter’s objections are: (1) concerns regarding the nature and 

content of the EPA’s format, which the agency has changed with some frequency and at significant 

expense to EGUs, (2) the EPA-provided software’s failure to ensure compliance with the CROMERR

requirements at 40 CFR part 3.10, (3) inconsistencies between the reporting format and the substantive 

provisions of the applicable rule, and (4) the lack of appropriate procedures for submitting reports when 

a source is unable to gain access to the EPA’s computer with the EPA provided software, or connect to 

the internet in a secure environment.

Comment 16: Commenter 17909 does not support collection of continuous Hg or particulate data. 

According to the commenter, the EPA’s authority under this section of the CAA is for exception 

reporting only.

2. Data reporting formats.
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Comment 17: Commenter 17725 asks that the EPA consider a single format for reporting data. The 

commenter states that for each set of monitoring and reporting requirements, reporting entities must 

purchase monitors and data acquisition handling systems. According to the commenter, these systems 

must be connected to other plant data monitoring systems and integrated into a single report. The 

quantity of data for EGUs can be staggering. The commenter encourages the EPA to employ like data 

collection and transfer systems for multiple programs so that this expensive system can be used for each 

program, especially since much of the data is the same. The commenter states that the utility industry 

has worked with the CAMD for the last 17 years to devise a comprehensive schema that is flexible and 

is relatively easy to maintain. The commenter recommends that this program and others continue to use 

ECMPS or devise a way to import data between programs.

Commenter 17725 suggests that the EPA use ECMPS reporting for the following data elements:

1. Monitoring Plan Data for PM CEMS, HCl/HF CEMS, Continuous Hg Monitoring Systems, and 

Sorbent Trap Monitoring Systems similar to what is currently being collected for COMS.

2. Monitoring Plan Data for Auxiliary Boilers present at facilities currently reporting in ECMPS

required under the Industrial Boiler MACT rules.

3. Certification Test Results for PM CEMS:

a. PS-11 Initial Correlation Audit Results

b. PS-11 Absolute Correlation Audit Results

c. PS-11 Annual Relative Response Audit Results

d. PS-11 Response Correlation Audit Results

e. Initial Certification 7-Day Drift Test Results

4. Certification Results for Continuous Hg Monitoring Systems:

a. Initial Certification Cycle/Response Time, 7-Day Drift, 3-point Linearity Check, and RATA 

test results

b. NIST Traceability Test Results

c. Annual RATA testing results

d. Weekly System Integrity Check results

5. Certification Results for Sorbent Trap Monitoring Systems:

a. Initial and Annual RATA test results

6. Certification Results for HCl/HF CEMS:

a. Initial Certification Cycle/Response Time, 7-Day Drift, 3-point Linearity Check, and RATA 

test results

b. Required ongoing quarterly and annual ongoing QA Tests for HCl/HF CEMS

Commenter 17725 does not support routine hard copy submittals of Monitoring Plan records as listed in 

Appendix A to subpart UUUUU section 7.1.1.2.2 and wishes to maintain an onsite file at each facility

that can be made available for inspection by the EPA and state auditors and inspectors.

Response to Comments 1 - 17: We recognize that emissions reporting for continuously measured 

pollutants (SO2, Hg, etc.) and for periodically measured pollutants (PM, non-Hg HAP metals, etc.) have 

different data demands. We recognize that minor revisions of the ECMPS will fulfill our data needs for 

continuously measured pollutants and we will make these minor modifications for receipt of the 
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additional data demands. We also recognize the need for substantial modifications to the ECMPS to 

accommodate the data needs for periodically measured pollutants. Although major modifications of the 

ECMPS would be required for periodic compliance tests by isokinetic and instrumental test methods, 

minor revisions are required of the ERT to receive these tests. We are implementing the changes in the 

ERT that are required to provide the software tools to implement the delivery of these performance test 

data to us.

The electronic submission of compliance test reports to us through the Central Data Exchange (CDX) is 

not solely for the purpose of developing improved emissions factors as some commenters assert. 

Although populating WebFIRE will allow us to improve emissions factors, we intend to use data stored 

in WebFIRE as the primary location for compliance test reports for use by regulatory authorities. The 

electronic submission of compliance test reports is a continuation of our efforts to bring the submission 

and sharing of environmental data into the modern age. The storage of this compliance data in our 

WebFIRE provides a convenient location which is already used to store source test data.

As our and State and local agencies data systems mature, information provided through the ERT will be 

used to populate these data systems. We are currently upgrading the AIRS Facility System and expect to 

replace manually entered information with electronic population from the ERT. We are also working 

with several State and local agencies to adopt the use of the ERT for delivery of compliance test reports. 

The ERT is also much improved since the version used during the 2010 ICR process, and there is no 

expectation that the information to be reported under this final rule will be as extensive as some of the 

data reported for the 2010 ICR purposes.

We disagree that a separate and independent regulatory action is required to implement electronic 

reporting for selected regulated sources. Each of these regulatory actions for selected source categories 

provides ample notice and the opportunity for individuals to provide comment. We also disagree that the 

system to receive the compliance data must be operational prior to establishing the requirement for 

regulated sources to submit compliance data electronically. We are on track to have the capability to 

receive electronic compliance tests through our CDX in sufficient time to receive all utility source test 

reports required by this final rule.

We do plan a separate and independent regulatory action to implement electronic reporting for regulated 

entities which are covered by past and future rules. Although we have provided draft procedures for the 

development of emissions factors, that effort is an ancillary effort to the electronic delivery of 

compliance test reports. It is our intention to convert to the electronic delivery and storage of all air 

emissions compliance source test data. With this transition, we believe this valuable information will be 

more readily available not only for compliance purposes but also for a variety of other uses.

3. Other CEMS reporting comments.

Comment 18: Commenter 18014 notes that the proposed EGU MACT Rule does not include provisions 

to use the part 75 “conditionally valid data procedures.” According to the commenter, this would require 

the operator to invalidate the part 75 conditionally valid data (for SO2, CO2, O2 or flow monitors) for the 

EGU MACT recordkeeping and reporting purposes. The commenter states that a clearer approach would 

be to allow quality-assured data from a CEMS certified and operated in accordance to part 75 to be used 

for EGU MACT compliance (with the exception of bias adjusted and missing data).
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Response to Comment 18: The final rule provides for certain part 75 procedures for the CEMS and 

sorbent trap monitoring systems used to comply with this rule, including the use of the conditionally 

valid data procedures.

Comment 19: Commenter 18449 questions why either CO2, O2 or stack moisture monitors are required 

to calculate mass emissions for any pollutant. According to the commenter, reporting pollutant 

concentrations on a dry or diluent basis may have been appropriate a generation ago, when point of 

impingement calculations required stack output concentrations but for several decades, it has been clear 

that the total mass emitted of each pollutant is what drives the environmental effects. The commenter 

states that only the wet concentration and wet stack flow is required to accurately calculate the mass 

emission rate of any pollutant and that adding confounding factors such as O2, CO2 or stack moisture 

will only increase periods of missing data and reduce the accuracy of the reported results.

Commenter 18449 states that further input of plant heat rate or electrical output being produced is all 

that is required to calculate the EPA’s proposed emissions in lb/TBtu or lb/GWh. According to the 

commenter, a CO2 analyzer may be required for heat input, but this is a separate issue, independent of 

any individual pollutant CEMS. The commenter states that the EPA should clearly differentiate the 

performance requirements for each pollutant monitor from the requirements of the additional variables 

required to calculate the proposed emissions limits.

Response to Comment 19: The final rule retains these requirements, consistent with the general 

approach to monitoring for this sector under part 75.

Comment 20: Commenter 18831 supports the ability to use alternatives to CEMS. The commenter 

states that sources should be allowed to select CEMS, but alternatives such as stack testing should be 

retained and CAM provisions developed.

Response to Comment 20: The final rule provides some alternatives, primarily CEMS or periodic stack 

testing (and a PM CPMS option). We do not believe developing CAM-like provisions under this rule is 

warranted as those requirements would likely be duplicative of existing control device and similar 

monitoring that already applies to these sources under other programs.
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5B04 - Recordkeeping/Reporting: Electronic reporting of emissions test data

Commenters: 17316, 17621, 17638, 17681, 17718, 17719, 17725, 17730, 17767, 17770, 17775, 17790, 

17795, 17816, 17820, 17821, 17868, 17881, 18014, 18498, 19033, 18023

1. ECMPS reporting of emissions test data.

a. Support for using a modified version of ECMPS.

Comment 1: Several commenters (17638, 17681, 18023) state that the EPA should use a modified 

version of ECMPS rather than the ERT to submit performance test results. The commenter states that 

the EPA’s proposed rule requires that performance test results be reported electronically to WebFIRE

and suggests using ERT software to do this and that the EPA has requested feedback on using a 

modified version of ECMPS for this purpose. Based on problems encountered by the industry in 

submitting ICR data using the ERT software, commenters suggest it would be better to use a modified 

version of ECMPS rather than ERT but that revisions to the ECMPS are necessary. According to the 

commenters, without revision, it may be difficult to use the ECMPS for this purpose because that system 

was developed to support a trading system and not an emission limit based rule.

Comment 2: Commenter 17316 also supports the idea of using a modified ECMPS program to report 

MACT test and RATA data in lieu of ERT reporting. The commenter states that as pointed out in the 

preamble to this rule, electric utilities are subject to the Acid Rain Program and are familiar with 

ECMPS reporting, which should facilitate the transition to MACT reporting and that SO2 RATA data is 

already reported in ECMPS, so this approach would avoid some duplication.

Commenter 17316 adds that using a modified ECMPS for MACT reporting could also help promote the 

development of an information system that allows ready interchange of data between the various 

programs (Part 75 ECMPS and Part 60/63 NSPS/MACT ERT), serving as a sort of bridge effort. 

According to the commenter, if this approach were adopted, the companion NSPS (subparts Da and Db) 

regulations should also allow use of ECMPS reporting, as an alternative to ERT, otherwise for utility 

units subject to NSPS, the potential consolidation benefits of reporting MACT data in ECMPS would be 

lost.

b. Opposition to using a modified version of ECMPS.

Comment 3: Commenter 17767 states that the ECMPS option would be overly burdensome as their 

experience with it has shown it to be increasingly obsessed with minor data formatting issues that often 

prevent the submission of data (though it might have been acceptably formatted and submitted without 

issue in the past). According to commenter, it often involves many hours of manpower to correct those 

issues without benefit to the quality of the key data sets or the environment. Commenter anticipates that 

this would continue if MACT rule data were to be submitted via ECMPS

Response to Comments 1 - 3: The EPA disagrees with the commenters who feel that using the ECMPS 

data collection process is overly burdensome and in the assertion that minor data formatting issues often 

prevent the submission of data. The assertion points to the fact that many data reporting errors may not 

have been previously caught in the past. The EPA created the ECMPS process to replace its previous 

less efficient and less precise data verification systems and processes. The result of this re-engineering is 

that there are significantly fewer formatting issues that prevent submissions, and a fraction of 

submissions that contain critical errors at the close of each reporting period. This has added significantly
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to the EPA’s ability to validate adherence to regulatory requirements, as well as, checking for the 

technical accuracy of the data. The EPA has received considerable support from the regulatory

community for the revised ECMPS process, praising its efficiency and the reduction in man hours 

required to report (and when necessary correct errors) using the ECMPS process as compared to the old 

record type column format and ETS/MDC processes that preceded ECMPS. However, the EPA 

recognizes that emissions reporting for continuously measured pollutants (SO2, Hg, etc.) from CEMS is 

structurally and procedurally different from what is needed to electronically collect reference method 

test data for periodically measured pollutants (PM, non-Hg HAP metals etc.). Therefore, the EPA has 

decided not to include detailed stack test data into ECMPS, rather will focus on only making minor 

revisions to ECMPS necessary to implement the EPA’s MACT data needs for continuously measured 

pollutants in a manner consistent with how other CEMS monitoring requirements are currently

implemented through the ECMPS process. Doing so will minimize the structural changes to ECMPS 

needed while harmonizing the data collection and reporting for CEMS systems. Because more 

substantial modifications would be required of the ECMPS to accommodate the MACT data 

requirements for detailed reference method test data and other periodically measured pollutants, the EPA 

has decided to further develop the ERT to receive these data.

2. ERT reporting of emissions test data.

a. Support for ERT reporting.

Comment 4: Commenters 17767 and 17795 agree with the proposed rule that the ERT would be an 

appropriate means of submitting test results to the agency. Commenter 17795 states that most states will 

require hard copies or electronic copies for quality assurance and acceptance. According to the 

commenter, ERT provides the flexibility to upload and import supporting data, and a common system 

will benefit operators with units in multiple states to have one system to generate reports for the EPA 

and local regulators.

b. Opposition to ERT reporting.

Comment 5: Several commenters (17621, 17718, 17775, 17790, 17868) express opposition to using 

ERT for reporting compliance test results, and commenters (17621, 17718, 17770, 17790, 17821, 

19033) state that the ERT needs extensive revision before it is used for that purpose.

Response to Comments 4 - 5: The EPA disagrees that the ERT needs extensive revision before it can 

be used for documentation and delivery of compliance test reports for which it is designed. The EPA 

also believes that with the January 2012 addition of the ability to satisfy CROMERR compliance several 

state and local agencies will no longer require wet signature paper test reports. The EPA recognizes that 

some state and local agencies are reluctant to adopt new programs, assess the experiences of those that 

do adopt new programs and adopt new programs when they have determined the effort benefits their 

program goals and available resources. The EPA believes that the use of the ERT will demonstrate to 

state and local agencies that it provides them with improved ability for compliance oversight, improved 

responsiveness with resources that are comparable to what they currently use to manage the paper 

reports which they currently receive. As a result, the EPA expects a reduction in the number of 

regulatory authorities which require the delivery of paper reports with wet signatures.

i. Performance, susceptibility to viruses, and corruption of data.
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Comment 6: Commenter 17730 notes that the EPA is proposing to use the ERT as the platform for 

sources to electronically report data. The commenter states that the ERT is a Microsoft Access desktop 

application that is prone to computer viruses, has created several problems in using this application, and 

is subject to significant performance issues, including software crashes and shutdowns, inoperable 

features (like report generation), and inadequate identification of errors preventing data analysis. 

Commenter has banned the use of the Microsoft Access database system on its internal network due to 

this susceptibility and is, therefore, opposed to its use for uploading data to the EPA WebFIRE database.

Commenter is concerned with the corruption of data that may occur due to the susceptibility of this 

software package to virus infections. The commenter questions how the EPA would ensure that the data 

that would be submitted to the WebFIRE database would not be infected and require further attention by

the EPA or by the source to rectify the information and if the EPA considered the cost of repairing a 

database that is eventually corrupted by virus attack, and if so, how the repair would be accomplished 

and the cost to the industry for the effort.

Response to Comment 6: The EPA implements scans and other techniques to ensure that data within its 

network environment, including data submitted through CDX is free of viruses and other security 

concerns. The EPA would expect that utilities would likewise ensure that the information it manages 

within its network and computers remains free of viruses and is not corrupted. It is the source’s 

responsibility to submit complete and accurate data to the EPA.

Comment 7: Commenter 17770 provided examples of the aspects of the ERT that the commenter 

considers cumbersome. The commenter states that even though the third party emission tester provided 

the correctly formatted spreadsheet to import into the ERT, there were instances where the ERT would 

not accept the file. According to the commenter, this resulted in manual input of the data, which was 

time consuming and frustrating. Commenters 17770 and 17775 noted the program provides no useful 

error messages when data were input incorrectly. The commenters state that the EPA staff were helpful 

in correcting these errors, but the entire exercise only proved that the current version of the ERT is not 

fully developed for everyday use.

Comment 8: Commenter 17790 states that the ERT used for submitting 2010 ICR results and had 

significant flaws including: not accepting data, incompatible test methods, inoperable features.

Comment 9: Commenter 17621 observes that the ERT provides no error checking or validation 

capability, and that the program failed to complete emissions calculations with no indication of the 

reason. According to the commenter, the ERT could also enhance data quality by storing information 

needed to understand sample results, such as results of analysis of method and field blanks and 

laboratory quality control samples.

Response to Comments 7 - 9: The EPA recognizes that the ERT provided 2 years ago for use with the 

utility ICR had some aspects of data entry that required improvement. To the extent that users identified 

those issues we have modified the ERT to address the issue such that users could successfully provide 

the required test report with all the necessary documentation. While the commentors may have had 

difficulties with this earlier version of the ERT, the majority of the ERT’s users were provided with 

adequate information for use in developing the final rule. The EPA understands that the number and 

detail of information required for the ICR was greater than what we require for compliance tests. The 

EPA believes that with the increased familiarity in the use of the ERT combined with the revisions to the 

ERT, the delivery of compliance reports to the EPA will not be a significant issue.

ii. Issues with detection limit flags.
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Comment 10: Commenter 17621 states that data flags confuse detected and non-detected results. The 

EPA requires users to assign a “DLL” (detection level limited) flag to emission measurements with one 

analytical fraction above detection limit and others below detection limits. The commenter notes that 

this can cause a degradation of data usability.

Comment 11: Commenter 17821 states that ERT coding for method detection limits is confusing and 

cumbersome; the ERT does not support the typical non-detect with a (<) symbol. The commenter states 

that the ERT requires the use of bracketed symbols as a bracketed “less than” detection level value (e.g., 

[<0.0105]) and that for sample trains with multiple fractions (i.e., Method 29 Metals) this is very

confusing and increases the possibility for miscoded data.

Response to Comments 10 - 11: The EPA recognizes that the way the EPA required users to enter 

individual laboratory components was not the most effective way to provide this information. We also 

recognize the significant level of resources required of source testers to properly enter laboratory data 

into their standard reports or into the ERT. This effort duplicates the resources expended by laboratories 

to enter this information into the report provided to the source tester. This effort is also duplicated again 

when tests are evaluated by regulatory authorities. The EPA will engage the laboratories to develop an 

electronic lab report which the ERT will use to populate an expanded laboratory feature to allow for 

improved capabilities for use by test contractors, state agency reviewers and the EPA.

iii. All required emission test methods are not supported by the ERT.

Comment 12: Commenter 17821 notes that Method 30B (Hg) is not supported by the ERT in the most 

current version and that in order to use the non-supported methods such as Method 30B a supplemental 

worksheet is used. According to the commenter, the use of elements outside of the ERT increases the 

opportunity for errors in both data entry and data review.

Response to Comment 12: The EPA has partnered with a vendor of Method 30B hardware and 

software to implement the electronic documentation of this test method into the ERT. The 

implementation of 30B in the ERT will be a non proprietary application so users can use any vendors’

hardware or field software to manage the collection and analysis of the samples. This capability will be 

in the version of the ERT available within 6 months following promulgation of the utility boiler MACT 

standard.

iv. ERT is burdensome.

Comment 13: Commenters 17730 and 17775 state that use of the ERT is burdensome (easily adding 10-

20 percent to the cost of compliance testing), requiring manual inputting of significant amounts of 

information much of which is not relevant to performance test results. Commenter 17730 states that, 

contrary to the EPA’s assertion, ERT as currently designed, requires the reporting of vast amounts of 

information that are not otherwise required to be reported under the applicable EPA test methods, or the 

EPA’s proposed rule. Commenter 17730 believes that the EPA’s requirement to report electronically is 

not sufficiently defined to support reporting of all the information that must be entered into ERT in order 

to submit the data.

Comment 14: Multiple commenters (17718, 17621, 17725, 17790, 17816, 17820, 17881, 18014, 

18498) state that using the ERT increases the cost of emission test submittal due to the time needed to 

manually input significant amounts of information. Several commenters (17718, 17621, 17816, 17881) 

note that manually inputting data significantly increases the potential for errors in data 
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reporting. Commenters 17718 and 17816 suggest that the EPA should make the tool more user 

friendly. Commenter 17881 states that using the ERT adds significant costs to the stack testing process.

Comment 15: Commenters 17730 and 17775 state that the ERT requires reporting of information that is 

not otherwise required to be reported under the applicable EPA test methods, or the EPA’s proposed 

rule. Commenter 17730 believes that EPA’s requirement to report electronically is not sufficiently

defined to support reporting of all the information that must be entered into ERT in order to submit the 

data.

Comment 16: Commenter 17775 provides as examples of information required by ERT that is not 

required under the EPA test methods or the proposed rule: proposed section 63.10030(a) and Table 10 

require compliance with section 63.7(c). The commenter states that section 63.7(c) requires 

development and, if requested by the Administrator, submission of a “site-specific test plan” to the 

Administrator “at least 60 calendar days before the performance test is scheduled to take place” (i.e., at 

the same time as the notification of intent to conduct a performance test) but that section 63.7(c) does 

not require submission of test plan information in the performance test report which obviously is 

submitted after the performance test is conducted. The commenter states that the EPA also proposes to 

require compliance with section 63.7(g) (Proposed Table 10). The commenter states that proposed 

section 63.7(g) requires submission as part of the “results of a performance test,” “the analysis of 

samples, determination of emissions, and raw data,” while ERT requires reporting of much more 

information, and including a test plan. The commenter states that similarly, the EPA’s proposed 

requirement in section 63.10031(h)(1) to report “performance test data” is not sufficiently detailed to 

support reporting of all of the information that must be entered into ERT in order to submit data.

Comment 17: Commenter 19033 states that using the ERT was very cumbersome, and the reported data 

was not easily reviewable.

Response to Comments 13 - 17: The EPA disagrees that the ERT is excessively burdensome. The EPA 

does understand that some users of the ERT did not have electronic versions of field data sheets or 

laboratory reports which allowed data to be imported into the ERT or that they could use to copy and 

paste the applicable data. The EPA recognizes that this duplication of effort could result in an increased 

burden. The EPA also understands that some field test crews preferred to use spreadsheet applications 

which they developed to match their workflow and data needs. The organization of these proprietary 

spreadsheet applications did not always match the organization of field data in the ERT. The EPA has 

developed a supplementary field data spreadsheet module for use with a wide variety of proprietary field 

data collection spreadsheet applications. We have also provided instructions for merging this 

supplementary module with proprietary spreadsheet applications. When the supplementary module is 

merged with the proprietary field data spreadsheet applications, the ERT will import the required 

information and greatly reduce the effort in entering the field data into the ERT. The EPA is also 

embarking on an effort which will allow for laboratory information to be electronically populated into 

the ERT.

The EPA disagrees that the ERT requires the reporting of vast amounts of data that is not currently 

required for compliance test reports. The commenters may be confusing the presence of a data field as 

one that requires entry of data. Also, the commenters may be confusing the level of information the EPA 

required in the ICR with what would be required for a compliance test report. The EPA made the ERT 

flexible to accommodate a wide variety of existing data requirements specified by various state and local 

agencies and which are specified in various published EPA test methods and published state and local 

agency test methods. The EPA does not expect sources to enter data into every available field of the 
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ERT for every source test. Each state or local agency which has delegated authority has provided 

guidance on those data elements which they expect in compliance source tests.

v. The EPA has provided no explanation of how WebFIRE will work.

Comment 18: Commenter 17730 states that the EPA has provided no discussion in the preamble 

regarding how the information required to be submitted under ERT to WebFIRE will benefit the EPA 

and sources by improving emission factors. Commenter says that the EPA has yet to explain in any 

detail how the process of emission factor development from performance test data submitted to 

WebFIRE will work.

Comment 19: Commenter 17775 states that the EPA is requiring reporting to ERT under provisions that 

are inapplicable, inappropriate, and impossible to implement. According to the commenter, the EPA also 

has provided no information to suggest that WebFIRE will be operational by the proposed January 1, 

2012 deadline. The commenter stated that the proposed requirements should be withdrawn.

Commenter 17775 states that to the extent EPA wants to add subpart UUUUU data to an emissions 

factor database, the EPA can do that on its own. That is not adequate justification for requiring 

additional reporting by EGUs. The commenter asks that the EPA fully explain how the process of 

emission factor development from performance test data submitted to WebFIRE will work. The 

commenter states that in its comments on the ANPR, the commenter expressed concerns about the 

process the EPA described and objected to any attempts to mandate submission of reports before the 

EPA had more completely explained its plans, completed any necessary rulemakings, and made 

operational its website. According to the commenter, the EPA should not be promulgating requirements 

intended to support a larger program piecemeal before that program has been fully developed. The 

commenter asserts that the EPA should reserve the question of mandatory reporting to WebFIRE until it 

has resolved the questions raised in the ANPR.

Response to Comments 18 - 19: The electronic submission of compliance test reports to the agency

through the CDX is not solely for the purpose of developing improved emissions factors. While 

populating WebFIRE will allow the agency to improve emissions factors, the agency intends to use data 

stored in WebFIRE as the primary location for compliance test reports for use by regulatory authorities. 

The electronic submission of compliance test reports is a continuation of the agency’s efforts to bring 

the submission and sharing of environmental data into the modern age. The storage of this compliance 

data in the EPA’s WebFIRE provides a convenient location which is already used to store source test 

data. As EPA and State and local agencies data systems mature, information provided in the ERT will be 

used to populate these data systems. The EPA is currently upgrading the AIRS Facility System and 

expects to replace manually entered information with electronic population from the ERT. The EPA is 

also working with several state and local agencies to adopt the use of the ERT for delivery of 

compliance test reports.

vi. Opposition to submittal of RATA data.

Comment 20: Commenter 17718 asked that the EPA clarify whether only CEMS RATA performed 

under this proposed rule are to be submitted electronically using the ERT and whether only SO2 RATAs

performed for the combined purposes of 40 CFR Part 75 and this proposed regulation would be reported 

in ERT. The commenter notes that any annual NOX or flow monitor RATA performed for 40 CFR Part 

75 requirements would not to be reported in the ERT even though it may have been performed 

concurrently.
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Comment 21: Commenter 17775 objects to the EPA’s suggestion that reporting of RATA results to 

WebFIRE would be helpful in the development of emission factors. The commenter notes that RATAs

are tests of CEMS in comparison to test methods and they are performed under conditions that may or 

may not be representative of operations the EPA deems relevant to emission factor development. The 

commenter also objects to the required submissions of results after each “performance evaluation” since 

that term is defined to include calibrations, which may be performed daily, whereas RATAs likely are 

performed only once a year and considers the proposed exclusion of “opacity data” is needless, since the 

rule does not require monitoring of opacity.

Commenter 17775 states that provisions for reporting in section 63.10021(a)(11)(iv) and (v) require 

sources that use PM CEMS to report “performance test data, except opacity data” and “relative accuracy

test audit data” electronically using ERT. The commenter states that in proposed section 

63.10021(a)(17)(i) and (ii), the EPA also includes a requirement for reporting of “performance test data, 

except opacity data” and “relative accuracy test audit data” for LEEs. The commenter objects to these 

provisions, citing the following points: EGUs using PM CEMS and LEEs do not conduct RATAs. PM 

CEMS are subject to different tests (RCAs and RRAs). According to the commenter, since LEEs

comply by initially demonstrating applicability with emission tests and thereafter by fuel analysis, LEEs

have no monitoring systems upon which to conduct RATAs. The commenter asserts that with respect to 

“performance test data,” the provisions are duplicative of a more general provision the EPA proposes.

Comment 22: Commenter 17881 states that all of the information the agency needs to determine an 

EGU’s compliance status already must be reported under the part 63 general provisions, and hard copies 

of the test reports will be provided to the Administrator (and/or the delegated authority). The commenter

does not agree with submitting RATA PM data into the WebFIRE database. The commenter states that 

for those monitoring systems operated pursuant to 40 CFR Part 75, RATA information is already being 

submitted to the EPA in an electronic format.

Commenter 17881 disagrees with the provision to submit RATA results through the ERT. The 

commenter states that the CEMS is the compliance mechanism, not the reference method data that is 

collected during the RATA.

Response to Comments 20-22: While the ERT has been upgraded to accept RATAs, the EPA does not 

believe that there is a need to submit these RATAs with multiple electronic applications. RATAs 

submitted through the EPA’s EMPCS for Part 75 reporting will also satisfy the requirement for parts 61 

and 63 reporting.

vii. Use of the ERT should require rulemaking and opportunity for comment.

Comment 23: Several commenters (17730, 17725, 17775) believe it is inappropriate for the EPA to 

require submission of reports through this rulemaking before the EPA has more completely explained its 

plans, completed any necessary rulemakings, and made operational its website. Commenter 17730 states 

that the EPA should not be promulgating requirements intended to support a larger program, piecemeal, 

before that program has been fully developed. The commenter requests that the EPA provide notice and 

opportunity to comment on all reporting requirements. The commenter concludes that the EPA should 

set aside the question of mandatory reporting to WebFIRE until it has fully addressed these issues. The 

EPA also has provided no information to suggest that WebFIRE will be operational by the proposed 

January 1, 2012 deadline.
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Comment 24: Commenter 17775 states that the EPA should identify the software it proposes to require 

with sufficient specificity that it can be incorporated by reference into the rule. According to the 

commenter, if the EPA simply wants to require electronic reporting, the EPA should limit its 

requirement to a specific format (e.g., xml) and allow sources to procure or develop their own software 

to comply with that format and the associated reporting elements.

Comment 25: Several commenters (17820, 18014, 18498) state that the development of any reporting 

tool or reporting format should also follow a transparent development process that includes feedback 

from the regulated community.

Response to Comments 23 - 25: The EPA disagrees that a separate and independent regulatory action 

is required to implement electronic reporting for selected regulated sources. Each of these regulatory

actions for selected source categories provides ample notice and the opportunity for individuals to 

provide comment. The EPA also disagrees that the system to receive the compliance data must be 

operational prior to establishing the requirement for regulated sources to submit compliance data 

electronically. The EPA is on track to have the capability to receive electronic compliance tests through 

the EPA’s CDX in sufficient time to receive all utility source test reports required by this rule.

The EPA does plan a separate and independent regulatory action to implement electronic reporting for 

regulated entities which are covered by past and future rules. While we have provided draft procedures 

for the development of emissions factors, that effort is an ancillary effort to the electronic delivery of 

compliance test reports. It is the agency’s desire to transition to the electronic delivery and storage of air 

emissions compliance source test data. With this transition, it is believed this valuable information will 

be more readily available for not only compliance purposes but for a wide variety of other uses.

To the EPA’s knowledge, there exists no standardized application for electronically documenting the 

conduct of source test reports. We believe that the ERT may generate interest in the development of 

software which is superior to the ERT. Should the agency see this interest, we will develop an XML 

Schema for source test reports from the data elements used by the ERT. At this time, we do not know of 

a private enterprise willing to develop software for source test companies to use to document field 

sampling and to generate a standardized electronic output.

viii. Hard copies of reports are needed for agency review.

Comment 26: Commenter 17719 notes that stack test data reported to state agencies must be 

considered along with additional, specific information for each source’s operations. According to the 

commenter, this evaluation cannot be easily conducted with the limited data reported in the ERT. The 

commenter believes that the stack test data submitted in the ERT, taken at face value, may be misleading 

unless the context in which the testing was completed is understood. The commenter states that until the 

number and degree of source configuration and operation variables can be adequately accounted for and 

reported in one reporting tool, allowing the associated test data to be wholly considered, the commenter

relies heavily upon the submission of written stack test reports. Thus, the commenter supports the EPA’s 

preservation of the submittal of written performance testing reports to state agencies, and states that as a 

state agency, it intends to continue to request sources to submit hard copies of stack test reports to the 

state, in addition to the EPA’s collection of stack testing data via the ERT and therefore supports the 

EPA’s preservation of related requirements in 40 CFR part 63, sections 63.7 and 63.10. The commenter

requests that the EPA consider a way for states to report to the EPA via the ERT that the test is not 

approvable or was not representative.
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ix. Hard copies of reports should not be required.

Comment 27: Commenters 17718 and 17816 state that a source should not be required to make paper or 

other electronic submittals of the same data submitted through ERT, but should only be required to 

reference data previously submitted.

Response to Comments 26 - 27: The EPA disagrees that the ERT is unable to store and make available 

to users all the information that may be required to document the degree of source configuration and 

operating variables. The ERT provides the ability for the documentation of process operating 

parameters, laboratory analyses of parameters associated with the process, text descriptions of process, 

controls, monitoring methodologies and descriptions of testing issues which can be migrated into larger 

data systems if desired. In addition, the ERT is capable of storing a variety of formats of electronic 

documents including but not limited to word processing files, spreadsheet files, scanned image files, and 

ISO standard ISO 32000-1:2008 compliant Portable Document Format files. The continued delivery of 

only a paper version of source test reports will continue to limit the availability of the information 

contained in these reports to the individual which receives the report. This will also limit the information 

which is available to others within the state/local agency, EPA and those needing access to this 

information to that information that the recipient manually enters into a widely available data system. 

The EPA believes that it is much more efficient to allow electronic population of data systems and 

electronic screening of source tests requiring increased scrutiny. The EPA recognizes that states with 

delegated authority may require sources to provide complete reports in paper form. However, these 

paper reports with be in addition to the delivery of electronic reports through the EPA’s CDX. The EPA 

encourages state and local agencies to accept electronic reporting in lieu of a paper report.

x. Cross-media Electronic Reporting Rule.

Comment 28: Commenters 17730 and 17775 state that any electronic report used to satisfy federal 

reporting requirements also must meet the requirements of the Cross-Media Electronic Reporting Rule, 

codified at 40 CFR part 3, including the requirement that the document include a valid electronic 

signature, as defined in the rule. Commenter asks that the EPA explain how ERT or WebFIRE meets 

this requirement and whether ERT can satisfy other criteria the EPA deems necessary for valid 

electronic reporting, including whether (i) each electronic signature was a valid electronic signature at 

the time of signing; (ii) the electronic document cannot be altered without detection at any time after 

being signed; and (iii) each signatory had the opportunity to review in a human readable format the 

content of the electronic document that he or she was certifying to, attesting to, or agreeing to by

signing. The commenter is concerned that the responsible official is unable to prevent revision of the 

information in ERT at or after the point of submittal.

Response to Comment 28: Submission of the ERT Project Data file through EPA’s CDX will be fully

compliant with the Cross-Media Electronic Reporting Rule. This includes the signature validation of the 

authorized official of the regulated source, the addition of electronic means to verify that no changes in 

the file were made subsequent to submission and the opportunity to review in the test report in a human 

readable format. As with a wide variety of electronic submissions through the EPA’s CDX, the original 

file submitted to the agency will be maintained with proof of the original signature and proof that the file 

has not been altered. A copy of the file of record will be stored in WebFIRE and is not required to be 

CROMERR compliant although the agency does not expect to modify the file. Users requiring 

verification of the authenticity of the contents of the file will be directed to the CDX where the official 

copy of record will reside.
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xi. Paperwork Reduction Act.

Comment 29: Commenters 17730 and 17775 state that to comply with the Paperwork Reduction Act 

and its implementing regulations, the EPA must specifically identify each piece of information it seeks 

to have reported, explain how those data have practical utility, and estimate the costs of collection and

the EPA review of those data. According to the commenters, the EPA has not appropriately responded to 

these requirements in the proposal. Commenters state that if the EPA intends to require reporting of 

more than the test results already required to be reported under the applicable EPA test methods, the 

EPA must issue a supplemental proposal identifying and soliciting comment on the information it seeks 

to collect so that the regulated community and members of the public may have an opportunity to 

adequately respond to the proposed requirements.

Response to Comment 29: While the ERT may have the ability to store a wide variety of information, 

there is no information required by the ERT which is not required in this rule or in those source test 

methods used for demonstrating compliance with this rule. There may be information which are required 

by the delegated authority but are not stipulated in this rule or test method required by this rule.
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5B05 - Recordkeeping/Reporting: Other

Commenters: 17197, 17681, 17691, 17725, 17775, 17820, 17881

1. Electronic reporting.

Comment 1: Commenter 17197 notes that the December 31, 2011 date in section 63.10021(a)(16)(vii) 

appears erroneous since it specifies compliance notifications that are due long before the rule’s 3-year 

implementation and compliance deadline from final rule Federal Register publication. The commenter

also notes that the referenced (CDX) electronic data reporting capability will be available beginning 

January 1, 2012. The commenter recommends that the date references in the proposed rule be replaced 

by a time reference (i.e., 180 days, 6 months, 12 months) from final publication of the rule.

Comment 2: Commenter 17881 states that due to the lack of specificity in the data to be submitted as 

required by section 63.10021(a)(16)(vii), the regulated community will not know how to comply with 

this requirement; it needs clarification. The commenter states that the EPA database does not currently

exist, and therefore it is not possible to constructively comment on this requirement.

Response to Comments 1 - 2: The EPA believes the revisions in the final rule address the calendar date 

issues, as well as the concerns with proposed section 63.10021(a)(16)(vii).

2. Performance test notification time.

Comment 3: Commenter 17681 asks that the EPA choose 15 days or 21 days rather than the 30 days of 

notification before performance testing required in section 63.10030(d) of the proposed rule.

Comment 4: Commenter 17691 asks that the EPA require at least 60 days of notification rather than the 

30 days of notification before performance testing required in section 63.10030(d) of the proposed rule.

Comment 5: Commenters 17775 and 17820 state that the proposed requirements for notifications to 

conduct performance tests and compliance status are unclear. The commenters state that proposed 

section 63.10030(a) requires submission of all of the notifications required under the General Provisions 

of 40 CFR part 63 (specifically section 63.7(b) and section 63.9(e)), proposed Table 10 also identifies 

section 63.7(b) and section 63.9 as applicable, sections 63.7(b) and 63.9(e) require notification of “intent 

to conduct a performance test at least 60 calendar days before the performance test” is initially

scheduled to begin, but that proposed section 63.10030(d) requires submission of a “Notification of 

Intent” to conduct a performance test, “at least 30 days before the performance test is scheduled to 

begin.” The commenters state that this inconsistency should be corrected in the final rule and provide 

clarity as to whether the 30-day or 60-day notification will be required.

Response to Comments 3 - 5: The final rule requires 30-day notice of all performance tests, and 

clarifies any discrepancy with the general provisions.

3. Multiple reporting requirements.

Comment 6: Commenter 17775 expresses concern that the proposed rule contains redundant 

requirements for reporting. The commenter states that in section 63.10031 and Table 10, the EPA 

proposes to require compliance with most of the reporting requirements in the part 63 general 

provisions, including requirements for submission of “performance test results” under section 
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63.10(d)(2), “performance evaluation results” under section 63.10(e), and “excess emissions and 

continuous monitoring system performance reports” under section 63.10(e)(3). The commenter states 

that according to section 63.7(g) (applicable under proposed Table 10), performance test results must be 

submitted as part of the “notifications of compliance status” under section 63.9(h) and must include 

“analysis of samples, determination of emissions, and raw data”; under section 63.8(e)(5), performance 

evaluation results, which include results of “relative accuracy testing” and “calibration error tests” also 

must be submitted simultaneously with any performance test results(40 CFR 63.2)(applicable under 

proposed Table 10); And that “Excess emissions and continuous monitoring system performance 

reports” are submitted semi-annually, and must contain the information in section 63.10(c)(5) through 

(13), section 63.8(c)(7), and 63.8(c)(8).” The commenter states that according to proposed Table 10, 

some of the provisions in section 63.10(c) are not applicable to subpart UUUUU, and that because the 

reports are to include information on “excess emissions” “as defined in the subpart, and subpart 

UUUUU does not define “excess emissions,” these provisions are not complete. The commenter asks 

that the EPA address these inconsistencies and omissions prior to finalizing the rule. 

Commenter 17775 notes that performance test results and notifications of compliance must be sent to 

the state, the EPA Regional Office and permitting authority (if different than the state). The commenter 

states that as a result, under the part 63 general provisions alone, most EGUs already will need to 

prepare and submit three types of reports (in addition to the notification of compliance status) to both the 

EPA Regional Office and at least one state office: (1) performance test reports, (2) performance 

evaluation reports for monitoring systems, and (3) excess emissions and monitoring system deviation 

reports. The commenter states that proposed section 63.100031(h)(3) also requires a hard copy of the 

ERT reports to be sent to the Administrator, bringing the number of copies of each performance test and 

performance evaluation report submitted up to at least four.

The commenter further notes that in addition to the semi-annual “excess emissions and continuous 

monitoring system performance reports” required under section 63.10(e), EGUs would submit the 

additional information specified for a semi-annual “compliance report” described in proposed section 

63.10031 and Table 9. The commenter states that this information presumably includes the “deviation”

reports referenced in the preamble. The commenter believes that this is excessive.

Commenter 17881 states that as proposed in section 63.10030(d), there will be limited time to submit a 

test plan and notice and to receive agency approval, let alone receive and review results from previous 

test events, prior to the next test event. The commenter suggests that one test notice or report be 

submitted for all testing conducted within a semi-annual period (or some other reasonable time frame).

Response to Comment 6: The agency agrees with the commenter’s assertion that there is a potential for 

duplicative reporting. To the extent possible, the rule has been revised to eliminate reporting to both 

States and permitting authorities where the state is the permitting authority. The rule eliminates 

duplicative reports to EPA Regional Offices. The agency agrees that clarification is needed so that 

duplicate copies of the same report do not need to be submitted more than once, and the rule has been 

revised to eliminate the requirements for more than one copy of any report.

The agency agrees with the commenter regarding the unclear requirements for excess emissions and 

deviation reports, and the rule has been revised to clarify that all of these reports are excess emissions 

reports which are referenced in the General Provisions of part 63. Also, the agency is aware that the 

rule’s exceptions to the General Provisions reporting, as shown in Table 9, will reduce burden on what 

the facilities need to submit. 
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The agency is aware of and agrees with the commenter that there needs to be a clear definition of excess 

emissions; the rule contains such a definition.

Generally, providing adequate notice of and receiving approval of emissions testing are non-federal 

requirements; should an EGU owner or operator believe timing to be problematic, the rule affords the 

owner or operator the ability to choose means other than emissions testing to demonstrate compliance.

4. Section 63.10031(c)(7).

Comment 7: Commenter 17881 asks if, assuming that paragraph 63.10031(c)(7) only pertains to units 

not using CEMS, that can burn the new fuel without meeting the Hg and HCl input operating limits, as 

long as you perform a compliance test within 60 days and if the test shows compliance, whether there is 

a deviation to report.

Response to Comment 7: If you combust a new fuel, you must conduct a performance test for that fuel. 

There are no input operating limits, but you must show compliance with the applicable emission limit. 

Performance test results must be submitted, but assuming the tests show compliance, there is no 

deviation to report with respect to the emission limit.

5. Notice of Compliance.

Comment 8: Commenters 17775 and 17820 ask that the EPA clarify if some EGUs are not required to 

submit a Notice of Compliance Status or revise the section to make clear that all EGUs must submit 

such a notice, citing inconsistencies between requirements in section 63.10031(e) and section 

63.10005(a). The commenters note that proposed section 63.10031(e) requires EGUs to submit a 

“Notification of Compliance Status” according to section 63.9(h)(2)(ii), “[i]f you are required to conduct 

an initial compliance demonstration as specified in § 63.10011(a)” but that under proposed section 

63.10005(a) all EGUs “must demonstrate initial compliance with each of the applicable emission limits 

in Tables 1 or 2...” and that, section 63.9(h) on its face applies to each affected source when it becomes 

subject to a relevant standard.

Commenter 17775 states that under paragraph (3), the Notification of Compliance Status must include 

“[i]dentification of whether you plan to demonstrate compliance with each applicable emission limit 

through performance testing and fuel analysis; performance testing with operational limits (e.g., CEMS

for surrogates or CPMS); CEMS; or sorbent trap monitoring system.” The listed options do not appear 

to correspond with the rest of the proposed rule. The EPA needs to issue a proposal that clearly

articulates the various compliance demonstration options.

Commenter 17775 states that under paragraph (3), the Notification of Compliance Status must include 

“[i]dentification of whether you plan to demonstrate compliance with each applicable emission limit 

through performance testing and fuel analysis; performance testing with operational limits (e.g., CEMS

for surrogates or CPMS); CEMS; or sorbent trap monitoring system.” The listed options do not appear 

to correspond with the rest of the proposed rule. The EPA needs to issue a proposal that clearly

articulates the various compliance demonstration options.

Response to Comment 8: The language cited in the first paragraph above has been changed to “initial 

performance test,” so that, for example, the notification requirement does not apply to the work practice 

standard and performance tune-up. The language in section 63.10030(e)(3) cited in the second paragraph 

has been revised to clarify the compliance options consistent with the final rule.
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6. SSM reporting.

Comment 9: Commenter 17725 suggests that the EPA consider reporting startup, shutdown, and 

malfunction reports listed in Table 9 to subpart UUUUU of part 63 Reporting Requirements via email so 

notification can be made concurrently to any necessary state or local reporting agencies as well. 

According to the commenter, this would also allow for a document trail to be maintained and eliminate 

the unnecessary use of maintaining both paper and electronic records.

Response to Comment 9: The general provisions apply similar to other NESHAP and the specific 

applicability of the General Provisions to EGUs is addressed in Table 9 of the final rule. Notices are 

required to be delivered or mailed to the address specified. A courtesy email may be sent as an unofficial 

notification.
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5C01 - Compliance: Dates

Commenters: 15678, 16122, 16469, 16705, 16824, 16849, 16850, 16856, 16858, 17003, 17004, 17022, 

17026, 17028, 17055, 17055, 17110, 17123, 17137, 17174, 17254, 17265, 17297, 17383, 17385, 17400, 

17402, 17403, 17406, 17408, 17608, 17623, 17627, 17637, 17638, 17640, 17648, 17654, 17655, 17656, 

17675, 17677, 17681, 17689, 17696, 17697, 17701, 17703, 17705, 17707, 17711, 17714, 17715, 17716, 

17718, 17719, 17720, 17722, 17724, 17725, 17730, 17731, 17732, 17734, 17735, 17736, 17738, 17740, 

17741, 17752, 17756, 17757, 17758, 17761, 17765, 17767, 17770, 17774, 17775, 17776, 17789, 17790, 

17791, 17796, 17797, 17798, 17799, 17800, 17805, 17807, 17808, 17810, 17812, 17813, 17815, 17816, 

17817, 17818, 17819, 17820, 17821, 17824, 17829, 17834, 17837, 17840, 17841, 17842, 17843, 17844, 

17846, 17852, 17854, 17856, 17857, 17868, 17870, 17873, 17876, 17877, 17878, 17879, 17881, 17883, 

17885, 17886, 17887, 17902, 17904, 17909, 17911, 17912, 17913, 17918, 17919, 17925, 17930, 17931, 

17973, 18016, 18021, 18024, 18025, 18026, 18027, 18031, 18033, 18034, 18037, 18038, 18039, 18419, 

18421, 18422, 18422, 18424, 18425, 18426, 18428, 18430, 18433, 18434, 18437, 18438, 18439, 18440, 

18441, 18442, 18447, 18448, 18450, 18477, 18487, 18498, 18500, 18501, 18502, 18539, 18541, 18575, 

18933, 19032, 19114, 19121, 19122, 19212, 19213, 19506, 19653, 8443, 9738, 19536, 19537, 19538, 

18023

1. General comments.

Comment 1: Multiple commenters (16850, 16858, 17004, 17022, 17026, 17028, 17110, 17654, 17689, 

17715, 17724, 17740, 17797, 17820, 17821, 17868, 17909) ask that the compliance date be clearly 

stated as soon as possible, as well as guidance for utilities unable to comply with the stated timelines, to 

allow time for utilities to prepare.

Response to Comment 1: The compliance date for the final rule is set forth at 40 CFR 63.9984. New 

sources must be in compliance with the standards on the date the final rule is published in the Federal 

Register or at start-up, whichever is earlier. Existing sources must be in compliance 3 years after the 

final rule is published in the Federal Register. Three years is the maximum compliance time authorized 

under the statute. See CAA section 112(i)(3)(A). If sources are unable to comply within 3 years, the 

owner or operator may seek a 1 year extension of the compliance period from its Title V permitting 

authority if the source needs the additional time to install controls necessary to comply with the final 

rule. See CAA section 112(i)(3)(B). 

The EPA sends rules to the Federal Register once they are signed. We do not know exactly when the 

rule will be published in the Federal Register but it is likely to take a month or more. As we have stated

elsewhere, we believe utilities should already be in the process of planning for compliance with this 

regulation.

Comment 2: Multiple commenters (17174, 17265, 17648, 17654, 17681, 17689, 17740, 17774, 17796, 

17820, 17821, 17868, 17873) ask that any decisions or policies on extensions be published in a 

rulemaking.

Comment 3: Commenters 18034 and 18447 request clarification on what actions the federal 

government will take to ensure reliability. Commenter 18034 also recommends the EPA clarify any 

possible discretionary enforcement the EPA may plan to exercise for states that may receive delegation 

of the new rule.
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Commenter 18034 states that EPA makes several vague statements about steps to ensure a reliable and 

reasonably-priced supply of electricity, particularly regarding localized issues, but does not provide any 

details concerning what authority would be exercised. The commenter states that in one discussion (76 

FR 24979), the EPA indicates that the federal government will work with companies to ensure a reliable 

and reasonably priced supply of electricity, and in a separate discussion (76 FR 24979), the EPA states 

that they believe they have the ability to work with companies making good faith efforts to comply with 

the standards so that consumers in those areas are not adversely affected. According to the commenter, 

the EPA should be clear about the steps it may take and what the federal government might do to 

provide all parties the opportunity to comment on the appropriateness and legality of the actions that the 

EPA and other agencies of the federal government are considering. The commenter states that 

additionally, states that might receive delegation of this regulation should be made aware of possible 

discretionary enforcement the EPA may plan on exercising. The commenter states that rather than 

pointing to vague steps that the EPA and the federal government may take to address electrical power 

system reliability problems after they occur, the EPA should be considering the consequences of their 

actions on the electrical power system and building an adequate safety margin into their rulemaking 

efforts to ensure that the electrical power system of the country is protected.

Commenter 18447 states that EPA states in the proposal preamble that “the Federal government will 

work with companies to ensure a reliable and reasonably-priced supply of electricity.” The commenter 

asks “How does the Federal government propose to fulfill this promise?” The commenter points out that 

maintaining generation capability and output from their facility is very important not only for satisfying 

the electrical demand (load) of the City of Ames and Iowa State University, but also for providing 

voltage support and electrical stability to the interconnected electric system of central Iowa. The 

commenter further notes that the impacts on the planning reserve margins and the need for more 

resources is a function of the tight compliance timeline associated with the proposed rules. “Potential 

constraints of skilled construction labor, material shortages, financing, and escalation of compliance 

costs coupled with coordination of overlapping outages resulting in congestion expense could present 

challenges in meeting the compressed time schedule,” NERC concluded.

Response to Comments 2 - 3: Some commenters asked that EPA, by rulemaking, extend the 

compliance timeframe for this regulation. Many of these commenters wanted the certainty that including 

the compliance timeframe through rulemaking would afford. Some of these commenters suggested 

unique situations where providing the extension could be crucial. Public power facilities might need 

additional time because many of them must obtain approval from public bodies for the compliance 

activities that might require a public process that can be time consuming. Some commenters felt that 

smaller facilities would have difficulty procuring the engineering, labor and equipment needed for 

compliance. CAA section 112 specifies the dates by which affected sources must comply with this rule. 

New or reconstructed units must be in compliance immediately upon startup or the date that this rule is 

published in the Federal Register, whichever is later. Existing sources may be provided up to 3 years to 

comply with the final rule; if an existing source is unable to comply within 3 years, a permitting 

authority has the ability to grant such a source up to a 1-year extension, on a case-by-case basis, if such 

additional time is necessary for the installation of controls. 

The CAA gives the permitting authorities the discretion to use this extension authority to address a range 

of situations in which installation schedules may take more than 3 years. The EPA believes that although 

most units will be able to fully comply within 3 years, the fourth year that permitting authorities are 

allowed to grant for installation of controls is an important flexibility that will address situations where 

an extra year is necessary. That fourth year should be broadly available where a facility owner has made 
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a clear and diligent effort to install controls within the 3-year time frame but is unable to complete the 

installation. 

The EPA’s authority to provide relief from the requirements of this final rule beyond the fourth year is 

limited by the statute. If reliability issues do develop, however, the CAA provides mechanisms for 

sources to come into compliance while maintaining electric reliability.

Comment 4: Multiple commenters (17402, 17403, 17623, 17648, 17714, 17740, 17774, 17799, 17808, 

17858, 18021, 18034, 18450, 18500) ask that the EPA establish, streamline, and simplify the process of 

applying for the 1-year extension under section 112(i)(3).

Commenter 17403 suggests that a commitment to install wet or dry scrubber, fabric filter, DSI, or other 

major emissions control equipment would automatically qualify the particular unit for the extension.

Several commenters (17808, 17648, 18450) suggest that companies requesting an extension have a 

compliance plan outlining the steps and timing of the project. Commenter 17648 also suggests operating 

criteria that must be maintained during the extension, to minimize emissions and remove any economic 

incentive of deferring compliance.

Commenter 17797 asks that the EPA outline the conditions in which an additional year for compliance 

with the proposed regulations would be granted. The commenter requests that power companies be 

allowed to operate on a restricted basis without additional controls as they upgrade their facilities.

Response to Comment 4: The EPA established General Provisions applicable to CAA section 112 

standards at 40 CFR part 63, subpart A. Included in those provisions are regulations implementing the 1 

year compliance extension provision of CAA section 112(i)(3)(B). See 40 CFR 63.6(i)(4). The EPA did 

not propose to revise those regulations for EGUs in the proposed rule and we are not issuing 

amendments to those provisions in the final rule. However, EPA does not believe that it is difficult for 

sources to request an extension under the regulations and we are not aware of sources subject to other 

NESHAP having difficulty obtaining an extension. In addition, we encouraged state Title V permitting 

authorities to provide the 1 year extensions for EGUs unable to install controls within the 3-year time 

frame, and we explained the many circumstances that might prevent a source from being able to comply

within 3 years. We believe that sources should make themselves familiar with the regulations and 

contract the state permitting authority as early as possible if the source determines that it will need a 1 

year extension.

Comment 5: Multiple commenters (17403, 17623, 17714, 17758, 17774, 17799, 17868) ask that the 

EPA develop procedures and criteria related to the Presidential exemption under section 112(i)(4). 

Multiple commenters (17758, 17820, 17868, and 18539) ask that the utility demonstrate good faith 

progress toward compliance.

Response to Comment 5: The EPA is not authorized to implement the Presidential exemption provision 

in CAA section 112(i)(4). That provision authorizes the President to provide 2-year renewable extension 

for sources to comply with the final standards if he determines that the technology to comply with the 

rule is not available and the extension is in the national security interest of the U.S. The availability of 

technology is a separate determination from that regarding the ability of all sources to install such 

technology within the timeframes authorized by the CAA to comply. As discussed in the preamble and 

TSD, the EPA has determined that the technology is indeed available and has been installed and 

operated successfully by many sources. As the EPA has stated elsewhere in this document, it will work 
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with source owners and operators and with permitting authorities in the event that a particular source has 

difficulty meeting the CAA compliance deadline. 

Comment 6: Commenter 17808 suggests that the EPA require utilities to submit a notice concerning 

which EGUs will be retrofitted or retired – within 1 year of the effective date.

Comment 7: Several commenters (17701, 17791, 18034) encourage the EPA to coordinate with FERC, 

DOE, and state and federal regulators to maintain system reliability. Commenters 17701 and 17791 

suggest the EPA develop a process that will require all generators to provide notice to FERC, system 

operators, and state regulators of expected effects of the EGU MACT and other EPA regulations. The 

commenters believe that such a process would provide an opportunity for meaningful assessment and 

response to reliability issues. Commenter 18034 recommends the EPA work closely with the regional 

agencies, such as (PUCT and ERCOT) that are responsible for monitoring and assuring the reliability of 

the electrical power system to ascertain the impact of the new rules on Texas’ and the nation’s electrical 

power system.

Commenter 17824 urged the EPA to adopt more flexible standards and reasonable compliance timelines, 

which will achieve the Agency’s goals while ensuring affordable utility bills, stable jobs and reliable 

power.

Response to Comments 6 - 7: The EPA is not requiring that sources provide notice within 1 year of the 

effective date of the rule, as to which units will retire and which units will be retrofitted to comply with 

the final rule. However, the Agency does encourage facility owners to notify the permitting agencies, the 

transmissions operators, and state regulatory agencies as early as possible of their intention to retrofit or 

close. Early notification will help to ensure that permitting is orderly and timely for plants that are 

retrofitting. It would also provide transmissions operators an early heads up so that they can plan for 

transmission upgrades to avoid reliability problems. It would also allow market solutions including new 

generation and demand side management solutions to come into the market and ensure grid stability. 

[Placeholder for additional response.]

Comment 8: Commenter 17648 suggests a process based on early notification of retirements.

Comment 9: Commenter 18441 asserts that the 3-year time period is insufficient for making necessary

transmission upgrades. They argue that although certain local reliability upgrades such as those that 

entail upgrades to existing substations can occur in an expeditious manner, other kinds of transmission 

upgrades may involve far more complex projects with extended delays. The commenter provides the 

following three examples to support their statements:

 The need for the Susquehanna-Roseland line was first identified by PJM and approved by the 

Board as part of 2007 RTEPP and was anticipated to be in service for 6/1/2012 to avoid 

identified reliability criteria violations. However, they note that delays due to National Park 

Service review have delayed the in-service date of this line to 2015 at the earliest.

 The retirement by Exelon Generation of the Cromby Unit 2 and Eddystone Unit 2 requires 18 

separate transmission system enhancements to address the identified thermal, voltage and short 

circuit violations. The commenter notes that even though Cromby and Eddystone provided 

notice of deactivation in December, 2009, due to the need for such transmission enhancements 

the units are not going to actually shut down until May, 2012.
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 A deactivation request for the Benning Road and Buzzard Point generating units (totaling 790 

MW, located in the Potomac Edison Power Company’s zone in Washington, D.C.) was 

submitted with PJM in February, 2007. Transmission reinforcements necessary to allow these 

generating units to retire, which include new circuits, upgrades to existing circuits, new 

transformers, new capacitors and upgrades to existing terminal equipment, are not expected to be 

in service until more than five years after such notice in May, 2012.

The commenter states that the analysis supporting the Proposed Rule has underestimated the risks to 

reliability of electric supply in light of the hard deadlines imposed pursuant to Clean Air Act § 112. 

Moreover, as EPA indicated, unit owners must only give 90 day notice prior to shutdown in the PJM 

region, 76 FR 25056. According to the commenter, the requirement to be in compliance three years 

following publication in the federal register, 40 CFR §63.9984, may result in the shutdown of certain 

units that are critical to the reliability of electric supply on a timeline that is faster than the time 

necessary to replace the power or upgrade transmission.

Comment 10: Multiple commenters (17716, 17701, 17791, 17804, 17813, 18034, 17868, 17911, 17913, 

17919, 18441, 19114, 18034, 18441, 18500, 18538) express concern that the EGU MACT may cause 

local transmission problems due to early retirement of EGUs. These commenters argue that the EPA 

should have assessed reliability at much more local level rather than relying only on national studies of 

reliability. Commenter 18034 notes that ERCOT anticipates localized impacts on transmission reliability

in the Houston and Dallas-Fort Worth areas as a result of the EGU MACT and other EPA regulations. 

Commenter 17701 notes that small older plants that would likely retire as a result of the EGU MACT

and other environmental regulations may need to stay running for a longer period of time because they

provide service to an area that cannot otherwise get reliable power (a load pocket) or they provide a key

reliability service (e.g., black-start facilities). Commenter 17919 believes that those areas most reliant 

upon coal-fired capacity are likely to face profound price, supply, and reliability concerns and that in 

the event of extraordinary events, only the additional peak-load capacity supplied by coal-fired facilities 

are likely to provide the resilience necessary to address potential weather-related blackouts or even 

cyber-security threats to critical infrastructure. Commenter 17731 believes that reduced grid reliability

will be exacerbated by heavier reliance on non-final (i.e., interruptible) transmission and gas 

transportation contracts that can result in curtailed deliveries of energy during peak periods when the 

energy is most needed.

Comment 11: Commenter 17716 considers the EPA to be downplaying transmission problems related 

to compliance. The commenter notes that transmission problems can arise because current paths are not 

used after plant retirement, or new/expanded transmission paths are needed for purchased power to 

replace that from retired plants. 

Comment 12: Commenters 17868 and 18500 mention recent blackouts in the ERCOT region of Texas 

as an example of localized reliability problems resulting from too many units out of service at one time 

during a cold weather event. Commenter 17868 suggests the EPA review the Texas PUC report on the 

February 2-3, 2011 outage in Texas to understand the implications of reduced electricity supply. The 

commenters believe this event is an important reminder that having generation offline for upgrades even 

during a low load season has its risks. 

Comment 13: Several commenters (17912, 18034, 18441, 18538, 18023) believe a more detailed study

of the impacts of the EGU MACT on reliability of the electric network should be undertaken by the 

EPA. These commenters identify several areas in which they believe the EPA’s analysis of reliability

impacts is incomplete or inaccurate.
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1. Commenter 17912 believes the EPA’s assessment of the impact of the rule on reliability failed to 

take into account differences between IPPs and regulated utilities. The commenter notes that IPPs do 

not have a regulated utility’s ability to shift load to other units because many IPP facilities are 

subject to regional reliability mandates that require firing with oil.

2. Commenter 18538 believes the EPA has overstated the ability of energy efficiency and demand 

response programs to mitigate the reliability impacts of the various EGU rules.

3. Commenter 18538 believes the EPA has understated the reliability impacts of the rule by using low 

target reserve margins. In the ERCOT region, the commenter argues that the EPA uses a target 

reserve margin of 12.5% instead of the 13.75% used by ERCOT for planning purposes. The 

commenter believes the EPA’s target margin would likely result in greater incidence of system 

outages than is considered acceptable in the electric industry. According to the commenter, ERCOT

adopted its 13.75% minimum reserve margin based on the results of a loss-of-load study, which is a 

probabilistic assessment of the likelihood of a system outage event. The commenter states that the 

study takes into account components of system volatility, including the forced outage and derating of 

generating facilities, load forecast uncertainties resulting from weather, and the intermittent nature of 

wind generation and that consistent with industry practice, ERCOT sets its minimum reserve margin 

at a level such that the expected frequency of a loss-of-load event is no more than 1 day in 10 years. 

According to the commenter, the EPA’s target reserve margin of 12.5% would increase the 

likelihood of a loss of load event from 1 day in 10 years to approximately 2.5 days in 10 years. By

using a target reserve margin below that required by ERCOT, the commenter argues that the EPA 

has understated the impact of the various rules on electric reliability in the ERCOT region.

4. Commenter 18034 notes that the EPA’s modeling assumes unlimited transmission capability within 

a model region (e.g., power generated anywhere in ERCOT can be transmitted anywhere in ERCOT) 

and states that this is not correct. The commenter notes that electrical power cannot be transmitted in 

an unlimited manner from anywhere to anywhere within a region as large as ERCOT and that 

fundamental principles of electrical transmission, such as thermal restrictions on transmission lines 

and voltage stability, restrict the distance that power can be transmitted over power lines within a 

region.

5. Commenter 18034 questions whether the EPA’s analysis accounted for units classified as 

Reliability-Must-Run (RMR) facilities that are necessary to ensure grid reliability in specific local 

areas.

6. Commenter 18034 notes that the 25% surplus reserve margin that the EPA cites as an indication that 

projected retirements will not affect reliability is a national average and is not consistent with 

ERCOT’s local projections for Texas. The most recent information from ERCOT, they argue, 

indicates that the ERCOT region currently has 17.5% of surplus reserve (Report on the Capacity, 

Demand, and Reserves in the ERCOT Region, May 2011); however, ERCOT expects this surplus 

reserve will drop to 11.1% by 2014 even without impacts of the EPA’s regulatory initiatives, which 

is less than ERCOT’s target reserve of 13.75%. 

7. Commenter 18034 believes the EPA has also over-estimated the generation potential of wind energy. 

They note that ERCOT derates wind capacity using an 8.7% capacity factor because wind generation 

is unpredictable and unreliable as a generation source. The EPA appears to be assuming that wind 

generation is capable of producing at 100% of the installed capacity, which is not correct and results 

in the EPA over-estimating wind capacity in ERCOT by 9,400 MW. 

8. Commenter 18034 states that the EPA included retired and mothballed units in their capacity

calculations. The commenter notes that the actual total generation resource capacity for ERCOT is 

73,175 MW, based on the May 2011 ERCOT report, which is substantially less than the EPA’s 

estimated 90,400 MW for the base case. A recent ERCOT study, entitled Review of the Potential 

Impacts of Proposed Environmental Regulations on the ERCOT System, issued on May 11, 2011, the 
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commenter asserts, finds that without additional replacement generation the reserve margins could 

be reduced to less than 2% by 2015 as a direct result of the EPA’s regulatory initiatives on EGUs.

9. Commenter 18441 argues that the EPA analysis erroneously assumes (1) wholesale power markets 

mirror least-cost planning models; reliability is related to only movements of power between large 

geographic areas; and (2) that there are no transmission or deliverability constraints within those 

areas. These errors, the commenter argues, result in conclusions that are not correct for RTOs. The 

commenter notes that retirement and new entry decisions are made in a decentralized manner based 

on price signals that are provided by wholesale markets that signal the financial profitability of 

existing and new entry resources. The commenter states that in contrast, the IPM employed by the 

EPA to model reliability impacts does not reflect the manner in which decisions are made in the 

wholesale market. According to the commenter, the objective of the IPM is to minimize the systemwide, region-wide, or nation-wide cost of achieving resource adequacy and maintaining its 

representation of transmission reliability subject to the environmental constraints imposed on 

generating units by the proposed rule. The commenter states that in sharp contrast to market 

dynamics, in the IPM modeling framework employed by the EPA, the retirement and new entry

decisions are centralized; the decisions, are not based on market price signals and do not depend 

upon unit profitability or returns on investment. Rather, according to the commenter, the decisions 

are based on cost and perfect foresight of future market conditions. As a consequence, the 

commenter believes the IPM model may reflect retirement and new entry decisions that differ 

significantly from the actual market-based retirement and new entry decisions. 

10. Commenter 18441 notes that the IPM framework does not account for Demand Response and 

Energy Efficiency resources as new capacity entry or account for the effect these resources may

have on market prices that drive retirement and new entry decisions. The commenter notes that 

wholesale energy and capacity markets in PJM allow for the participation of Demand Response and 

Energy Efficiency. According to the commenter, since these resources are generally lower cost 

capacity alternatives than traditional generation resources, the commenter argues that they can have 

an effect on market prices and ultimately on the retirement and new entry decisions of generation 

resources when considered in conjunction with the costs imposed by the EGU MACT. The 

commenter believes the IPM framework is likely missing possible generation retirements that may

be driven by the interaction of the EGU MACT with these potentially lower cost capacity resources. 

The commenter is concerned that the EPA’s analysis understates the volume of system security and 

local reliability issues faced by RTOs and other transmission operators.

11. Commenter 18447 states that the IPM modeling of regions misses large 500 kilovolt (“kV”) reactive 

transfer interfaces that reside within some of the regions. The commenter also notes that some of the

regions span across multiple RTOs and each RTO region undertakes its own security constrained 

generation dispatch. According to the commenter, the manner in which power is moved from one 

region to another in IPM does not account for parallel path or loop flows that occur across multiple 

regions and the international border between the U.S. and Canada that take careful inter-regional 

coordination between multiple RTOs and transmission providers to solve. The commenter notes that 

the recent Independent Market Monitor (“IMM”) reports for PJM states that the amount of 

generation available to be redispatched to alleviate localized constraints to maintain transmission 

security is small, sometimes only one or two generating units have the ability to relieve such 

localized constraints. The commenter argues that the deactivation or retirement of some generation 

would take away potential re-dispatch solutions and therefore likely trigger the need for transmission 

upgrades to prevent transmission reliability criteria violations. The commenter notes that more than 

half of all the pending deactivations require transmission upgrades to allow the unit to retire without 

a violation of transmission reliability criteria.

12. Commenter 18023 believes that the EPA’s analysis is overly simplistic and incorrectly assumes that 

demand response, energy efficiency, and rapid and wide-spread deployment of renewable energy
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resources will sufficiently replace lost coal-fired generation capacity both from a resource adequacy

and bulk power system operations standpoint. The commenter argues that renewable generation 

resources and demand response do not provide inertia, frequency response, or voltage support. 

13. Commenter 18023 believes that the EPA has underestimated the impact that a decrease in available 

generating resources will have on the ability of authorities to comply with the reliability standards. 

The commenter believes the EPA’s failure to take into account mandatory BAL and VAR reliability 

standards (among others) in its discussion of reliability impacts of the Utility MACT is a significant 

error. The commenter argues that violations of the reliability standards have a wide variety of 

negative consequences for the electric system, including load shedding and black-outs. The 

commenter notes several potential operating reliability impacts of the Utility MACT rulemaking:

 Contingency Reserves: requires resources sufficient to address system disturbances; 50 % must 

be “spinning reserves” (i.e., reserve capacity at units already on-line);

 Load-Following Reserves: requires resources sufficient to respond to load changes within an 

hour;

 Regulating Reserves: requires resources sufficient to control system performance by responding 

within 4-6 seconds; all regulating reserve must be “spinning”;

 Frequency Control: requires sufficient resources capable of automatically and instantaneously 

responding to changes in frequency caused by constant tracking and matching of power demand 

and power supply to prevent imbalances;

 Voltage support: needed to enable the transmission of electricity over distance. Grid operators 

must ensure there is enough reactive power at the right locations to support the electricity that is 

being delivered on the system; and

 In addition to all NERC standards developed and implemented by NERC/SERC, utilities must 

also satisfy planning reserve margin requirements established by NERC/SERC, as well as 

resource adequacy expectations established by state public utility regulators.

Comment 14: Commenter 17731 questions the EPA’s view that utilities can easily retire and replace 

units that are unable to comply with the new emission limits. The commenter considers the option of 

replacing older units with more efficient units to be risky because they utility may spend the time and 

money to build new coal-fired units only to find out that the units cannot comply with the stringent new 

unit emission limits.

Response to Comments 8-14: The EPA agrees with these commenters that real threats to reliability

from these rules are unlikely but agrees as well that a process involving early notification can promote 

confidence in reliability and as well as promote the kind of planning by companies, regulatory agencies, 

grid operators, and reliability organizations that can ensure a smooth transition to cleaner electric 

generating fleet.

The industry has adequate resources to install the necessary controls and develop the new capacity that 

may be required within the compliance time provided for in the final rule.3EPA believes that the 

flexibility of permitting authorities to allow a fourth year for compliance should be available in a broad 

range of situations (as discussed below), and that this flexibility addresses many of the concerns that 

have been raised. Furthermore as indicated below, in the event that an isolated, localized concern were 

to emerge that could not be addressed solely through the 1-year extension under CAA section 112(i)(3), 

the CAA provides flexibilities to bring sources into compliance while maintaining reliability. 

 

3 As stated above, EPA has provided the maximum compliance time authorized under CAA section 

112(i)(3)(A).
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Although there are a significant number of controls that need to be installed across the industry, with 

proper planning, we believe that the compliance schedule established by the CAA can be met. Many 

companies have begun to do the detailed analysis and engineering and are ahead of others in their 

compliance strategy. There are already tools in place (such as integrated resource planning, and in some 

cases, forward auctions for future generating capacity) that ensure that companies adequately plan for, 

and markets are responsive to, future requirements such as this final rule. 

The EPA agrees with these commenters that companies that intend to retire EGUs should formally 

notify their RTO (or comparable planning coordinator in the case of non-RTO regions), state regulatory

agencies, and regional reliability entities as soon as possible that they will retire. As we said before, in 

most places a closing plant will not be a cause for concern. To the extent there is concern, however, 

early notification will provide an opportunity for transmission planners, market participants, and state 

authorities to develop solutions to avoid a reliability problem. In RTOs with forward capacity markets, 

owner/operators that do not bid generating capacity that they plan to close will provide an advance 

signal to market participants to take action to assure adequate future capacity. In all regions, early and 

public notification will allow market participants, planning coordinators and state authorities, as 

appropriate and in a timely fashion, to bring new generation on line, put demand side resources in place, 

and/or complete any transmission upgrades needed to circumvent a potential issue. Most RTOs only 

require 45 to 120 days notification of closure. The 5 RTOs suggested that such notification should be 

made no later than 12 months after this regulation is final in order to allow a smooth transitioning to 

action to avoid a reliability problem. The EPA strongly encourages early notification, and believes that 

responsible owner/operators should and will do the early planning for compliance and provide early 

notification of their compliance plans, especially where such plans include retiring one or more units.

On the supply side, there are a range of options including the development of more centralized power 

resources (either base-load or peaking) and/or the development of cogeneration or distributed 

generation. Even with the current large reserve margins, there are companies ready to implement supply

side projects quickly. For instance, in the PJM region, there are over 11,600 MW of capacity that have 

completed feasibility and impact studies and could be on-line by the third quarter of 2014.4The EPA 

notes, as well, that in the 3 years from 2001 to 2003, industry brought over 160 GW of generation on 

line.5

Demand side options include energy efficiency as well as demand response programs. These types of 

resources can also be developed very quickly. In 2006, PJM had less than 2,000 MWs of capacity in 

demand side resources. Within 4 years this capacity nearly quadrupled to almost 8,000 MW of capacity.

6

In addition to helping address reliability concerns, reducing demand through mechanisms such as energy

efficiency and demand side management practices has many other benefits. It can reduce the cost of 

compliance and has collateral air quality benefits by reducing emissions in periods where there are peak 

air quality concerns.

With regard to transmission, recent experience also shows that, in many cases, transmission upgrades to 

address reliability issues from plant closures can be implemented in less than 3 years. For instance, when 

 

4

Paul M Sotkiewicz, PJM Interconnection, Presentation at the Bipartisan Policy Commission Workshop 

Series on Environmental Regulation and Electric System Reliability, Workshop 3: Local, State, 

Regional and Federal Solutions, January 19, 2011, Washington DC,

http://www.bipartisanpolicy.org/sites/default/files/Paul%20Sotkiewicz-%20Panel%202_0.pdf, slide 6

5

{need citation}

6 BPC slides cited above – slide 5
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Exelon notified PJM of its intention to retire four units,7it was determined that transmission upgrades 

necessary to allow retirement of two units could be made within 6 months of notification, transmission 

upgrades for the third unit would require slightly over 1 year and transmission upgrades to allow the 

fourth unit to retire could be made in approximately 18 months.8

The CAA allows CAA Title V permitting authorities the discretion to grant extensions to the compliance 

time of up to one year if needed for installation of controls. See CAA section 112(i)(3)(B)). If an 

existing source is unable, despite best efforts, to comply within 3 years, a permitting authority has the 

discretion to grant such a source up to a 1-year extension, on a case-by-case basis, if such additional 

time is warranted. This provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(i). We believe that the 

permitting authorities have the discretion to use this extension authority to address a range of situations 

in which installation schedules may take more than 3 years. 

The EPA does not believe there will be a significant impact on oil facilities as a result of the final rule. 

The rule contains “limited use” provisions that will mitigate the impacts on many oil-fired facilities used 

for peaking and/or reliability purposes. For those units that are expected to continue firing residual oil, 

many already have existing air pollution control technologies (e.g., electrostatic precipitators) necessary

to achieve the emission standards and the remaining units that are not capable of converting to another 

fuel (e.g., subject to natural gas curtailment) are expected to install cost-effective air pollution control 

technologies. The EPA used AEO demand forecasts as the baseline for electricity demand. The EPA 

does not believe these forecasts overstate the impact of energy efficiency. The EPA used the official 

target reserve margins that were available at the time of the analysis of the final rule in the 2010 Long 

Term Assessment. In the case of ERCOT, the reserve margin was 12.5% percent in that assessment, but 

was updated after the margins were provided to NERC for the 2010 Long Term Assessment. The EPA’s 

IPM modeling of MATS shows that ERCOT would continue to meet its target reserve margin even 

taking into account its recently revised target of 13.75 percent. See TSD on Resource Adequacy for EPA 

resource adequacy results. The EPA believes the regional impact evaluation that it conducted was 

correct in focusing resource evaluation at the regional level, and treating local reliability issues within 

regions as best handled by standard reliability management practices as the rule is implemented. 

Processes for addressing local reliability issues have been made more flexible in response to comments 

received on the proposed rule and are discussed in the preamble. See also responses elsewhere on local 

reliability issues. As the commenter notes, ERCOT reserve margins are above their target margin in 

2012. The EPA agrees with the commenter’s recognition that ERCOT’s projected capacity shortage 

shown in that report is not primarily driven by EPA regulations. The EPA believes that there will be 

sufficient time to add more capacity where needed in ERCOT by 2015; EPA has also included 

additional flexibility on timing of compliance in the final rule. The EPA’s IPM modeling does not 

purport to capture all potential local reliability variables affecting any specific unit. The final rule 

provides greater flexibility when additional time is needed to address transmission issues arising from 

reliability violations related to plant retirements. As noted earlier, the EPA modeled demand based on 

the AEO, which includes an estimated level of demand response. The reliability contribution from 

renewable resources is a relevant issue only for wind resources. The reliability capacity contribution 

from wind resources in the analysis of the rule was based on estimates from the National Renewable 

Energy Laboratory (NREL) and was incorporated in the resource adequacy assessment (See IPM 

 

7

http://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.aspx?k=eddystone

8 Cromby Units 1 and 2 and Eddystone Units 1 and 2 – Deactivation Study, Updated September 7, 2010 

- http://policyintegrity.org/documents/20100907-cromby-and-eddystone-retirement-study-postingupdate.pdf
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documentation of wind resource and TSD on Resource Adequacy.) Local reliability issues can be 

addressed during implementation of MATS.

Comment 15: Commenter 17725 asks that the compliance date align with the Power Year used by 

RTOs.

Response to Comment 15: The compliance date for this rule is 3 years from the date of publication in 

the Federal Register. That is the maximum amount of time permissible under CAA section 112(i)(3)(B)

which EPA felt appropriate given the significant work that some plants will need to undertake to come 

into compliance.

Comment 16: Commenter 17821 asks that the EPA develop guidance on applicability of section 

112(i)(6) in the final rulemaking.

Response to Comment 16: There are regulatory provisions in 40 C.F.R. section 63.6 (the general 

provisions) that govern the use of CAA section 112(i)(6).

Comment 17: Commenter (17887) supports the provision in the NARUC resolution that the rule should 

allow sufficient time for generators to evaluate and implement the best compliance options and integrate 

these options into their systems in order to ensure reliability of operations.

Response to Comment 17: The EPA has consistently said that early planning for compliance is very 

important and we have urged utilities to take proactive steps in coordination with relevant planning and 

regulatory authorities. The industry has adequate resources to install the necessary controls and develop 

the new capacity that may be required within the compliance time provided for in the final rule.9

Although there are a significant number of controls that need to be installed across the industry, with 

proper planning, we believe that the compliance schedule established by the CAA can be met. Many 

companies have begun to do the detailed analysis and engineering and are ahead of others in their 

compliance strategy. There are already tools in place (such as integrated resource planning, and in some 

cases, forward auctions for future generating capacity) that ensure that companies adequately plan for, 

and markets are responsive to, future requirements such as this final rule.

Commenter 18: Commenter 17701 representing the National Association of Regulatory Utility

Commissioners (NARUC) states that although there are logistical issues that may impact system 

reliability given the Proposed Rule’s compliance timeframe such as: coordination of offline time for the 

installation of pollution controls on several plants in the same region; repowering or replacing a plant 

with a natural gas generator relies on access to natural gas pipelines; and transmission solutions 

generally take longer to plan, site, build and interconnect than the proposed rule’s 3- to 4-year 

compliance timeframe, the association’s members will work with their utilities to ensure that customers 

maintain access to safe and reliable power while generating plants install controls or while plants are 

retired and replaced or repowered.

Response to Comment 18: The EPA appreciates this comment and agrees that the state regulators have 

an important role to play in assuring that the transition to a cleaner electric generating fleet that this rule 

will bring about occurs as smoothly as possible so that reliable power is maintained.

 

9 As stated above, EPA has provided the maximum compliance time authorized under CAA section 

112(i)(3)(A).
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Comment 19: Commenter 17701 advocates flexibility in the implementation of this and other rules to 

avoid compromising electric system reliability while minimizing cost impacts to consumers. According 

to the commenter, flexibility will enable the EPA to accommodate the highly localized and regional 

nature of electricity services and avoid reliability issues.

Comment 20: Commenters 17701 and 17791 suggest the EPA allow utilities (1) to coordinate the 

closure and/or retrofitting of existing electric generating units in an orderly manner that will ensure the 

continued supply of electricity; (2) allow regulatory options for units that are necessary for grid 

reliability that commit to retire or repower; (3) allow an EPA-directed phasing-in of the regulation; and 

(4) establish interim progress standards that ensure generation units meet the EPA regulations in an 

orderly, cost-effective manner.

Comment 21: Several commenters (17701, 17761, 17791, 17930, 19506, 19114) advocate flexibility in 

the implementation of the EGU MACT and other rules to avoid compromising the reliability of the 

electric system. These commenters believe the EPA should incorporate greater flexibility into the EGU

MACT to ensure adverse impacts on the reliability of the electricity supply are avoided.

Response to Comments 19 - 21: There are several flexibilities in final rule that EPA wills help to avoid 

reliability issues. The regulation is applied facility wide so that facilities are able to average across units. 

Facilities also are able to average over time. They do not have to operate above the standard all the time 

but rather can meet the standard on a 30 day rolling average. There are alternative standard formats so 

that a plant can choose, for example, to meet a metals standard or a PM standard on either an input or 

output based level. In addition EPA is encouraging that permitting agencies be generous in offering the 

fourth year for installation of controls. 

Comment 22: Commenter 17701 encourages the EPA to work with state and federal environmental 

regulators to examine all possible options to maintain system reliability and achieve health and 

environmental benefits while also ensuring reliability, minimizing capital costs to utilities, rate increases 

to consumers, and other avoidable economic impacts. The commenter offers the following suggestions:

Allow utilities to coordinate the closure and/or retrofitting of existing electric generating units in 

an orderly manner that will ensure the continued supply of electricity and that will allow power 

generators to upgrade their facilities in the most cost effective way, while at the same time 

achieving attainable efficiency gains and environmental compliance; and 

Allow regulatory options for units that are necessary for grid reliability that commit to retire or 

repower; and

Allow an EPA-directed phasing-in of the regulation requirements; and

Establish interim progress standards that ensure generation units meet EPA regulations in an 

orderly, cost-effective manner.

Commenter 23: Commenter 18441 requests that the EPA state in the preamble to the final rule that the 

permitting authority should explicitly authorize or endorse the extensions to the 3 year compliance 

deadline for units which the RTO or relevant Reliability Coordinator indicates are “Reliability Critical 

Units.” The commenter also believes that Reliability Critical Units that have timely announced their 

deactivation should be eligible for a 1-year extension of the compliance obligation because deactivating 

a generating unit is simply another control option to comply with the final rule if the affected generating 
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unit owner believes this is the least-cost compliance option, and is effectively no different from a 

generating unit choosing to install retrofits to meet the emissions rate standards that cannot get its 

retrofits in service by the January 1, 2015, compliance deadline. The commenter suggests that units 

choosing deactivation as a compliance option would only be granted an exemption if under the RTO’s

independent analysis, they are deemed critical to system reliability and are required to stay in service for 

a defined period until transmission or replacement resource solutions could be placed into service.

Response to Comments 22 - 23: The EPA expects that the fourth year for compliance will be broadly

available to these plants that need it for the installation of controls or on site replacement capacity or, 

where reliability could be at risk, for transmission upgrades and construction of replacement capacity off 

site. This will allow facilities to plan for a well-coordinated compliance period.

Comment 24: Commenter 17868 desires that EPA take into account the numerous contingencies that 

could cause concern for reliability during the compliance period including multiple retirements, multiple 

outages, lack of generator response during a cold weather event, and revisions to the North American 

Electric Reliability Corporation’s (NERC) Critical Infrastructure Protection (CIP) Standards. 

Response to Comment 24: The EPA has indeed taken into account the wide array of contingencies that 

will prevent a facility from either retrofitting or closing within the compliance time frame. The EPA 

maintain that most, if not all, units will be able to comply with the requirements of this rule within 3 

years. The EPA also believes that making it clear that permitting authorities have the authority to grant a 

1-year compliance extension where necessary, in the range of situations described above, addresses 

many of the other concerns that commenters have raised. The EPA believes that the number of cases in 

which a unit is reliability critical and in which it is not possible to either install controls on the unit or 

mitigate the reliability issue through construction of new generation, transmission upgrades, or demandside measures, within 4 years, is likely to be very small or nonexistent. None-the-less, where such cases 

appear EPA has authorities to manage these situations so that the maximum environmental protection 

can be achieved while facilities continue to come into compliance.

Comment 25: Commenter 17919 claims that analyses that have been submitted to the EPA showing 

that the rule does not cause a problem for electricity reliability, are “highly suspect” in that they are 

“largely from economic competitors with a vested economic interest in decreasing the economic 

viability of coal-fired generation and thereby increasing the clearing price of energy for consumers –

that dispute adverse reliability claims from the proposed rule.”

This commenter points instead to another analysis from the Federal Energy Regulatory estimating a 

large amount of coal-fired capacity ‘likely’ and “very likely” to retire. The commenter states that the 

EPA should utilize the flexibility afforded under the CAA to ease the compliance schedule set out by the 

proposed rule.

Response to Comment 25: The EPA makes no judgments about the motives of any of the commenters. 

The Federal Energy Regulatory Commission (FERC) report relied on here was a staff draft that was 

done before EPA had even proposed its regulations. It made assumptions about the stringency of the 

regulations that went well beyond what EPA actually proposed and final led. As such it has very little 

bearing on this rulemaking. Furthermore the FERC Chairman stated clearly the study the commenter is 

referring to was a “back-of-the envelope first assessment of the amount and location of potential 

generator retirements, that informal assessment cannot be relied upon to determine specific effects on 

system reliability. Therefore, it is inadequate to use as a basis for decision making.”
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None-the-less as stated elsewhere in this document, the CAA provides flexibility to address any 

reliability problems should any arise.

2. Current compliance period should be shorter.

Comment 26: Several commenters (15678, 16122, and 17846) ask the EPA to ensure that compliance 

occurs as soon as possible. Commenters 16122 and 17846 make note of the EPA’s Trust Responsibility.

Comment 27: Commenter 17819 asserts that the 3 or 4 year implementation schedule for Hg control is 

not as expeditious as practicable. According to the commenter:

1. U.S. EPA asserted in 2000 that is appropriate and necessary to establish Hg emission standards for 

coal-fired EGUs. 65 FR 79825 (December 20, 2000).

2. By 2003, the DOE concluded ACI is an effective Hg control technology for coal-fired EGUs that 

requires minimal capital costs, is easily retrofitted and can achieve 90 percent removal efficiencies. See 

Durham, Michael et al. Full-Scale Evaluation of Mercury Control By Injecting Activated 

Carbon Upstream of ESPS. 2003. available at: 

www.netl.doe.gov/technologies/coalpower/ewr/mercury/control-tech/pubs/ A5-B2.pdf.

3. The DOE’s findings about the effectiveness of ACl Hg control systems are consistent with the use of 

ACl in other industry sectors since the mid-1990’s to meet MACT mandates. See 62 FR 48348 

(September 15, 1997).

4. Coal-fired EGUs in Illinois and several other states are already subject to state-specific Hg emission 

standards and have demonstrated it is already practicable to retrofit effective Hg controls. See “State 

Local Mercury Toxics Program for Utilities” from the NACAA, available at \Vww.4cleanair.org; see 

also 35 Ill. Admin. Code § 225.230.

5. For its part, U.S. EPA’s present regulatory proposal explicitly acknowledges that all Hg control 

options take significantly less than 3 years to install. Proposed Rule at 441-447.

6. U.S. EPA also estimates that the implementation of these controls will reduce cumulative Hg 

emissions from 29 tpy to 6 tpy. Id at 26 and 153. Each year that regulatory implementation is delayed 

will result in up to 23 tons of unnecessary emissions of Hg, a persistent, bioaccumulative and toxic 

substance.

7. ln light of the ready availability of Hg controls for coal-fired EGUs and the well established threat to 

human health and the environment posed by Hg emissions, U.S. EPA’s compliance timeline is not as 

expeditious as practicable.

8. To comply with the CAA mandate for emission standards to be implemented as expeditiously as 

practicable, two commenters assert U.S. EPA must establish a more immediate deadline for 

implementation of Hg emission standards for coal-fired EGUs.

9. Under any circumstances, it is contrary to the plain language of the CAA and against the manifest 

weight of evidence to allow a 4-year compliance schedule for any coal-fired EGU.
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On the other hand, commenter 17675 requests a 5-year compliance period for the Hg limits only. The 

commenter notes that this would be similar to the BACT status allowed under 40 CFR 63.6(i)(2)(ii).

Response to Comments 26 - 27: Several commenters suggested that 3 years was too long for a 

compliance period given the delays in promulgating this regulation, and urged EPA to require 

compliance in a shorter timeframe. Some of these commenters said that, consistent with EPA’s Trust 

Responsibility the compliance period should be as short as possible. The EPA understands very well the 

importance of bringing facilities into compliance as soon as possible so that all Americans can realize 

the public health benefits of this rule without further delay. We agree that many plants will need fewer 

than 3 years to come into compliance and some already are in compliance. For other plants, coming into 

compliance will require substantial engineering and construction. The EPA finalized the 3-year 

compliance period for EGUs given the sheer number of sources that are in the category and that may

have to install controls to comply with the final rule.

3. Current compliance dates are sufficient.

Comment 28: Multiple commenters (19536, 19537, 19538, 17110, 17402, 17648, 17808, 17854, 17870, 

17973, 18025, 18027, 18421, 18425, 18438, 18439, 18450, 18487, 18501, 18541) ask that no additional 

time be granted for compliance.

Multiple commenters (19536, 19537, 19538, 16850, 17408, 17421, 17648) reference an April 2011 

report entitled “Assessment of Technology Options Available to Achieve Reductions of Hazardous Air 

Pollutants” where URS Corporation concludes not only that technology is readily available, but that the 

technology can typically be installed in less than 2 years.

Commenter 18421 states that based on that report, no additional controls would need to be installed in 

many cases and any coal unit should be able to comply with all of the standards. Commenter 17648 

notes that utilities that failed to plan ahead “should not be permitted to use their own inaction to justify

more time.”

Commenters 17808 and 18450 note that several major utility companies have anticipated the EPA’s 

rules and are already taking action to ensure a reliable supply of electricity in their service territory and 

beyond. Commenter 17808 cites two companies that have made planning efforts in advance of final 

rulemakings. The commenter cites one company (NextEra Energy) that began evaluating control 

technology before the release of the proposed rule. The commenter cites another company (Constellation 

Energy) that similarly conducted preliminary engineering studies before the Maryland Legislature 

enacted the Healthy Air Act of 2006.

Commenters 17648 and 18450 agree that there is significant excess generation capacity in the country 

and reliability will not be threatened by the rule.

Several commenters (18487, 19536, 19537, 19538) agree that the 3-year period will not adversely affect 

electricity system reliability.

Commenter 17110 urges the EPA to proceed with finalizing the rule without delay. According to the 

commenter, companies are already preparing for a 2015 compliance date, factoring in the capital 

expenditures required to comply and delays would undermine decisions that have already been made.
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Commenters 17789 and 18450 agree that the compliance time is reasonable and further states that a 

shortage of skilled labor is unlikely to prevent utilities from meeting the compliance requirements.

Commenter 18421 notes that the Building and Construction Division of the AFL-CIO has stated that 

there is no evidence to suggest that the availability of skilled manpower will constrain pollution control 

technology development. According to the commenter, in fact, given the high levels of unemployment 

in the construction sector, these jobs are much needed.

Several commenters (17844, 18439, 18450) believe that the industry is well-positioned to comply in the 

time allotted without threatening electric system reliability. Commenters (17844, 18450) cite the 

following sources: two recent reports – one from M.J. Bradley & Associates and Susan Tierney of the 

Analysis Group, and the other from the Bipartisan Policy Center – that independently conclude that the 

electric industry is well-positioned to comply with the EPA’s proposed air regulations without 

threatening electric system reliability. According to the commenters, if electric system reliability were to 

be threatened in local areas as a result of the rule, the EPA has the statutory authority to grant, on a caseby-case basis, extensions of time to complete the installation of pollution control systems.

The commenters assert that n addition, recent electricity forward capacity market auctions in the PJM

and ISO-New England markets for the period of 2014 and 2015 indicate that the capacity markets 

cleared with electricity reserve margins of 20 percent in PJM and greater than 14.4 percent in ISO-New 

England. According to the commenters, these reserve margins are well in excess of the federal reliability

standards set by the NERC for the year 2015, and these results cover periods after the rule is expected to 

have been in place for at least 6 months, demonstrating that the electric industry can meet the 

requirements of the rule without threatening the reliability of the electric system. Commenter 18450 

quotes NERC, stating that NERC does not see impacts from the proposed climate legislations or 

anticipated EPA regulation as a reliability concern. Commenter 18450 cites a January 2011 report by 

Charles Rivers Associates (CRA) that concludes that (1) Less than 5 percent (35 GW) of the total 

capacity in the EIC will retire by 2015; and (2) Electric system reliability can be maintained while 

transitioning to a cleaner energy future through increasing operation of existing, underutilized gas 

plants, coal-to-gas conversions, new gas-fired generation, expansion of load management programs, and 

established market and regulatory safeguards.

Commenter 18541 notes the existence of a:

broad array of electricity generation and grid management technologies that are making 

“baseload” power obsolete as FERC Chairman Wellinghoff noted in 2009. Indeed, a 

combination of renewable energy (such as wind, solar, biomass, geothermal, low-head 

hydro), natural gas and flexible generation technologies, and energy efficiency can now 

meet new electricity demand, and begin to replace or back out existing generation, within 

most balancing areas in the country. Such combinations of technologies, paired with 

smart grid management in balancing areas (including use of forecasting of output from 

wind and sun generation) can ensure a reliable electricity supply. The use of renewable 

energy and efficiency will also provide savings over time from reduced fuel use.

Commenter 17819 cites a 2003 DOE report evaluating Hg control by activated carbon:

injection (ACI), stating that ACI has low cast, requires little downtime to install, is 

effective for bituminous and sub bituminous coals, can achieve 90 percent removal when 
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used with a fabric filter, can be integrated with virtually every configuration of air 

pollution control equipment including ESPs, fabric filters, wet and dry scrubbers.

Commenter 18425 states that the 1-year extension if the facility is unable to install appropriate controls 

will protect electricity system reliability. According to the commenter, applying the extension to both 

the installation of add-on controls and the construction of on-site replacement power is appropriate 

under the CAA.

Commenter 17928 supports the schedule and the agency’s authority to extend the time allowed provided 

that any additional time granted does not provide an undue economic advantage.

Comment 29: Commenter 17648 asked that EPA establish uniform criteria for the section 112(i)(3)(B) 

case-by-case one-year extension and allow plants that receive the extension to dispatch only to meet 

reliability needs during the extension period.

Comment 30: Multiple commenters (17254, 17620, 17648, 17810, 17852, 17853, 18025, 18421, 

18932) agree with the EPA’s assessment that the new rules will not jeopardize or impair the reliability

of the electricity supply. Other commenters (17254, 17648, 17810, 17852, 17853) cite reliability

assessments that show sufficient capacity to ensure reliability of the electricity network after the rule 

takes effect. These include:

 North American Electric Reliability Corporation (NERC). 2010 Long-Term Reliability

Assessment. October 2010. http://www.nerc.com/files/2010_LTRA_v2-.pdf

 Ira Shavel & Barclay Gibbs, Charles River Associates, “A Reliability Assessment of EPA’s 

Proposed Transport Rule and Forthcoming Utility MACT” (Dec. 16, 2010)

 Michael J. Bradley, Christopher E. Van Atten, & Amlan Saha (M.J. Bradley & Associates LLC) 

& Susan F. Tierney (Analysis Group), “Ensuring a Clean, Modern Electric Generating Fleet 

while Maintaining Electric System Reliability: Summer 2011 Update,” (June 2011)

 Susan F. Tierney & Charles Cicchetti, “The Results in Context: A Peer Review of EEI’s

‘Potential Impacts of Environmental Regulation on the U.S. Generation Fleet’” (May 2011).

 Integrated Planning Model data commissioned by America’s Natural Gas Alliance (ANGA).

 Credit Suisse, Growth from Subtraction: Impact of EPA Rules on Power Markets (September 23, 

2010), p. 45, available at 

http://epw.senate.gov/public/index.cfm?FuseAction=Files.View&FileStore_id=b42de70d--

-b814---4410---831d--- 34b180846a19.

Comment 31: Several commenters (17648, 17853, 18421) believe that the number of coal-fired EGU

retirements that will result of regulation of EGUs have been overestimated by some sources. These 

commenters note that independent analyses support the EPA’s retirement projections, and criticisms of 

the EPA’s projections are overstated. Commenters note that EEI’s report resulted in inflated unplanned 

coal retirements because their modeling scenarios incorrectly assumed that the Waxman-Markey climate 

change bill passed Congress, that the CWA section 316 cooling tower regulations would mandate a onesize-fits-all standard, and MACT limits that are more restrictive than those proposed in the Toxics Rule. 

Commenters also state that the Tierney-Cicchetti Peer Review Report found that only one of EEI’s

scenarios represented a plausible regulatory scenario, but determined that the incremental unplanned 

coal retirements modeled under this scenario for 2015 (totaling 24 GW) should be considered the upper 

end of potential retirement impacts, since even this scenario overstates the impacts of the section 316 

rule. Commenter 18421 believes that the North American Electric Reliability Corporation (NERC) 
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“2010 Special Reliability Assessment: Resource Adequacy Impacts of Potential U.S. Environmental 

Regulations” may also overestimate the impact of new regulations.

Comment 32: Several commenters (17648, 17810, 17852) believe that existing gas units have 

significant untapped potential, which can be utilized to maintain reliability without the need to undertake 

new construction. Commenter 17648 notes that if all coal-fired units with a name plate capacity of less 

than 200 MW retired, the power produced by these retired units could be replaced using only 5% of the 

unused capacity of existing combined cycle gas units. Commenter 17810 notes that the existing natural 

gas-fired EGU capacity will allow the industry to maintain its reserve margins, including during the 

scheduled outages that will be necessary to install pollution control equipment required by this 

regulation.

Comment 33: Several commenters (17620, 17648, 17853, 17875, 18932) argue that EGUs will have 

sufficient time to comply with the rule without disrupting reliability. These commenters note that power 

plants have known about the various new regulations affecting power plants for several years and have 

therefore had plenty of time to prepare. These commenters note that many public utility commissions 

require integrated resources plans, which implement a planning mechanism to assure adequate reserve 

margins are maintained. Commenter 18932 notes that several utilities have made statements indicating 

that they are well positioned to comply with the EGU MACT, as well as other EPA regulations that will 

affect the utility sector.

Comment 34: Commenter 17620 points out that several states have implemented Hg limitations for

EGUs without adverse impacts on reliability.

Comment 35: Several commenters (17110, 17810, 18025, 18421) note that forward capacity auctions, 

such as those held by PJM and ISO-New England for the years 2014 and 2015 (after the Transport Rule 

and this proposed rule will be in effect), have shown that the regions will have more than enough 

capacity to meet federal reliability standards without significant price increases.

Comment 36: Several commenters (17648, 17810, 17853, 18025) believe that retirements that occur 

can be managed and new capacity can be developed to ensure no disruption to the electric power supply

after the rule is implemented. These commenters note that a number of practical and legal options exist 

for when an EGU is to be retired or needs greater time to install controls. Commenters further note that a 

resolution that maintains reliability can be reached through the authority under the Federal Power Act, or 

through exercise of enforcement discretion in a consent order to decree that accommodates both 

environmental imperatives and reliability concerns. Commenter 17648 points out that if reliable electric 

power is compromised by compliance with environmental regulations, the U.S. DOE, the EPA, state 

agencies, and regional transmission organizations (RTOs) can work together to strike a balance in 

protecting public interest in both objectives. Commenter 17648 also notes that RTOs typically have 

advanced warning of proposed unit retirements and that each RTO has procedures to assure that threats 

to reliability are identified early enough to be avoided.

Comment 37: Commenter 17810 notes that the EPA can grant time extensions for power plants to 

install pollution control equipment on a case-by-case basis under the CAA. This commenter further 

notes that the EPA and the DOE have the authority to enter into administrative orders of consent or 

consent decrees with power plants that allow them to run under specific and limited circumstances to 

maintain reliability. The commenter states that the DOE can override CAA requirements under section 

202(c) of the Federal Power Act in limited emergency circumstances, and if a widespread reliability

concern were to arise that could not be addressed through these statutory mechanisms, the President also 
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has the authority under the CAA to extend deadlines in the rule if technologies are not available and it is 

in the national security interest.

Comment 38: Commenter 18039 questions the suggestion that existing units be allowed to run for an 

additional year while a replacement is constructed, without being subject to MACT standards for that 

year. The commenter agrees that this is a reasonable scenario for facilities that will use that year to 

construct a replacement unit with significant long-term emission reductions. However, the commenter is 

concerned that a facility in the process of building replacement power may decide to operate a highemitting unit for an additional year, specifically due to the extension. The commenter therefore objects 

to the extension, for fear a large amount of pollutants will result. The commenter also asks that if 

construction replacement power lasts longer than the one-year extension, the final rule wording make 

clear that the older unit is not permitted to avoid MACT compliance beyond that year, even if the 

replacement is not yet on-line.

Comment 39: Commenter 18421 called on the EPA, the Department of Energy, and the Federal Energy

Regulatory Commission to expand and accelerate interaction with regional utility planning and 

operation centers, the National Association of Regulatory Utility Commissions, state PUCs, and 

all market participants to ensure that the measures available to preserve electric system reliability while 

providing for life-saving reductions of Air Toxics are implemented.

Commenter 19114 states that EPA notes that before the final rule, they will work with “DOE and FERC 

to identify any opportunities offered by the authorities and policy tools at the disposal of DOE and/or 

FERC” to protect reliability. According to the commenter, this language suggests that EPA has not 

consulted with DOE and FERC to date, which suggests that the necessary rule coordination or 

harmonization is not occurring. The commenter states that the statement implies that EPA only sees 

flexibility on the part of DOE and FERC to protect reliability and that adding this flexibility into the 

MACT rule itself, or other proposed rules for that matter, is not a concern for EPA, which goes directly 

against the Executive Order. 

The commenter states that it has been involved in a series of meetings with PJM, SPP, EPA, DOE, 

FERC, and NERC to discuss the impacts of this and other EPA rulemakings on the reliability of the 

transmission system as well as to discuss ways that EPA can provide flexibility to ensure reliability. The 

commenter suggests that EPA closely examine all of the publicly announced implementation plans from 

utilities to assess the accuracy of the data EPA is relying on to make the claim that grid reliability is not 

an issue. According to the commenter, these data must take into account actual and planned future 

regulations and their impact on the electric sector, as well as resulting rate and reliability impacts, and 

only in viewing a comprehensive and holistic analysis of the electric sector can there be a reasonable 

discussion of the reliability impacts. The commenter states that this type of cross-functional analysis 

should include the most specific localized or unit level reliability analysis possible in order to pick up 

key ancillary services important to grid stability.

Response to Comment 28 - 39: The EPA has set out in the preamble to this rule, the situations that 

merit the one-year extension under CAA section 112(i)(3)(B). While authority to grant the 1-year 

extension is given to the state permitting authorities, EPA expects that that discussion in the preamble 

will help guide the states on this matter. The CAA allows CAA Title V permitting authorities the 

discretion to grant extensions to the compliance time of up to 1 year if needed for installation of 

controls. If an existing source is unable, despite best efforts, to comply within 3 years, a permitting 

authority has the discretion to grant such a source up to a 1-year extension, on a case-by-case basis, if 

such additional time is necessary for the installation of controls. Permitting authorities should be 
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familiar with the operation of the 1-year extension provision because EPA established regulations to 

implement the provision and the provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(i). 

This category of sources is unique due to the large, complex and interconnected nature of electrical 

generation, transmission and distribution, and the criticality of the electric grid to the functioning of all 

aspects of the economy. The grid functions as an interconnected system that supplies electricity to end 

users on a continuous basis. Safe, reliable operation of the grid requires coordination among actions 

taken at individual units, including timing of outages for the installation of controls, derating, or 

deactivation. For this reason that we believe that the fourth year may be appropriate in additional 

circumstances. The EPA believes that it is reasonable for permit authorities to allow the fourth year 

extension to apply to the installation of replacement power at the site of the facility when a unit is 

retiring and being replaced by a cleaner unit. The EPA believes that building replacement power 

constitutes the “installation of controls” at a facility to meet the regulatory requirements.

In addition several situations may be eligible for the 1-year extension if it is necessary to maintain 

reliability including: (1) generation from the retiring unit is needed to maintain reliability while other 

units install emission controls; (2) new off-site generation was being built to replace the retiring unit, but 

the new generation was not scheduled to be operational within the 3-year time-frame and any gap 

between the time the existing unit retires and the new unit comes on line would cause reliability

problems; and (3) transmission upgrades were needed in order to maintain electric reliability after the 

unit retired but could not be completed within 3 years.

While the ultimate discretion to provide a 1-year extension lies with the permitting authority, EPA 

believes that all three of these cases may provide reasonable justification for granting the 1-year 

extension if the permitting authority determines based on information from the RTO or other planning 

coordinator for the relevant region, and/or NERC or one of its regional entities, and/or the FERC or the 

DOE, that continued operation of a particular unit slated for retirement for some or all of the additional 

year is necessary to avoid a violation of applicable FERC-approved or state electric reliability standards. 

In the three cases related to retirement of a unit without construction of onsite replacement power, 

additional information is needed. The Title V permitting authority should request that the affected 

company or companies provide information from the relevant RTO or other planning coordinator and, 

where appropriate, the state electric regulatory agency, and/or NERC or its regional entities, and/or 

FERC – demonstrating that retirement of a particular unit within the 3-year compliance period would 

result in a violation of applicable FERC-approved or state reliability standards. 

In all cases the EPA urges that permitting authorities endeavor to the extent practicable to reduce of the 

existing unit’s HAP emissions while maintaining electric reliability.

4. Current compliance period should be longer.

Comment 40: Numerous commenters (18023, 8443, 9738, 16705, 16469, 16849, 16856, 17022, 17055, 

17254, 17265, 17297, 17368, 17383, 17400, 17402, 17403, 17406, 17608, 17623, 17627, 17637, 17638, 

17640, 17648, 17654, 17655, 17656, 17675, 17677, 17681, 17689, 17696, 17697, 17703, 17705, 17707, 

17711, 17714, 17716, 17720, 17722, 17724, 17730, 17731, 17732, 17734, 17735, 17736, 17741, 17752, 

17756, 17758, 17761, 17765, 17767, 17770, 17774, 17775, 17790, 17798, 17799, 17800, 17805, 17807, 

17808, 17810, 17812, 17813, 17815, 17817, 17820, 17821, 17824, 17829, 17834, 17837, 17840, 17857, 

17868, 17870, 17873, 17876, 17877, 17878, 17879, 17881, 17883, 17885, 17887, 17902, 17904, 17909, 

17911, 17912, 17913, 17918, 17925, 17930, 17931, 18016, 18021, 18024, 18026, 18027, 18031, 18037, 
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18038, 18419, 18422, 18424, 18428, 18430, 18433, 18437, 18440, 18441, 18447, 18477, 18498, 18500, 

18502, 18575, 18933, 19032, 19114, 19121, 19212, 19213, 19506, 19653) state that the compliance 

period is too short.

Several commenters (8443, 9738, 17608) ask that small entities be granted additional compliance time.

Multiple commenters (16469, 16705, 16849, 17265, 17400, 17637, 17655, 17656, 17703, 17730, 17758, 

17776, 17913, 18038, 18437, 18447, 18477, 18498) advocate for an optional extension for 2 more years, 

resulting in a total of 5 years. Several commenters (18575, 19032, 19213) request that the EPA allow a 

total of 5 years for compliance.

Multiple commenters (18023, 17623, 17689, 17714, 17722, 17731, 17732, 17756, 17775, 17817 (major 

sources of HAP), 17868, 17904, 17925) request that the EPA allow a total of 6 years for compliance.

Multiple commenters (17022, 17408, 17735, 17758, 17761, 17817 (non-major sources of HAP)) ask that 

the timeframe be extended until 2020.

Several commenters (17724, 17741, 17805, 17868) ask that a compliance timeline of 9 years be 

permitted.

Multiple commenters (17055, 17408, 17677, 17734, 17756, 17761, 17774, 17791, 18024, 18026, 18422, 

19506) ask that the EPA consider a flexible, gradual, or staggered compliance schedule for this 

rulemaking.

Commenter 17911 requests a 2-year extension on compliance with some provision for further extension 

for local utilities, based on the utilities’ additional burden of maintaining a publicly accountable process. 

The commenter requests provision for further extension provided that the local utility can document that 

they have pursued a good faith effort to expeditiously secure approvals, financing, engineering, design, 

manufacturing, acquisition and installation of the necessary emission control equipment.

Commenter 18441 states that outage windows to accommodate upgrade construction are limited to 

opportunities when prevailing system conditions permit, so that operational reliability is not 

compromised. The commenter appreciates the EPA’s recognition of the need to spread complex outages 

over multiple outage periods. According to the commenter, as the breadth of the outages and the 

availability of retrofit materials may impact the scheduling of outages, it is not clear that the proposed 

3+1 timeline provides sufficient flexibility for the commenter, as a regional transmission organization to 

manage all of these outages in a staggered manner.

Commenters 18441 and 18448 state that timely notice of deactivation to the regional transmission 

organization and an identification that the unit in question is a reliability critical unit which cannot be 

replaced with alternative resources or transmission reinforcements in the 4-year time allotted would be 

allowed a limited “safe harbor” from penalties until the regional transmission organization indicates that 

adequate resources have been put in place to address the reliability concern. The commenter states that 

the regional transmission organization’s findings would be developed in open stakeholder processes and 

made available for the EPA’s (or state air permitting authority’s) ultimate determination as to whether to 

grant such an extension and that such a process may entail the EPA authorizing or endorsing a schedule 

of compliance in the affected generating unit’s Title V permit through the implementing state authority, 

in coordination with the regional transmission organization; and/or a Consent Decree between the EPA, 

the state authority and the generation owner developed and signed prior to the end of the compliance 
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period, or a formal extension through a streamlined process including the EPA, and the implementing 

state authority working with the asset owner and the regional transmission organization to grant 

extensions beyond January 1, 2016.

Multiple commenters (16469, 16850, 17608, 17640, 17705, 17711, 17716, 17719, 17724, 17730, 17752, 

17756, 17761, 17774, 17805, 17820, 17821, 17837, 17840, 17868, 17902, 17918, 17919, 17931, 18016, 

18033, 18037, 18422, 18428, 18440, 18442, 18498, 18575, 19506) ask that the EPA consider other 

simultaneous rulemakings and extend the compliance period. Commenters specifically mentioned the 

following:

a. Cooling Tower Intake Structures (17724, 17805, 17868, 17918, 17919, 18440, 18442)

b. Coal Combustion Residuals (17724, 17774, 17805, 17821, 17868, 17918, 17919, 18440, 18442)

c. Regional Haze (17719, 17724, 17730, 17761, 17805, 18442)

d. Clean Air Transport Rule (17608, 17724, 17868)

e. Water Effluent Limit Reductions (17724, 17774, 17805, 17919)

f. Cross State Air Pollution Rule (16850, 17640, 17705, 17716, 17730, 17752, 17756, 17761, 17774, 

17820, 17821, 18442, 18498, 19506)

g. NESHAP for industrial, commercial and institutional boilers (16469, 17608, 17711,

17756, 17837, 17840, 18024, 18424, 18442)

h. NESHAP for commercial and industrial solid waste incinerators (17608, 18024)

i. NSPS for greenhouse gas emissions from EGUs (17608, 17774, 17918, 17919, 18440, 18442, 18498)

j. NAAQS for SO2, NO2, ozone, and PM (17821, 17918, 17919, 18440, 19506)

k. Area source Boiler MACT (18024)

Multiple commenters cite previous compliance timeline extensions that were granted:

a. Marine Tank Vessels - 1 year (18023, 16469, 17254, 17368, 17403, 17623, 17681, 17696, 17734, 

17758, 17775, 17837, 17840, 17857, 17902, 17931, 18033)

b. Pulp and Paper Production - 8 years (17623, 17774)

c. MON (17623, 17774)

d. NESHAP for Secondary Lead Smelting - 1 year (17716, 17731)

Multiple commenters (8443, 17402, 17627, 17767, 17821, 17868, 18021, 18037, 18502) ask that the 

EPA consider physical space limitations. According to the commenters, without sufficient space to 

install control devices, units may have to be retired.

Commenter 18575 discusses its diverse generation portfolio and says that this usually mitigates price 

fluctuations related to the cost of generation of any single resource. However, the commenter says that 

this diversity now guarantees that it will be affected by several of the new and pending EPA rules all in 

the same timeframe, which will strain their ability to afford and meet compliance timelines. The 

commenter gives the following examples:

1. EGU MACT: As proposed, the commenter’s coal-fired generation will be covered by the proposed

EGU MACT;

2. RICE Rule: commenter’s contracted generation from gas-fired, reciprocating internal combustion 

units are covered under the EPA’s recent RICE Rule;

3. CSAPR: Commenter’s Whelan Energy Center unit is covered by the CSAPR (formerly known as the 

“Clean Air Transport Rule”);
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4. CCR Rule: Commenter’s coal-fired resources face compliance requirements related to the disposal of 

coal combustion residuals from coal-fired power plants to be finalized by the EPA in 2012;

5. GHG Rule: Commenter’s facilities face restrictions under the upcoming NSPS for GHG emissions 

from new and existing EGUs that are scheduled to be proposed in September of 2011 and finalized 

by May 2012;

6. 316(b): On April 20, 2011, the EPA proposed its section 316(b) rule under the CWA that will require 

changes in cooling water intake structures used to cool coal, gas and nuclear steam-electric 

generating plants, including the Cooper Nuclear Station which forms a portion of the commenter’s

generation portfolio.

7. Regional Haze Rule: Commenter’s Laramie River Station facility, located in Wyoming, faces 

additional regulatory costs since the state’s SIP is still under review and could face new, potentially 

very expensive retrofit requirements to be completed by 2013, according to the EPA’s Regional 

Haze timeline.

Commenter 17911 asks that the EPA consider the unintended consequences of recommending 

technologies that make CCR more difficult to recycle. The commenter suggests a 2-year moratorium on 

implementation of the proposed rule until some of the interrelated rules are more fully defined.

Response to Comment 40: The EPA provided the maximum 3-year compliance time authorized under 

the statute. See section 112(i)(3)(A). Furthermore, the EPA’s actions in other CAA section 112 

rulemaking actions authorizing longer compliance periods are no longer relevant. Since those rules were 

issued, the D.C. Circuit Court has determined that the EPA does not have authority to provide a 

compliance period in excess of 3 years. See NRDC v. EPA, 489 F.3d 1364, 1373-74 (D.C. Cir. 2007) 

(rejecting a 1-year extension for all sources in the category because of changes to reporting requirements 

issued after the final rule setting forth the emission standards were initially promulgated too short).

The following is a response to the various reasons given in comments as to why the proposed 

compliance time frame is too short. For a fuller discussion of these issues please see the Technical 

Support Document entitled, “An Assessment of the Feasibility of Retrofits for the Toxics Rule” in the 

docket.

Claims of Infeasibility for 2015-16 Compliance

The EPA’s authority for setting the compliance time frames is set out in the CAA. In developing this 

proposed rule, the EPA has performed specific analysis to assess the feasibility (e.g., ability of 

companies to install the required controls within the compliance time-frame) and potential impact of the 

proposed rule on reliability. For that analysis entitled “An Assessment of the Feasibility of Retrofits for 

the Toxics Rule” dated March 9, 2011, the EPA has projected the quantity of each APC technology that 

may need to be newly retrofitted and in service by the compliance date(s). The EPA used its IPM model 

to analyze which APC technologies would likely be used, and in what quantities, to achieve compliance 

with the proposed Toxics Rule.

The EPA’s assessment shows that a reasonable, moderately paced effort of the power sector and 

supporting industry, including some early starts, would result in many of the needed retrofits being 

installed by January 2015 with some needing up to an additional year. In order for all retrofits to be 

completed by January 2015, most projects would have to start early and the sector would have to engage 

in a more aggressive deployment program. In the event that individual projects cannot be completed by

the January 2015 statutory deadline for compliance, the CAA offers affected sources the opportunity to 

apply for a 1-year extension.
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Claims That More Time is Needed for Small Entities To Comply

As stated above, the EPA’s authority to provide more than three years to comply with the standards is 

constrained by CAA section 112(i)(3)(A) and the D.C. Circuit Court interpretation of that provision. See 

NRDC v. EPA, 489 F.3d 1364, 1373-74 (D.C. Cir. 2007) (rejecting a 1-year extension for all sources in 

the category after the agency promulgated changes to reporting requirements issued after the final rule 

setting forth the emission standards). The compliance provisions of the statute do not provide an 

exception for small entities.

Inadequate Labor Pool, Low Skill Level & Insufficient Equipment Suppliers

With current unemployment rates, sufficient quantities of engineers and skilled craft exist for 

implementation of this rule. Likewise, for the extreme case of local labor shortages (which is not 

anticipated), this challenge can be overcome by instituting a workforce development action plan during 

project execution. This sector’s equipment suppliers and manufacturers are underutilized and have been 

since 2010. 

Site Congestion Can Lengthen Retrofit Timing and lead to retirement

One commenter suggested that the facilities that were easy to retrofit, did retrofit for compliance with 

the acid rain program and CAIR. So what is left to retrofit under this program, is more difficult and will 

take longer than retrofits in the past. Several commenters said that plants may retire because space 

constraints would prohibit retrofitting. 

Available space is a problem at many remaining facilities. Space constraints are a challenge that must be 

addressed early in the design stage of a compliance strategy. There are a number of ways to economize 

the available space but ultimately each plant is different and the solutions will be different. Many of the 

controls that the EPA expects plants to use to comply with MATS, especially DSI and ACI, work well at 

a space constrained facility. In addition, the EPA expects that in many cases it will be possible and 

economic to combine emissions from several units into a larger control device. In such combined multiunit cases the installation time should be only slightly greater than for a single unit, and still feasible for 

compliance by 2015-2016. In any event, a multi-unit retrofit on one site has significant execution cost 

and schedule advantages not realized at multiple single unit stations through aggregating resources to 

create economies of scale. These include one-time mobilization, extended equipment rental, dedicated 

staging area, efficient skilled craft utilization, and reduced administrative outlays. Furthermore, units can 

be “tied-in” sequentially, avoiding a complete station shutdown during installation.

Successful examples include Dickerson Station’s three 190 MW units feed a single scrubber which 

discharges into a single flue stack. Chalk Point station’s two units share a single common wet FGD. 

FirstEnergy’s Sammis station’s wet scrubber project combined emissions from seven units into three 

absorbers. AEP’s Clifty Creek and Kyger Creek stations will employ similar design concepts for their 

wet FGDs. And at WE Energies’ Presque Isle facility several units are tied into one fabric filter.

Finally the rule allows facility averaging for existing EGUs in the same subcategory so that in many

cases it may be possible to retrofit only some of the units and achieve the standards. 

Time frame for Compliance Is Too Short to Construct and Permit an FGD Landfill 
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The compliance deadline allows sufficient time for completing landfills for FGD solids disposal. For 

example, DP&L will construct a landfill within 18 months to accept wastes generated from Stuart and 

Killen stations scrubbers. The EPA notes, however, that retrofitting units do not necessarily need to 

complete landfill construction ahead of commencing operation of the retrofit to achieve cost-effective 

emission reductions under the Transport Rule programs. Such a source may either utilize a completed 

portion of the newly permitted landfill under construction, transfer waste off-site to a permitted landfill 

within the owner’s fleet, or contract waste removal (and disposal) services. For example, Dallman 

station subcontracts coal ash disposal at a local abandoned mine. The EPA uses a disposal cost 

assumption of $30-$50 per ton for wet FGD, dry FGD, and DSI controls, which the EPA developed in 

consultation with an experienced power sector engineering firm.

Short Time Frame Will Cause Electricity Rates to Rise

The EPA recognizes that this rule will cause electricity prices to rise. The EPA projects that the increase 

in retail electricity prices that will result from this regulation range from 2 to 3 cents per kWh in 2015 

and will decrease in the ensuing years. On average, this is a 2.9 percent increase and is well below 

electricity prices seen historically and as recently as four or 5 years ago. The average increase over the 

base case declines over time.

Multiple Rulemakings Necessitate a Longer Compliance Time

A number of commenters said that the unusual number of regulations that the EPA is promulgating for 

the electric power sector in approximately the same time frame compounds the problems caused by the 

MATS compliance time. The EPA understands that there are a number of regulations that will set in 

place standards that have to be met by this industry. The Cross-State Air Pollution Rule was 

promulgated last summer and the Cooling Water Intake Rule will be promulgated next year. A 

regulation setting standards for handling coal combustion waste has been under development for the past 

few years. The confluence of these regulations allows the power industry to plan for compliance with 

information about the full suite of requirements that they will face. It reduces uncertainty and provides 

an opportunity for the power sector to develop integrated strategies for meeting EPA regulations 

allowing for a cost effective approach on the part of the companies that takes account of the multiple 

requirements. Many of these strategies will take advantage of the collateral effect of pollution control 

technologies. For example, actions taken to reduce emissions under the Cross-State Rule will help 

facilities achieve the acid gas and in many cases mercury standards in this rule. 

Smaller Plants Will Not be Able to Compete with Larger Plants for Controls

Some commenters said that smaller plants would have a harder time getting controls on plants within the 

compliance time frame because they would not be able to compete with larger plants for equipment, 

labor, and engineering and therefore they need a longer compliance time frame. Small plants are not 

necessarily at a disadvantage. The EPA notes that smaller plants can often control very cost effectively

either because they simply need less equipment and labor to retrofit and because they can often tie more 

than one small or midsize unit into one control device. Shared APC systems will allow the overall effort 

to be more manageable than otherwise, and should require relatively fewer supply chain resources.

Smaller Companies Will Not be Able to Compete with Larger Companies for Controls

Several commenters said that small companies need more time to comply with the regulation because 

they would not be able to compete with larger companies in the market for labor, equipment and 
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engineering services to comply with this regulation. This comment presumes that there is a shortage of 

equipment, labor and materials to apply to compliance with this regulation. As stated elsewhere we are 

in an economy that is characterized by high unemployment and chronic excess capacity. While this 

regulation will modestly spur demand it cannot reasonably be expected stimulate enough demand to 

cause shortages such that firms will have difficulty obtaining the services they need to comply.

Comment 41: Multiple commenters offer suggestions on methods for allowing more time for 

compliance:

a. Authority under section 112(n)(1)(A): (17403, 17799).

b. State authority under section 112(i)(3): (18023, 9738, 16469, 17265, 17297, 17402, 17403, 17623, 

17638, 17648, 17654, 17681, 17689, 17696, 17705, 17714, 17716, 17722, 17724, 17752, 17756, 17758, 

17765, 17775, 17790, 17798, 17799, 17800, 17805, 17807, 17808, 17810, 17817, 17820, 17837, 17841, 

17857, 17868, 17870, 17876, 17877, 17886, 17887, 18034, 18038, 18502, 18575)

c. Presidential authority under section 112(i)(4): (18023, 16469, 16705, 16849, 17265, 17400, 17637, 

17655, 17656, 17681, 17689, 17703, 17705, 17714, 17722, 17724 (5-year exemption), 17730, 17756, 

17758, 17774, 17775, 17799, 17805 (5-year exemption), 17807, 17817, 17820, 17821, 17868, 17870, 

17876 (5-year exemption), 17877, 17886, 17931, 18027, 18031, 18033, 18034, 18038, 18428, 18477, 

18500, 18502, 18575)

d. Categorical extension for publicly-owned or governmental facilities according to EO 13132, 13563, 

and UMRA of 1995: (17868)

e. State-designed programs under the delegation provisions of section 112: (17719, 17873)

f. Delay Consent Decree: (17654, 17876, 17930)

g. Through Administrative Orders of Consent (AOCs): (17808, 17868, 17870)

h. Through Consent Decrees: (17648, 17808, 17870, 18448)

i. Temporary waiver mechanisms: (17055)

j. Adoption of MACT compliance schedules through minor permit modifications of a source’s Title V 

federal operating permits: (17868, 18422)

k. Compliance extensions for units that reduce early or install specified control equipment: (17265, 

17638, 17681, 17807)

l. CAA section 112(i)(6): (17821; although the commenter argues that it offers no meaningful relief to 

most sources)

m. Provide a future effective date for the rule. This approach would allow promulgation by the date 

mandated by the consent decree, and would assist states and utilities by relieving the requirements of 

case-by-case MACT determinations that must be made until the MACT standard is promulgated: 

(18442)
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Commenters 17648 and 18502 ask that the EPA allow use of consent agreements. Commenter 17648 

states that as a matter of law and long-standing administrative practice, then, the requirements of the 

Toxics Rule will apply without abatement to facilities subject to a consent arrangement, however, as a 

matter of policy, the EPA may wish to accommodate certain consent arrangements that pre-date 

publication of the proposed Toxics Rule in case-specific circumstances. Commenter 17648 explains that 

most existing consent arrangements are directed to controls on criteria pollutants which will ordinarily

be insufficient to control HAP in a manner consistent with the rule. Commenter 17648 states that any 

accommodation would need to provide for the implementation of HAP controls “as soon as practicable”

given existing commitments under the consent arrangement. According to the commenters, for example, 

a consent arrangement that provides for installation during 2015 of a FGD system that would adequately

control acid gas HAP might be accommodated provided controls for Hg and non-Hg metal HAP were 

installed prior to the compliance deadline.

Commenter 17648 suggests two options for accommodating consent arrangements:

1. First, the EPA could authorize state permitting agencies to provide facilities subject to a consent 

arrangement with the same 1-year extension from the applicable statutory deadline “for the installation 

of controls” under section 112(i)(3)(B) available to other sources, assuming those facilities intend to 

install controls before the end of 2015. According to the commenter, the EPA could exercise its 

discretion as to whether to require facilities subject to a consent arrangement to comply with interim 

operating conditions.

2. The second option available to the EPA is to enter into a “wrap-around” consent order or consent 

decree that would incorporate additional requirements necessary to comply with the Toxics Rule beyond 

those required in the existing consent arrangement. The commenter states that this task must be 

approached on a case-by-case basis, with the judicious use of the enforcement discretion of the EPA and 

state permitting agencies and that existing consent arrangements are unlikely to provide for the 

installation of emission controls sufficient to comply with the Toxics Rule. The commenter asserts that 

EGU operators who are parties to such arrangements will bear the burden of deciding whether to seek 

additional relief, or to comply with the rule on time. The commenter states that some consent 

arrangements will be inadequate in scope or alacrity, or both, and will need to be supplemented either by

a “wrap-around” consent order or decree, or by an amendment to the existing arrangement. According to 

the commenter, ultimately the same enforcement discretion that formed the basis of the existing consent 

arrangements will be applied to determine if, and how, they must be modified, and the operating 

conditions that should be applied during the period of extension. The commenter states that only in this 

way can the EPA and state permitting agencies conserve the benefits of these consent arrangements 

without sacrificing the overwhelming health and economic benefits that the Toxics Rule will provide.

Response to Comment 41: The agency has provided the maximum time authorized under CAA section 

112(i)(3)(A), and the provisions cited by commenters do not alter our authority concerning the initial 

compliance time that may be provided in CAA section 112 standards. Furthermore, as the EPA stated in 

the preamble to the final rule, our analysis shows that most plants can meet the standards within the 3-

year timeframe. The EPA believes that although most units will be able to fully comply within 3 years, 

the fourth year that permitting authorities are allowed to grant for installation of controls is an important 

flexibility that will address situations where an extra year is necessary. That fourth year should be 

broadly available where a facility owner has made a clear and diligent effort to install controls within the 

3-year time frame but is unable to complete the installation. Furthermore, in the event that an isolated 

localized reliability concern were to emerge that could not be addressed solely though the 1-year 
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extension under CAA section 112(i)(3), the CAA from provides some flexibility to assure reliability is 

maintained.

Comment 42: Multiple commenters (18023, 16469, 17254, 17297, 17383, 17403, 17623, 17638, 17654, 

17681, 17696, 17705, 17716, 17718, 17720, 17722, 17724, 17731, 17734, 17752, 17765, 17774, 17775, 

17790, 17798, 17799, 17800, 17807, 17816, 17820, 17840, 17842, 17856, 17857, 17868, 17876, 17881, 

17886, 17902, 17931, 18016, 18021, 18031, 18033, 18034, 18424, 18428, 18500) request a “blanket 1-

year extension” of the compliance deadline.

On the other hand, multiple commenters (9738, 17265, 17402, 17648, 17701, 17758, 17808, 17810, 

17852, 17887, 17973, 18025, 18027, 18438) ask that requests be granted only on a case-by-case basis.

Response to Comment 42: CAA section 112(i)(3)(B) provides that “[t]he Administrator (or a State 

with a program approved under subchapter V of this chapter) may issue a permit that grants an extension 

permitting an existing source up to 1 additional year to comply with standards under subsection (d) of 

this section if such additional period is necessary for the installation of controls.” This provision on its 

face applies to individual sources and, furthermore, the D.C. Circuit Court has determined that EPA 

does not have authority to provide a compliance period in excess of three. See NRDC v. EPA, 489 F.3d 

1364, 1373-74 (D.C. Cir. 2007) (rejecting a one year extension for all sources in the category after the 

Agency promulgated changes to reporting requirements issued after the final rule setting forth the 

emission standards). Even if we determined that we had the authority to provide an across the board 

fourth year under CAA section 112(i)(3)(B), we would likely decline to do so because some industry

commenter have specifically stated that they will be able to comply with the rule in the 3 year period 

and we believe that there are approximately 69 EGUs that are currently complying with all of the 

existing source standards. We do not think it would be reasonable or consistent with the statute to 

provide a longer compliance period for sources currently complying and sources that can in fact comply

within 3 years. For sources that cannot comply in that time, the 1 year compliance extension is available 

and EPA has committed to working with sources to ensure that compliance with the final rule will not 

affect electric reliability.

Comment 43: Multiple commenters (16824, 17003, 17137, 17730, 18441) ask that compliance be 

delayed until additional studies or analyses are conducted.

Commenter 16824 asks that the EPA complete a cost-benefit analysis (with further peer review and 

additional opportunity for public comment) before implementing this rule.

Commenters 17137 and 17821 endorse an indefinite delay until further study can be undertaken on the 

costs and impacts to industry, jobs, and consumers along with additional testing and evaluation. 

According to commenter 17137, the current deadline meets neither “the test of reasonability nor 

realism.”

Commenters 17003 and 17730 ask that the EPA undertake a formal assessment of the feasibility for 

regulated sources to contract for equipment and manpower needed to meet compliance deadlines for the 

Utility MACT and other pending regulations affecting coal-fired power generation.

Commenter 17003 asks that the EPA allow that a trial be undertaken to prove EPA’s assumption that 

acid gas can be removed at low cost.
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Commenter 17821 asserts that non-Hg metallic HAP removal technologies need further study in the 

same way that the DOE studied Hg.

Commenter 18441 states that full impact of the rule and the resulting generator decisions on whether to 

comply or retire have not been made. According to the commenter, it is simply premature to reach a 

definitive conclusion that the rule can be met without adversely impacting electric reliability. The 

commenter states that although the EPA’s analysis addresses overall system adequacy, the EPA has not 

analyzed system security under the rule.

Response to Comment 43: The MATS was developed by the EPA after years of studies and data 

analysis that examined the nature and quantity of HAP emissions from power plants, the health and 

environmental effects of the pollution, the availability of pollution controls and other measures to reduce 

emissions of these pollutants, the costs and benefits of reducing HAP emissions from EGUs, and the 

effect of the rule on consumers and on jobs. What the EPA learned is that coal-fired and oil-fired power 

plants are very large emitters of these pollutants, that cost effective strategies to reduce these emissions 

are readily available, and that doing so, while expensive would provide public health benefits valued at 

many times the cost, including avoiding premature deaths, more aggravated asthma and other respiratory

problems, non-fatal heart attacks, missed work and school days In the process the rule has little impact 

on consumer prices and increases jobs moderately. 

Although one can always argue for more studies, delaying this rule now for the purpose of more studies 

would delay significant health benefits to hundreds of thousands of Americans.

Comment 44: Commenter 17682 worries that the rule as proposed will severely harm the ability of the 

United States to produce reasonably priced power, diminish its international competitiveness, and result 

in minimal environmental improvements, and that it could even result in increased environmental risks 

from alternative energy sources, This commenter requested that the EPA withdraw the proposed rule. 

Commenter further asks that the EPA reissue a new rule only if it reflects the results of a credible costbenefit analysis and a full assessment of the impacts of using potentially conflicting and relatively 

untested MACT technologies to achieve compliance with the range of pollutant standards

Commenters 17003 and 17297 quote the EPA compliance cost estimates of a $3-4 increase in consumer 

electricity costs and suggest that a longer compliance timeline to develop and implement the least cost 

compliance strategy to ensure a reliable electric supply and minimal rate impacts.

Response to Comment 44: The impact of this rule on electricity and natural gas prices are within the 

range of normal variability and well below levels seen only 2 or 3 years ago. It is not reasonable to take 

as a “given” that this rule will diminish international competitiveness. In fact the annual cost of the rule 

is less than 0.001 percent of GDP. It is unlikely to have much impact on the competitiveness of the U.S. 

economy. 

The benefits of the rule on the other hand, according to the EPA’s cost benefit study which is based on 

peer reviewed scientific literature and methodologies are far greater than the costs, providing significant 

public health improvements to Americans. Furthermore this regulation can be complied with using 

tested control technologies that are in use on coal-fired plants today.

Comment 45: Multiple commenters (18023, 16850, 17402, 17403, 17623, 17648, 17655, 17686, 17705, 

17736, 17757, 17758, 17800, 17805, 17840, 17873, 19114) offer opinions on the timelines for control 
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equipment installation. Commenter 19114 provides a detailed discussion of time frames for planning, 

permitting and construction of controls in their comments.

a. DSI:

(1) 9-18 months on average but up to 5 years recently (17758)

(2) Two years (17402)

(3) <12 months (17648)

b. ACI: Up to 2 years for optimization after installation (17402)

c. FGD:

(1) Up to 60 months (17758)

(2) 40-69 months (18023)

(3) 36-42 months (17402)

(4) 40–60 months (17705)

(5) 40-65 months (17403)

(6) 52 months (17736, 19114)

(7) 44-64 months (17800)

(8) 66-72 months (17873)

(9) 2-4 years (16850)

(10) 40-65 months (17799)

(11) 52 months (17821)

(12) 50-63 months (17886)

d. FGD-associated landfill:

(1) 54 months on average (17736, 18428, 19114)

(2) > 10 months (19114)

(3) 3-5 years for permitting (17800)

e. Baghouse:

(1) 12-24 months (18421)

(2) >36 months (18023, 19114)

(3) >4 years for retrofit (17805)

f. SCR:

(1) 36 months (1837)

(2) 3 1⁄2 years (17623, 18428)

(3) 43 months (17655)

(4) 42 months (17736)

g. Scrubber:

(1) > 36 months (19114)

(2) 40-60 months (17623)
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(3) 40-69 months, average of 50 months (18023)

(4) 4-5 year time frame (17757)

(5) 4-5 years (17736)

(6) 48-54 months (17840)

(7) 2-3 years (16850)

(8) 52-58 months (17627, 18037)

(9) 3-5 years (17817)

(10) 45-58 months (17820)

h. New generation: 6 years (18023)

i. Changes in fuel supply to natural gas: 4 1⁄2 years (18023)

j. Changes to transmission grid:

(1) >3 years (18023)

(2) up to 7 years (17886)

k. Fabric filter:

(1) 42 months (17736, 17821)

(2) 5.5 years (17840)

(3) >=36 months (17868)

l. DSI with baghouse: 50+ months (17886)

Commenter 17868 notes that the EPA’s assumption of faster retrofits is probably incorrect.

Response to Comment 45: Numerous commenters submitted their own evaluation of the length of time 

required to install controls, switch fuels, and upgrade the grid, some of it based on their own experience 

from the past. Numerous commenters claimed that actual project execution timeframes exceeded the 

time allotted by the proposed rule. To illustrate the point, some commenters referenced specific retrofit 

project elements with asserted time requirements for their completion as part of the retrofitting process. 

The EPA does not agree with commenters that lengthy retrofit schedules from various individual prior 

projects are dispositive of the power sector’s ability to install cost-effective retrofits under the MATS 

schedule. Project schedule length is heavily influenced by resource dedication and execution method. 

While any project can be executed at a slow pace, the EGU pollution controls industry developed into a 

mature industry in response to the Acid Rain Program, the NOX SIP Call, and CAIR with the ability to 

perform accelerated project execution using a faster and more efficient Design-Build process. The power 

sector has realized considerable efficiency gains through integrating standardized equipment designs, 

systems approach, and modular construction techniques as well as the formation of business alliances1 

to reduce frictional time lags.

A typical control retrofit project consists of the following elements, several of which may occur 

simultaneously: site studies, conceptual engineering, equipment sizing, and cost estimating, planning, 

detailed design, procurement, construction, commissioning/testing, and permit application. For designbuild methodology, the project is divided into two major phases: pre-award work requiring minor 

expenditures (site studies, conceptual engineering, equipment sizing, cost estimates, schedule planning) 
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and award work requiring significant capital commitment (detailed design, procurement, construction, 

commissioning/testing).

Pre-award work elements are typically executed sequentially since each preceding stage’s results inform 

the following stage; however, award work elements can be executed with “Lean Construction”

techniques to shorten time frames. Since a typical emission control device is a combination of, rail car 

unloading, waste water treatment, and dewatering facility occupy different plant site locations; thereby, 

allowing simultaneous design, procurement, construction, and testing activities. To illustrate the point, 

Asheville Power station FGD retrofit was completed on a 26 month schedule. Constellation’s FGD, 

fabric filter, and activated carbon retrofit was completed in 29 months from notice to proceed. Presque 

Isle’s 3-unit fabric retrofit was completed in approximately 2 years.

The examples cited by commenters fail to account for the adoption of proven faster execution methods 

evidenced by numerous units that have demonstrated FGD retrofit project completion in less than 30 

months. In particular, commenters who cite examples of lengthy or delayed retrofit schedules from 

projects conducted during the highly uncertain period of the CAIR remand (when it was prudent to 

proceed cautiously) cannot reasonably expect such experiences to apply to retrofit project execution 

with the benefit of renewed regulatory certainty gained by promulgation of the final MATS rule (when it 

is prudent to proceed expeditiously and with confidence).

Evidence that almost all future APC retrofits can be completed far more quickly than were historical 

APC projects derives in part from a comparison of past APC schedules to the project schedule for an 

entire new coal-fired unit, including its APC systems. Springerville Unit 3, for example, is a 400 MW 

coal-fired unit that became operational in July 2006, some 33 months after the turnkey engineeringconstruction contractor was given a notice to proceed with engineering.5Springerville was clearly on an 

accelerated schedule, as its original planned schedule was about 38 months. The main point here is that 

typical schedules for large complex power projects can be significantly accelerated. Because the scope 

of the work involved for an entire new coal unit is at least five times that of a retrofit wet FGD system, 

EPA believes that even the most complex retrofit APC project can be significantly accelerated as well. 

The recently surveyed wet FGD project schedules are not all representative of the shorter project 

schedules that EPA expects to be prevalent under the MATS Rule. Some of these projects were 

conducted in a period of regulatory uncertainty without a strong driver for accelerated retrofit 

completion, tie-in, and subsequent operation – particularly where initiating such operation increases 

marginal operating costs without a certain regulatory benefit. Factors that will likely accelerate project 

schedules under the Toxics Rule include the use of overtime and/or two-shift work schedules during 

construction, and 5- or 6-day work weeks, instead of the 4-day x10-hr schedules often used to minimize 

cost when time is not of the essence. Increased use of offsite modularization and pre-fabrication of APC 

components can also shorten schedules and reduce job hours. Also, many of the wet FGD projects 

performed in response to CAIR or to other legal actions in the same time frame took longer to perform 

than under normal market conditions due to the initial high demand for a large number of complex wet 

FGD systems in a short period of time. Extended lead times in the 2007/2008 time period, as high as 18 

months for key wet FGD engineered equipment (such as large recycle pumps, large motors, and 

chimneys) contributed to extended wet FGD project durations. Increased lead times quickly subsided as 

the supply chain processed the initial influx of orders for this equipment. Neither the proposed Cross 

State Rule nor the MATS Rule, however, is projected to require a significant number of large, complex 

wet FGD systems. The relatively much simpler dry FGD, flabric filter, and other even simpler DSI and 

ACI systems that may be required under the Mercury and Air Toxics rule will take significantly less 

time to plan, design, install, and commission than wet FGDs.
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5. One-year extension.

Comment 46: The EPA requested comment on a 1-year extension under section 112(i)(3) for 

“installation of controls.” Multiple commenters (18023, 9738, 17297, 17638, 17648, 17696, 17758, 

17775, 17810, 17818, 17841, 17843, 17870, 17886, 18025, 18037, 18424, 18426, 18428, 18440, 19114) 

agree with the extension.

Commenter 18025 states that in the limited cases of extensions beyond 3 years, it will be important for 

the EPA to ensure that a company uses the additional time to install controls or test the installation of 

controls and to ensure a unit is only dispatched for reliability purposes so that it does not receive any

undue economic gain as a result of an extension.

Multiple commenters (18023, 17297, 17385, 17638, 17696, 17701, 17758, 17775, 17820, 18426, 18434, 

18439) ask that the 1-year extension apply in other cases as well. Multiple commenters (18023, 17297, 

17758, 17775, 17820, 17886, 19114) also support applying the extension to transmission upgrades. 

Commenter 19114 asks that the extension should apply if additional gas supply lines must be 

constructed or replaced, or if required state and federal regulatory approvals to retire the capacity cannot 

be obtained.

Commenter 17385 asks for clarification of whether energy efficiency and fuel switching measures can 

count as “controls.”

Commenter 18434 stated that this extension should also apply to on-site non-conventional replacement 

generation through combined heat and power and waste heat recovery. According to the commenter, 

restricting replacement power to on-site equipment significantly reduces opportunities for facilities to 

invest in clean replacement power and consider retirement as a compliance strategy. The commenter 

states that this approach has multiple advantages.

Several commenters (18434, 18439, 19114) ask the EPA to clarify that retirement and any clean 

replacement power that complies with the NESHAP rule, including off-site combined heat and power 

and waste heat recovery, can be deemed “controls” under the CAA, thereby allowing the same 1-year 

extension to apply. Commenter 18439 notes that the EPA should clarify that energy efficiency and fuel 

switching measures can count as controls for purposes of eligibility for a 1-year extension for 

compliance if additional time is needed for installation. Commenter 19114 notes that the timeline for 

constructing a new combined cycle unit is similar to that for retrofitting an FGD system on an existing 

unit, and could not be completed within a 3-year window.

Several commenters (19536, 19537, 19538) believes that: Shut-down of an existing unit is within the 

definition of a pollution “control” under section 112, as well as under the CAA generally. The 

commenters state that section 112 uses “emission control” broadly to refer to pollution reductions of any

sort(see, e.g., 42 U.S.C. §7412(d)(3), (d)(5), (d)(6), & h(1) (all using “control” to refer to pollutionreduction and referring to “emission control” achieved by “best controlled similar source”)), that in 

keeping with that general synonymy, section 112 defines “maximum achievable control technology”

limit as a limit reflecting the “maximum degree of reduction” achievable(42 U.S.C. §7412(d)(2) & 

(g)(2)), and the statute confirms that any “measure,” “method” or “technique” that reduces hazardous air 

pollution may be prescribed to accomplish the necessary limitation(42 U.S.C. §7412(d)(2)). The 

commenters state that elsewhere in the statute, as well, the term “control” is defined broadly enough to 

include the cessation of polluting operations. See, e.g., 42 U.S.C. §7479 (defining “best achievable 

control technology”). According to the commenters, closure of a high-polluting unit is a measure that 
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reduces pollution, and is therefore a “control” under the CAA. The commenters state that the EPA has, 

accordingly, recognized in its consent decrees that shut-down is under some circumstances a method of

pollution-reduction that is a “control technology” within the meaning of the CAA. See, e.g., Consent 

Decree, United States v. Tampa Electric Co., Civ. No. 99-2524 (M.D. Fla. 204) at 7-8 (prescribing 

permanent shut-down amongst “emissions reductions and controls” required to comply with CAA). 

According to the commenter, consequently, the word “control” in section 112 encompasses the shutdown of a polluting unit, and “installation of controls” should be understood to include the on-site 

physical operations required to accomplish permanent shut-down. Also according to the commenter, the 

accompanying term “practicable,” in section 112(i)(3)(A), allows the EPA to consider the need to 

provide replacement power necessary to permit such a permanent shut-down. The commenter states that 

section 112(i)(3) allows the EPA (or state agencies) to provide up to 1 additional year to an existing 

source where “necessary for the installation of controls,” 42 U.S.C. §7412(i)(3)(B), while also 

establishing that controls are to be installed “as expeditiously as practicable,” 42 U.S.C. §7412(i)(3)(A). 

The commenter states that whether an extension is “necessary” for the installation of controls must be 

informed by whether those controls can “practicabl[y]” be put in place at an earlier date. According to 

the commenter, read together, sections 112(i)(3)(A) & (B) allow an extension of up to 1 year to be 

granted on a case-by-case basis for facilities at which controls cannot practicably be installed within 3 

years. The commenter states that the EPA has, elsewhere in its proposed rulemaking, considered 

reliability to determine the pace at which controls can practicably be installed (see 76 FR 25,054, 25,056 

& nn. 177-178 (describing EPA’s efforts and intention to work with FERC, NERC, the Department of 

Energy, and regional transmission organizations on issues related to compliance and reliability, 

particularly in the event unit shutdowns occur in load-constrained areas)).

Commenter 18426 states that the extension, with the factors and conditions for qualifying and applying 

for the extension, needs to be part of the rule. The commenter provided Michigan’s conditions for that 

state’s Hg rules.

Commenter 18034 requests clarification, as the commenter is unaware of any precedent for such an 

interpretation of the CAA. The commenter states that while the EPA’s attempt at flexibility through this 

interpretation is clear, the commenter is unclear as how other parts of the proposed NESHAP rule should 

be interpreted and enforced given this new interpretation and poses the following questions: Would such 

a reconstructed facility be held to the new or reconstructed EGU emission limits in Table 1 or the 

existing EGU emission limits in Table 2? How does the EPA reconcile this interpretation with the 

proposed requirement in section 63.9984(a) that a new or reconstructed EGU must comply by the date 

of the final rule published in the Federal Register or upon restart of the EGU, whichever is later? Is this 

interpretation limited to just EGUs or may states apply this same approach to existing sources subject to 

other NESHAP rules, for example, a Portland cement kiln subject to the EPA’s recently finalized 

Portland cement NESHAP rule?

Commenter 19122 states that the 1-year extension process seems to apply only to the installation of 

control equipment and not for installation of systems such as CEMS and BLDS. The commenter

recommends that the EPA provide an extension process for procurement of emission monitoring/BLDS 

as well as for installation of control equipment and streamline the extension process such that a source 

can be granted an extension if good faith efforts have been made to meet compliance.

Commenter 17868 outlines the EPA prediction that the industry will have very little problem in meeting 

the 3-year compliance schedule proposed in the regulation if the additional year of compliance time is 

provided to “some” units. The commenter provides their key assumptions supporting this conclusion as:
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1. The use of low-cost, simple, DSI systems to control acid gases, instead of more complex FGD 

systems;

2. Faster retrofits than similar projects in the past;

3. Compliance requirements of other regulations have no impact on HAP compliance;

4. The small number of projected retirements, about 10 GW of coal capacity;

5. Early planning action by regulated utilities; and

6. Early planning action by RTOs.

Comment 47: Multiple commenters (16850, 17004, 17026, 17887, 18539) comment on retiring or 

repowering units.

Commenters 17004 and 17026 request that the EPA allow power companies to operate their plants as 

efficiently as possible, including allowing units that are already scheduled to shut down to operate on a 

restricted basis without installing additional controls, as they upgrade their facilities and move toward 

new generation.

Commenters 18434 and 18439 ask the EPA to clarify that retirement and any clean replacement power 

that complies with the NESHAP rule, including off-site combined heat and power and waste heat 

recovery, can be deemed “controls” under the CAA.

6. Extensions for retirement and replacement power.

Comment 48: Several commenters (18023, 17638, 17696, 17820, 17821) ask that the provision to allow 

a 1-year extension apply to all retirements.

Multiple commenters (17841, 18426, 18434, 18441, 18442 18448) ask that a 1-year extension be 

provided for possible unit retirements, retrofits, or repowering. Several commenters (18434, 18441, 

19114) note that this extension should apply to off-site power generation in limited circumstances. 

Commenters 18031 and 18442 ask that the maximum amount of time allowable be available for these 

actions.

Commenter 17677 states that for units that elect to shutdown, the EPA should allow significant 

automatic extensions upon notification of elected unit shutdown. According to the commenter, this will 

allow the source sufficient time to permit and construct a replacement facility or contract additional 

power that will most likely have to be constructed.

Commenter 19506 states that the EPA should consider allowing units that a company has scheduled to 

be shut down to continue to operate beyond the compliance deadline until other units owned by the same 

company have been fully retrofitted.

Commenter 18450 opposes allowing a fourth year for compliance when building replacement power 

unless the source can demonstrate an electric reliability issue.

Commenter 18039 objects to granting 1-year extensions for facilities that are building replacement 

power. According to the commenter, the EPA should avoid allowing a facility in the process of building 

replacement power, and that would otherwise shut down an existing high-emitting unit at the 3-year 

compliance deadline, to operate such existing high-emitting unit for an additional year, specifically due 

to the 1-year extension. The commenter states that in addition, if designing, permitting and constructing 
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replacement power continues beyond a 1-year extension, it should be stressed that the CAA does not 

allow MACT compliance extension beyond 1-year, whether or not a replacement unit has come on-line.

Commenter 18441 notes that the 1-year extension request, if granted, may create incentives for 

generation owners faced with compliance decisions to wait as long as possible to submit their 

deactivation requests to their regional transmission organization in the hope they can get their units 

extended beyond the January 1, 2015 compliance deadline if their units are deemed by the regional 

transmission organization in its subsequent deactivation study to be Reliability Critical Units. According 

to the commenter, in this case, generator owners can effectively attempt to extend the life of their units 

for an additional year or more with no intention of installing retrofits by simply delaying their 

deactivation request so they can effectively side-step compliance with the final rule through a potential 

misuse of the extension process contemplated herein. The commenter requests the EPA provide 

guidance in the final rule that such an extension for deactivating units only be granted if the unit owners 

provide the regional transmission organization, with a copy to the EPA, with notice of deactivation by

the earlier of 12 months from the effective date of the final rule, or January 1, 2013, a full 2 years in 

advance of the January 1, 2015 compliance deadline. The commenter notes that nothing in this proposal 

should be read as limiting the ability of units which are retrofitting but cannot complete such work by

the compliance deadline from also being eligible for a compliance extension. The commenter states that 

nothing in this proposal eliminates a generating owner from petitioning the Secretary of Energy to 

excise its authority under section 202(c) of the Federal Power Act and section 301(b) of the Department 

of Energy Organization Act to order the unit remain operational, and nor would this preclude a generator 

from working with the EPA to establish a compliance schedule.

Response to Comments 46 - 48: The EPA believes that although most units will be able to fully comply

within 3 years, the fourth year that permitting authorities are allowed to grant for installation of controls 

is an important flexibility that will address situations where an extra year is necessary. That fourth year 

should be broadly available where a facility owner has made a clear and diligent effort to install controls 

within the 3-year time frame but is unable to complete the installation. Toward that end, the EPA is 

making it clear that permitting authorities have the authority to grant a 1-year compliance extension 

where necessary. The EPA believes that this fourth year should also be made available when a unit is 

being shut down and the capacity is being replaced on-site by another unit. The EPA believes that 

building of replacement power as part of a strategy to comply with the regulation may be appropriate as 

long as the unit that is running during the additional year optimizes any existing controls, takes 

additional reasonable steps to minimize emissions, and runs only to extent necessary. 

This category of sources is unique due to the large, complex and interconnected nature of electrical 

generation, transmission and distribution, and the criticality of the electric grid to the functioning of all 

aspects of the economy. The grid functions as an interconnected system that supplies electricity to end 

users on a continuous basis. Safe, reliable operation of the grid requires coordination among actions 

taken at individual units, including timing of outages for the installation of controls, derating, or 

deactivation. It was for this reason that we believe that a reasonable interpretations of the phrase 

“installation of controls” in CAA section 112(i)(3)(B) maybe somewhat more expansive than is usually

the case. The EPA believes that the 1-year extension should be available for a unit if a company’s 

compliance choice was to retire that unit but doing so within the 3-year time-frame caused reliability

problems for any of the following reasons: (1) generation from the retiring unit is needed to maintain 

reliability while other units install emission controls; (2) new off-site generation was being built to 

replace the retiring unit, but the new generation was not scheduled to be operational within the 3-year 

time-frame and any gap between the time the existing unit retires and the new unit comes on line would 
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cause reliability problems; and (3) transmission upgrades were needed in order to maintain electric 

reliability after the unit retired but could not be completed within 3 years.

Although the ultimate discretion to provide a 1-year extension lies with the permitting authority, the 

EPA believes that all three of these cases may provide reasonable justification for granting the 1-year 

extension if the permitting authority determines based on information from the RTO or other planning 

coordinator for the relevant region, and/or NERC or one of its regional entities, and/or the FERC or the 

DOE, that continued operation of a particular unit slated for retirement for some or all of the additional 

year is necessary to avoid a violation of applicable FERC-approved or state electric reliability standards. 

In a case where pollution controls are being installed, or onsite replacement power is being constructed 

to allow for retirement of older, under-controlled generation, a determination that an extra year is 

necessary for compliance should be relatively straightforward. In order to install controls, companies 

will have to go through a number of steps fairly early in the process including obtaining necessary

building and environmental permits and hiring contractors to perform the construction of the emission 

controls or replacement power. This should provide sufficient information for a permitting authority to 

easily determine that emission controls are being installed or that replacement power is being 

constructed. It should also provide information to determine whether the company is working 

expeditiously to comply, and whether the construction schedule will nonetheless exceed the 3-year 

compliance window. Because companies will need to develop this information early in the process and 

because a determination can easily be made as to whether the schedule will exceed 3 years, EPA 

believes that Title V permitting authorities should be able to quickly make determinations as to when 

extensions are appropriate.

In the three cases related to retirement of a unit without construction of onsite replacement power, 

additional information is needed. The title V permitting authority should request that the affected 

company or companies provide information from the relevant RTO or other planning coordinator and, 

where appropriate, the state electric regulatory agency, and/or NERC or its regional entities, and/or 

FERC – demonstrating that retirement of a particular unit within the 3-year compliance period would 

result in a violation of applicable FERC-approved or state reliability standards. 

The first two situations involving a retiring unit – where one or more related existing units are upgrading 

pollution controls or a new unit is being constructed off-site – are similar to the situation we discussed in 

the proposed rule wherein a retiring unit at a facility runs an additional year while a replacement unit on 

the same site is constructed. In each of these situations, the retiring unit would be allowed to run so a 

unit compliant with the rule (either a retrofitted existing unit or a new unit) can come on line. We 

believe that these situations may, in the appropriate circumstances, constitute ones in which a 1-year 

extension for the retiring unit is “necessary for the installation of controls”. In these two situations, 

however, we believe that it would be appropriate for the title V permitting authority to consider 

reliability concerns as a necessary factor before granting the additional year – because continuing 

operation of the retiring unit is only “necessary” to the extent it is required for reliability. In both of 

these two situations, the permitting authority should determine that the retiring unit is necessary to 

maintain reliability until the new unit comes on line or the other existing unit is retrofitted. Title V 

permitting authorities may determine that multiple retiring units are available to maintain reliability, but 

unless all the units are necessary to address the issue, it would likely be unreasonable to provide the 

additional year for all the identified units. 

The third hypothetical situation identified above is one in which transmission upgrades are necessary to 

address a reliability issue resulting from the retirement of a unit in order to comply with this rule, where 

the upgrade cannot be completed by the 3-year compliance date. In terms of the functionality of the 
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electric grid, this situation has some similarity to those discussed above. Here, it is the completion of the 

transmission upgrades, rather than bringing another compliant (retrofitted or new) unit on line, that 

would allow the retiring unit to come into compliance (by retiring) without threatening reliability. The 

general objective and result, however, is similar – reductions of the existing unit’s HAP emissions 

(through retirement) while maintaining electric reliability. If such situations develop, permitting 

authorities should consider whether – where the reliability problem has been properly demonstrated, as 

discussed above – an extension under CAA section 112(i)(3)(B) may be provided. 

The EPA continues to believe, based on the analysis discussed at the beginning of this section, that most, 

if not all, units will be able to comply with the requirements of this rule within 3 years. The EPA also 

believes that making it clear that permitting authorities have the authority to grant a 1-year compliance 

extension where necessary, in the range of situations described above, addresses many of the other 

concerns that commenters have raised. The EPA believes that the number of cases in which a unit is 

reliability critical and in which it is not possible to either install controls on the unit or mitigate the 

reliability issue through construction of new generation, transmission upgrades, or demand-side 

measures, within 4 years, is likely to be very small or nonexistent. This view is echoed by commenters 

explicitly mandated with ensuring grid reliability.

7. Issues and costs that need to be considered in determining compliance date.

Comment 49: Multiple commenters (16469, 16849, 17403, 17406, 17640, 17722, 17730, 17732, 17734, 

17752, 17756, 17757, 17758, 17770, 17774, 17812, 17813, 17815, 17817, 17820, 17821, and 17868, 

17876, 17881, 17912, 17925, 17931, 18033, 18037, 18422, 18424, 18428, 18440, 18442, 18447, 18498, 

18500, 19114, 19122, 19506) are concerned about the availability of qualified construction and technical 

labor, as well as availability of equipment.

Multiple commenters (8443, 17383, 17608, 17697, 17722, 17767, 17812, 17868, 17911, 18038, 18419, 

18498, 18575) are concerned about the competition between small utilities and larger utilities, for 

equipment and labor.

Commenter 18433 states that it will be difficult for facilities in remote areas to get vendors and 

contractors to respond to requests-for-proposals for a single opportunity to sell an ESP when large 

utilities will also be seeking larger quantities of such equipment from the same vendors.

Commenters 19032 and 19653 believe that too many activities must be coordinated and completed to 

comply with the proposed rule. The commenter states that these activities include emissions testing to 

determine what type of capital equipment or upgrades will be required to facilitate compliance, 

Designing/engineering, permitting, securing financing, construction, start-up and acceptance testing.

Comment 50: Multiple commenters (16849, 17403, 17731, 17752, 17757, 17774, 17775, 17821, 

18428) are concerned about major tie-in outages, especially during low peak seasons.

Commenter 18477 does not have shoulder months like the contiguous U.S. Therefore, according to the 

commenter, there are no specific time periods when outages can occur without impacting electric 

reliability.

Response to Comments 49 - 50: In both the preamble to the rule and in greater detail in the TSD, the 

EPA has assessed the feasibility of installing these controls within the compliance window and believes 

that the controls can be reasonably installed within that time. Although the EPA assessed the ability to 
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install the controls in 3 years (and determined that the controls could be installed in that time-frame), 

this would require the control technology industry to ramp up quickly. Therefore, the EPA also assessed 

a time-frame that would allow some installations to take up to 4 years. This time-frame is consistent 

with the CAA which allows permitting authorities the discretion to grant extensions to the compliance 

time-line of up to 1 year. This time-frame also allows for staggered installation of controls at facilities 

that need to install technologies on multiple units. Staggered installation allows companies to address 

such issues as scheduling outages at different units so that reliable power can be provided during these 

outage periods or particularly complex retrofits (e.g., when controls for one unit need to be located in an 

open area needed to construct controls on another unit). In other words, the additional 1-year extension 

would provide an additional two shoulder periods to schedule outages. It also provides additional 

opportunity to spread complex outages over multiple outage periods. The EPA believes that while many

units will be able to fully comply within 3 years, the 4th year that permitting authorities are allowed to 

grant for installation of controls is an important flexibility that will address situations where an extra 

year is necessary. The EPA expects that state permitting authorities will make the fourth year available 

where it is warranted. In addition where necessary to avoid a violation of applicable FERC-approved 

electric reliability standards the EPA can use existing CAA authorities to allow additional time to come 

into compliance.

Comment 51: Multiple commenters (8443, 17123, 17297, 17406, 17623, 17716, 17732, 17756, 17716, 

17752, 17758, 17820, 17842, 17912, 18024, 18419, 18422, 18440, 18502, 19121) are concerned about 

financing these projects and the likely cost increases for labor and equipment likely to occur over this 

compliance period.

Multiple commenters (17254, 17406, 17842, 18422, 18437, 18502, 18539, 18575, 19653) are concerned 

that these increased costs could affect the affordability of electricity.

Response to Comment 51: The EPA has not observed financing obstacles for pollution control retrofits 

under its previous programs. The EPA includes publicly-reviewed financial assumptions regarding 

pollution control investments with its IPM modeling of the power sector. Furthermore, the financial 

industry views utilities with large customer bases (e.g., AEP, Duke, Edison Intl., Southern Co., TVA) as 

less risky to finance due to the consistent, ample revenue stream. To reduce financing risk, utilities have 

the option to award “fixed price” contracts with penalties for exceeding price limits or LD’s (liquidated 

damages) for schedule and/or performance default. Considering the past successes of the pollution 

control industry regarding retrofits, the EPA believes the financial markets will supply adequate capital 

for units pursuing retrofit under the final MATS.

Although costs could increase during the compliance period, the EPA anticipates the first wave of 

retrofit controls orders to be less costly than recent historical prices since suppliers shall compete for 

work to utilize idle resources. For example, in June 2011 NIPSCO awarded B&W a contract worth $54 

million for two wet scrubbers at R.M. Schahfer Generating Station with an operational date of autumn 

2013 and 2015 for units #14 (465 MW) and #15 (515 MW), respectively. In another example, Colorado 

Springs Utility plans to retrofit its 254 MW Martin Drake unit with a FGD for $113 million with 

projected construction completed by 2014. The EPA expects therefore that the costs it has used in its 

IPM modeling will be accurate over the life of the compliance period. Documentation for IPM can be 

found in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epaipm/index.html

Comment 52: Multiple commenters (18023, 17254, 17640, 17689, 17705, 17716, 17730, 17731, 17761, 

17767, 17774, 17808, 17813, 17820, 17821, 17824, 17837, 17841, 17876, 17902, 17931, 18033, 18038, 
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18419, 18422, 18424, 18428, 18430, 18441, 18442, 18500, 18539, 18575, 19114, 19653) are concerned 

about grid and electricity reliability.

Commenter 18441 states that the larger regional adequacy impacts can only be determined once the 

impact of the final rule has been analyzed and units have made their individual retrofit vs. retirement 

decisions. The commenter believes that the EPA understates the number and size of retirements.

Comment 53: Many commenters (16549, 17055, 17701, 17137, 17697, 17716, 17724, 17725, 17743, 

17745, 17757, 17761, 17774, 17775, 17813, 17791, 18038, 18437, 18433, 17887, 17930, 18448, 18540, 

19506, 19199) express concern that the EGU MACT will jeopardize the reliability of the U.S. electricity

supply by reducing generating capacity through early retirement of EGUs. 

Numerous commenters (16549, 17055, 17701, 17137, 17697, 17716, 17724, 17725, 17743, 17745, 

17757, 17761, 17774, 17775, 17813, 17791, 18038, 18437, 18433, 17887, 17930, 18448, 18540, 19506, 

19199) express concern that the EGU MACT will jeopardize the reliability of the U.S. electricity supply

by reducing generating capacity through early retirement of EGUs. Some commenters (18034, 18538, 

18907) believe that the EGU MACT may result in rolling blackouts that have economic impacts. 

Commenter 18034 notes that without reliable, affordable electricity, sensitive populations, such as 

elderly citizens, may be at risk during severe winter weather or hot summer temperatures.

Comment 54: Commenter 18023 believes the loss of generation capacity caused by early retirement of 

EGUs would undermine the operational support that is critical to maintaining balance, resilience, and 

contingency response capability on the bulk power network. The commenter believes the EPA has 

overlooked the critical role generation capacity plays in providing grid stability.

Comment 55: Numerous commenters (16705, 17055, 17254, 17400, 17403, 17608, 17627, 17761, 

17765, 17804, 17813, 17857, 17901, 17911, 17813, 17901, 17904, 17911, 17919, 17930, 18034, 18038, 

18437, 18441, 18497, 18500, 18538, 18575, 18023) believe that the EPA has underestimated the 

number of EGU retirements. Many commenters (16705, 17055, 17403, 17761, 17765, 17627, 17761, 

17813, 17901, 17911, 17813, 17901, 17904, 17911, 17919, 17930, 18034, 18038, 18437, 18441, 18497, 

18500, 18538, 18575, 18023) cite independent projections that estimate capacity retirements will be 

much higher than the EPA’s estimate. The independent projections cited by commenters include:

 Potential Coal Plant Retirements Under Emerging Environmental Regulations, The Brattle

Group, December 8, 2010 (estimate 67 GW will be retired as a result of the EGU MACT);

 Potential Impacts of Environmental Regulation on the U.S. Generation Fleet, Edison Electric 

Institute, prepared by ICF International, January 2011 (estimate 50to 70 GW will be retired as a 

result of the EGU MACT in conjunction with other new EPA regulations).

 Review of the Potential Impacts of Proposed Environmental Regulations on the ERCOT System, 

Electric Reliability Council of Texas, May 11, 2011 (predicts that by 2016, the base case 

scenario will lead to 11 GW of retirements in the state of Texas to all forms of generating 

capacity, leaving only a -2.3% reserve margin);

 US Department of Energy (Deputy Assistant Secretary, James Wood) (suggested that the 

approval of new rules for air pollution, water pollution and waste disposal could result in the 

retirement of up to 70 GW of coal-fueled power generation nationwide. Woods highlighted that 

these retirements will increase electric rates and lead to pronounced transmission grid reliability 

issues “...both because of the shutdowns and because of the intermittency of renewables.”).
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 Ira Shavel & Barclay Gibbs, Charles River Associates, “A Reliability Assessment of EPA’s 

Proposed Transport Rule and Forthcoming Utility MACT” (Dec. 16, 2010)(estimate 39 GW will 

be lost through early retirement).

 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. 

Environmental Regulations, North American Electric Reliability Corporation, October 2010 

(Estimate that 78 GW from coal, oil, and gas EGUs will be lost through early retirement over the 

next 10 years).

 U.S.Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and 

Who Loses?, Bernstein Research, October 2010. (estimate that close to 60 GW of coal fueled 

capacity will find it “uneconomic” to install MACT and will shut down. Also predicts that 

capacity margins would decrease by 7 to 15 % and reliability is forecasted to go down).

 NERA Economic Consulting, May 2011 (estimates 48 GW of additional coal-fired generating 

capacity will retire prematurely by 2016).

 PIRA (states that over 160 GW of coal units do not currently have scrubbers installed. Of these, 

about 55 GW have announced plans for scrubber retrofits, leaving a potentially large universe 

(over 105 GW) of “vulnerable coal units.”).

 Credit Suisse, April 26, 2011 (predicts that at a 60 GW retirement capacity and suggests an 

additional 24 GW would be needed to maintain reserve margins at 15 %).

Some utilities provide projections of the capacity they anticipate retiring as a result of this rule. These 

include:

 Commenter 17627 estimates that 5.4 GW of coal-based generation capacity will be lost as a 

result of the EPA’s regulations;

 Commenter 17757 estimates that 5 coal-fired plants (6,000 MW) will be shut down as a result of 

the EGU MACT.

 Commenter 17821 plans to retire 6 units, or 1,125MWs of coal fired capacity at the W.C. 

Beckjord Station by January 1, 2015, principally due to the EGU MACT rule.

 Commenter 17821 plans to retire the 163 MW Miami Fort Unit 6 on January 1, 2015.

 Commenter 17821 estimates that approximately 1,574 MWs of additional coal-fired capacity is 

at risk of shutdown due to new or pending EPA regulations, including the EGU MACT rule.

Comment 56: Commenters 17919 and 18033 refer to statements made by FERC that acknowledge 

FERC’s preliminary assessment on the impact of EPA rules on coal-fired generating capacity “showed 

40 GW of coal-fired generating capacity ‘likely’ to retire, with another 41 GW ‘very likely’ to retire.”

(see letter dated August 1, 2011 from the FERC Chairman John Wellinghoff). Commenter 17919 also 

quotes from another letter from FERC Commissioner Marc Spitzer in which he argues that regulated 

entities should not have to make such a “Hobson’s” choice between EPA regulations on reliability

and entities’ requirements to uphold FERC-approved reliability standards. Commenter 18033 claims that 

the EPA has failed to document its discussions with FERC on the impacts of the EGU MACT on electric 

system reliability. This commenter believes it is inappropriate for the EPA not to include a record of 

those discussions in the rulemaking docket and that by not doing so the EPA has not adhered to the 

statutory requirements of the CAA, which requires the EPA to provide the public with an opportunity to 

review and comment on these documents.

Commenter 18033 states that the EPA also attempts to fall-back on early collaboration with key

stakeholders to prevent the potential for skyrocketing electricity prices and job losses. According to the 

commenter, the agency states that, “[i]n addition, EPA itself has already begun reaching out to key

stakeholders including not only sources with direct compliance obligations, but also groups with 
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responsibility to assure an affordable and reliable supply of electricity including state Public Utility 

Commissions (PUC), Regional Transmission Organizations (RTOs), the National Electric Reliability 

Council (NERC), the Federal Energy Regulatory Commission (FERC), and DOE.” The EPA further 

states, “[i]t is EPA’s understanding that FERC and DOE will work with entities to ensure an affordable, 

reliable supply of electricity...” The commenter states that it can find no evidence of these consultations 

in the rulemaking docket and that the public has no ability to discern whether EPA is presenting the 

implications of this rule with its overly optimistic DSI assumption thereby coloring the perceptions of 

the stakeholder. The commenter states that as of October 2010, NERC as one of the identified 

stakeholders did not share the EPA’s view of de minimus impacts to electric power generating sector. 

According to the commenter, overlapping compliance schedules for the air and solid waste regulations, 

along with the required compliance for rule 316(b) following shortly thereafter, may trigger a large 

influx of environmental construction projects at the same time as new replacement generating capacity is 

needed. The commenter states that such a large construction increase could cause potential bottlenecks 

and delays in engineering, permitting and construction. The commenter asserts that based on this 

assessment, either NERC has changed its position since this time to align with the EPA based on 

information not included in the rulemaking docket, or the EPA is not being forthcoming about the reality

of these “collaborations” to deal with this important issue. The commenter states that in any event, and 

unsurprisingly, the foregoing demonstrates that FERC – responsible for delivering reliable electricity to 

the country – is not as confident in the EPA’s assessment of the situation as the EPA portrays it to be. 

Following FERC’s responses to Senator Murkowski, the commenter joins the Senator’s extreme concern 

with the impending situation, as described in her August 3 press release, “[h]aving received FERC’s 

responses this week, I must say that I am now less confident [after initially hearing the Chairman’s plans 

for an interagency task force] of that being the case.” The commenter states that preliminary review of 

FERC’s responses completely validates her position. 

The commenter states that in response to the EPA’s exaggerated representations in the preamble, 

Chairman Wellinghoff stated in his letter, “...this information assessment offered only a preliminary 

look at how coal-fired generating units could be impacted by EPA rules, and is inadequate to use as a 

basis for decision-making, given that it used information and assumptions that have changed” (emphasis 

added). The commenter states that this sentiment is further confirmed in Commissioner Moeller’s 

response, “[a]ccording to OER staff, EPA’s reliability analysis has been limited,” and that staff have, 

“pointed out to EPA that a reliability analysis should explore transmission flows on the grid, reactive 

power deficiencies related to closures, loss of frequency response, black start capability, local area 

constraints, and transmission delivery” (emphasis added). According to the commenter, in sum, the 

EPA’s “trust us” mentality has far underestimated the complexity underlying the delivery of affordable 

and reliable electricity. 

The commenter states that this is further evidenced by the fact that neither FERC nor the EPA has 

conducted a cumulative impacts analysis and that FERC’s assessment that 81 GW of “likely or very 

likely” retirements may result from the implementation of this suite of rules, further highlights the need -

- as expressed by the commenter – for a more transparent and open process to deal with these important 

issues. The commenter states that recognizing the Chairman’s reservations about the results of this 

preliminary study, it nevertheless highlights the EPA’s failure to disclose this critical study and any 

other material that may exist regarding the EPA-FERC consultation process.

The commenter joins Commissioner Moeller’s recommendations to have FERC: (1) use its expertise to 

perform an analysis of the EPA’s rules that could impact reliability of electricity – and disclose that 

analysis for public comment – and then hold a technical conference for public input; and (2) have the 
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EPA extend the timing of these regulations as the agency’s schedule “does not conform to the relevant 

planning horizons in the electric sector of our economy, one of the most capital-intensive sectors of 

industry.”

The commenter states that understatement of potential coal-fired EGU retirements and electricity prices 

will be especially acute if the EPA holds the line with its new source emissions limits. The commenter 

states its belief that the new source emissions standards are based on the impermissible HAP-by-HAP 

approach, which makes it difficult to foresee investment in new coal. According to the commenter, 

Credit Suisse projects that at a 60 GW retirement figure, there would need to be an additional 24 GW 

just to maintain reserve margins at 15% begging the important question of where will coal-dependent 

regions of the county replace these important sources of energy. The commenter states that despite the 

EPA’s effort to “level the playing field,” the agency has done an inadequate job of informing the public 

as to the consequences of such a policy and that the public will only be able to confirm if the EPA 

includes all of the relevant documents regarding this particular issue. The commenter asserts that the 

public is entitled to an opportunity to inspect these documents and provide comment.

The commenter states that the failure to provide evidence of the communication between FERC and 

other key stakeholders regarding the electric reliability issue is inexcusable and that the EPA cannot 

claim it has adhered to the statutory requirements of the CAA without installing all records related to 

these consultations and permitting the public an opportunity to meaningfully comment. The commenter 

asserts that given FERC’s reservations about the EPA’s portrayal of the situation, there is a glaring need 

for more serious collaboration on this issue with an opportunity for public participation and that the EPA 

must not sacrifice electric affordability and reliability at the feet of an arbitrary regulatory calendar. 

According to the commenter, these are errors that are directly at odds with the rulemaking requirements 

under section 307(d). The commenter states that under paragraph (d)(3), a “notice of proposed 

rulemaking...shall be accompanied by a statement of its basis and purpose,” and this statement “shall 

include a summary” of the “factual data on which the proposed rule is based;” and the “methodology

used in obtaining the data and in analyzing the data,” and that paragraph (d)(3) instructs that “[a]ll data, 

information, and documents referred to in this paragraph shall be included in the docket on the date of 

publication of the proposed rule.” According to the commenter, the EPA has not followed these 

statutory commands as the requirement to provide “all data” on which the proposal was based was not 

included in the preamble nor in the docket at the time the proposal was published in the Federal 

Register.

The commenter states that the D.C. Circuit Court of Appeals has held that the public notice and 

comment requirements “are designed (1) to ensure that Agency regulations are tested via exposure to 

diverse public comments, (2) to ensure fairness to affected parties, (3) to give affected parties an 

opportunity to develop evidence in the record to support their objections to the rule and thereby enhance 

the quality of judicial review.” According to the commenter, these objectives have been undermined in 

this rulemaking process, and there are indications in the preamble that regardless of the public input, the 

EPA has a predetermined outcome in mind when it crafted these proposed regulations. The commenter 

notes that the proposed rule states, “...EPA expects that sources will begin promptly, based upon this 

proposed rule, to evaluate, select, and plan to implement, source-specific compliance options” and that 

the Court’s holding highlights the issue of whether EPA’s unreasonable timeframe will effectively 

prevent the agency from being responsive to public comments.

Comment 57: Commenter 19114 believes that the EPA has not taken into consideration the impact of 

upsets or variations in operation, process or fuel specification could have on reliability. Such conditions, 
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the commenter argues, could result in a unit having to be derated or taken off line to remedy the 

situation. The commenter recommends that the EPA more thoroughly examine the impact of process 

upsets on reliability of the electric supply.

Comment 58: Several commenters (17813, 17911, 17930) are concerned that the EPA has 

underestimated the impact of rising demand on electric system reliability. Commenter 17813 argues that 

even without the EGU MACT retirements, the Texas ERCOT grid will struggle to meet rising electricity

demand. They note that Texas is growing at a rate of 1,000 people a day, and that ERCOT anticipates 

capacity shortfalls of at least 7,000 MW in 2015, 18,245 MW in 2020, and 50,000 MW in 2030 to 

maintain a reserve margin of 13.75%. Commenters 17911 and 17930 note that the current electric power 

market has significant excess capacity that is the result of power consumption cutbacks caused by a 

stalled economy. If industry were to return to pre-2008 levels, they argue the market availability and 

market demand would be more closely aligned, and even the EPA’s estimated 9 GW retirement may

have an impact.

Comment 59: Several commenters (17627, 18037, 18441) note that the EGU MACT has already had an 

impact on coal-fired electricity generation. They note that 6,900 MW (11% of PJM coal capacity) did 

not clear the recent PJM capacity market auction completed in May 2011. These commenters believe 

that the coal plant offers, which included anticipated environmental compliance costs, likely did not 

clear the market because they were high relative to demand response offers. They further assert that 

capacity that does not clear in the PJM capacity market auction is likely to be retired and that they

expect a much higher percentage of coal capacity will not clear the 2015/16 capacity auction.

Comment 60: Multiple commenters (8443, 16705, 17400, 17761 17697, 17724, 17804, 17813, 17911, 

17919, 17930, 18034, 18037, 18448, 18538, 19114) believe the EPA’s analysis underestimates the 

potential impacts on electric system reliability because the agency has failed to fully account for the 

potential effects of other related, ongoing and or upcoming regulatory initiatives affecting the electric 

generation sector, including more stringent NAAQS, upcoming emission guidelines for GHG emissions 

(under NSPS as well as related PSD guidance), coal combustion residue (CCR) regulations, and 

regulations under section 316(b) of the Clean Water Act (CWA) for cooling water intake structures. 

Commenter 8843 worries that the “enormous” investments required to comply will lead to reliability 

issues by closing down anywhere from 30-50% of coal-fired power plants. Commenter 17055 worries 

that the EPA has not considered the impact of the RICE regulations that could potential result in the loss 

of the small generators upon which many municipalities rely. They note that elimination of those units 

could create local supply challenges.

Comment 61: Commenter 17725 argues that more time is need to comply with the rule because the 

utilities that participate in the PJM and ISO-NE auctions have already made commitments to supply

power through May 31, 2015. They further note that the last date to submit a delist bid for ISO-NE for 

PY 2015/2016 will have passed before the final EGU MACT is published. 

Comment 62: Several commenters (17774, 17919, 18441) disagree with the EPA’s statements that

reliability challenges related to early EGU retirements can be managed. Commenter 18441 believes the 

RTO/ISO notification procedures are not adequate to meet the magnitude of changes and potential 

retirements that could result from implementation of the proposed rule. Commenter 17774 states that

South Carolina does not have an RTO or ISO to assist in planning. This commenter believes that the 

EGU MACT will cause long-range planning challenges and reliability concerns in the South Carolina, 

because of the lack of RTOs and the significant shutdowns of coal plants in the southeastern U.S. 

Commenter 17919 believes that the industry cannot rely on EPA emergency authorities because the EPA 
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and the U.S. DOE cannot agree on whether or not emergency orders actually forestall agency

enforcement actions. Commenter 19114 is concerned that the EPA has not yet consulted with DOE and 

FERC and worries that the necessary rule coordination or harmonization is not occurring.

Response to Comments 52-62: The EPA has considered the concerns raised by commenters and has 

concluded that given the flexibilities provided in the final rule, the requirements of the final rule for 

existing sources can be met by most sources without adversely impacting electric reliability. In 

particular, the EPA believes that the flexibility of permitting authorities to allow a fourth year for 

compliance should be available in a broad range of situations (as discussed below), and that this 

flexibility addresses many of the concerns that have been raised. Furthermore as indicated below, in the 

event that an isolated, localized concern were to emerge that could not be addressed solely through the 

1-year extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into 

compliance while maintaining reliability.

The EPA considered the impact that potential retirements in response to this rule will have on reliability. 

In considering these impacts, the EPA considered both the analysis it has conducted as well as analyses 

conducted by a number of other groups. The EPA’s analysis shows that the expected retirements of coalfueled units as a result of this final rule (4.7 GW) are fewer than was estimated at proposal and much 

fewer than some have predicted. Because concerns have been raised that the use of DSI may not be as 

prevalent as the agency has predicted and because this could lead to more coal retirements, the agency

also performed a sensitivity analysis in which less DSI systems and more scrubber systems were 

installed. In that sensitivity, we see approximately 1 more GW of retirement. This small change would 

have only a very small potential impact on reliability. When considering the impact that one specific 

action has on power plant retirements, it is important to understand that the economics that drive 

retirements are based on multiple factors including: expected demand for electricity, the cost of 

alternative generation, and the cost of continuing to generate using an existing unit. The EPA’s analysis 

shows that the lower cost of alternative fuels, particularly natural gas, as well as reductions in demand, 

will have a greater impact on the number of projected retirements than will the impact of this final rule.

The EPA’s assessment looked at the capacity reserve margins in each of 32 sub-regions in the 

continental U.S. Demand forecasts used were based on EIA projected demand growth. The analysis 

shows that with the addition of very little new capacity, average reserve margins are significantly higher 

than required. The NERC assumes a default reserve margin of 15 percent while the average capacity 

margin seen after implementation of the policy is nearly 25 percent. Although such an analysis does not 

address the potential for more localized reliability concerns associated with transmission constraints or 

the provision of location-specific ancillary services (such as voltage support and black start service), the 

number of retirements projected suggests that the magnitude of any local reliability concerns should be 

manageable with existing tools and processes.

Several outside analyses have reached conclusions consistent with the EPA’s analysis. For example, in 

August 2010, M.J. Bradley & Associates and the Analysis Group released a report commissioned by

several utilities on the reliability impacts of the MATS and the CSAPR. Their analysis, which examines 

reserve margins, demand trends, industry’s track record with regard to the installation of new capacity

and pollution control equipment, among other factors, concluded that the “electric industry is wellpositioned to comply with the EPA’s proposed air regulations without threatening electric system 

reliability.”

10 In June 2011, they updated the earlier report based on the actual MATS proposal, recent 

 

10 M.J. Bradley & Associates and Analysis Group, August 2011, “Summer 2011 Update: Ensuring a 

Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliability.”
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financial statements from industry, and recent activity in the forward markets for future generating 

capacity. This update “reaffirms the major conclusion of the prior report that the electric industry can 

comply with the EPA’s air pollution rules without threatening electric system reliability provided that 

the EPA, the industry and other agencies take practical steps to plan for the implementation of these 

rules and adopt appropriate regulatory approaches.”

11

In August 2011, PJM Interconnection – the RTO responsible for planning and reliable operation of the 

bulk power system serving all or portions of 13 states in the Mid-Atlantic and Midwestern regions -

issued a report analyzing the impacts of the CSAPR and the proposed MATS rule.12 Although PJM’s 

analysis assumes substantially more retirements than the EPA projects, it nevertheless concludes that 

resource adequacy is not threatened in the PJM region. This is particularly significant, given that the 

PJM region is one of the largest and most heavily dependent on coal-fueled generation in the country. 

The PJM notes, as the EPA has acknowledged, that even where there is adequate generation capacity on 

a regional basis, localized reliability issues may emerge in connection with retirements that may need to 

be addressed.

DOE has recently published a report that looked at resource adequacy in the bulk power system when 

faced with a stress test which was a regulatory scenario far more stringent than the EPA’s regulations. 

For this stress test, in addition to CSAPR and MATS requirements, each uncontrolled electric generator 

is required to install both a wet flue gas desulfurization (FGD) system and a fabric filter to reduce air 

toxics emissions. If such installations are not economically justified, this scenario assumes that the plant 

must retire by 2015. In reality, as discussed previously, power plant owners will have multiple other 

technology options to comply with the regulations – options that typically cost less than installations of 

FGDs and fabric filters. The analysis finds that target reserve margins can be met in all regions, even 

under these stringent assumptions. Moreover, in every region but one (TRE), no additional new capacity

is needed. In TRE, the analysis finds that less than 1 GW of new natural gas capacity would be needed 

by 2015 beyond the additions already projected to occur in the Reference Case. This analysis also finds 

that the total amount of new capacity that would be added by 2015 is less than the amount that is already 

under development.13

The EPA has reviewed industry studies suggesting, contrary to the EPA’s, DOE’s and these other 

groups’ analyses, that the EPA rules affecting the power sector (including this final rule, the CSAPR, the 

EPA’s proposed rule addressing power plant cooling water intake systems under section 316(b) of the 

Clean Water Act (CWA), and the EPA’s proposed rule addressing coal combustion residuals under the 

Resource Conservation and Recovery Act) will result in substantial power plant retirements. Some of 

these studies predict that such levels of retirements will have adverse effects on electric reliability in 

some regions of the country. Although the specifics of these analyses differ, in general they share a 

number of serious flaws in common that call their conclusions into question. First, most of these studies 

make assumptions about the requirements of the EPA rules that are inconsistent with, and dramatically 

more expensive than, the EPA’s actual proposals or final rules. For example, a large proportion of the 

retirements projected by several of these studies is attributable to their inaccurate assumption that EPA’s 

 

11 M.J. Bradley & Associates and Analysis Group, June 2011, “Ensuring a Clean, Modern, Electric 

Generating Fleet while Maintaining Electric System Reliability.”

12 PJM Interconnection, August 26, 2011, “Coal Capacity at Risk for Retirement in PJM: Potential 

Impacts of the Finalized EPA Cross State Air Pollution Rule and Proposed National Emissions 

Standards for Hazardous Air Pollutants.”

13 U.S. Department of Energy, December, 2011, “Resource Adequacy Implications of forthcoming EPA Air Quality 

Regulations”.
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cooling water intake rule under CWA section 316(b) would require all or virtually all existing power 

plants to install cooling towers. In one study, the reliability effects reported are based on inaccurate 

assumptions that all existing EGUs with a capacity utilization factor of less than 35 percent would close, 

and that all in-scope electric generators would be required to install cooling towers within 5 years, 

whereas the not-selected options with closed cycle cooling in EPA’s proposal envisioned that permit 

authorities could exercise discretion to allow facilities 10 to 15 years’ time to comply. In most cases, 

these analyses were performed before the CWA section 316(b) rule or the MATS rule were even 

proposed.

Second, in reporting the number of retirements, many analyses fail to differentiate between plant 

retirements attributable to the EPA rules and older, smaller, and less efficient plants that are already 

scheduled for retirement because owners have made business decisions, based in significant part on 

market conditions, not to continue operating them.

Third, most of these analyses fail to account for the broad range of responses available to address 

electric reliability concerns associated with power plant retirements, including upgrades to the 

transmission system, construction of new generation, and implementation of demand-side measures. 

These measures are discussed at greater length below.

These and other flaws in these analyses have been highlighted by other studies, including the M.J. 

Bradley and Analysis Group analyses discussed above, a June 2011 report by the staff of the Bipartisan 

Policy Center,14 and an August 8, 2011, report of the Congressional Research Service.15

Comment 63: Numerous commenters (17402, 17403, 17689, 17697, 17705, 17730, 17734, 17736, 

17757, 17758, 17761, 17770, 17800, 17808, 17813, 17815, 17817, 17820, 17821, 17868, 17877, 17881, 

17925, 17931, 18016, 18021, 18024, 18033, 18424, 18430, 18433, 18442, 18447, 18498, 1850, 18502, 

19032, 19114, 19121) note that there are likely to be delays due to permitting, which will likely increase 

due to the volume of utilities complying with this rule.

Multiple commenters (17689, 17821, 17868, 17877, 17881, 18024, 18442) specifically reference the 

NSR process.

Multiple commenters (17730, 17736, 17758, 17808, 17820, 17821, 18024, 18037, 18428, 18447, 19114) 

specifically reference the PSD process.

Multiple commenters (17402, 17757, 17736, 17800, 17820, 17821, 18428, and 18502) are concerned 

with the extra delay that FGD landfill permitting and building could cause.

Commenters 17821 and 18428 are specifically concerned with GHG permitting and an associated 

BACT determination.

Commenter 18424 is concerned that utilities must have rate-payer financed capital investments approved 

by state regulatory bodies, which can expand the compliance time by many months.

 

14 Bipartisan Policy Center, June 13, 2011, “Environmental Regulation and Electric System Reliability.”

This report concludes, among other things, that “scenarios in which electric system reliability is broadly

affected are unlikely to occur.” Id. at 3.

15 James E. McCarthy and Claudia Copeland, Congressional Research Service, August 8, 2011, “EPA’s 

Regulation of Coal-Fired Power: Is a ‘Train Wreck’ Coming?”
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Commenter 17813 is concerned about pre-permit approval evidentiary hearings required in Texas, 

which typically exceed 2 years in duration.

Commenter 18031 notes that Minnesota utilities must comply with the Minnesota Mercury Emission 

Reduction Act of 2006 (“MERA”), which requires review by the Minnesota Pollution Control Agency.

Commenter 18433 cites Guam’s procurement laws and lengthy procurement process that may take 

longer than the EPA’s deadline would allow.

Commenter 19114 states that prior to beginning construction, some state regulations require obtaining 

public utility commission approval in the form of a certificate of need.

Commenter 18450 asks that the EPA establish an expedited permitting process for those affected units 

that require permit amendments to install HAP controls.

Response to Comment 63:

Permitting Process under the Clean Air Act can cause Delays 

Some commenters thought that EPA permitting could cause delays in implementing this rule. The EPA 

recognizes that, following the vacatur of the new source review (NSR) pollution control project 

exemption in New York v. EPA, 413 F.3d 3, 40–41 (D.C. Cir. 2005), pollution control projects, 

including pollution control projects constructed to comply with this rule, have the potential to trigger 

NSR permitting. Based on an analysis done in 2005 that looked at SCR and FGD for CAIR compliance, 

but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR 

requirements would not significantly impact the construction of pollution controls that are installed to 

comply with this Rule. In addition it is very unlikely that pollution control projects would cause GHG 

increases that would exceed the 75,000 tons per year threshold either as a result of either chemically 

manufacturing GHGs or as a result of parasitic load. The EPA concludes therefore that there will be no 

significant impacts on timing from NSR for any pollution control projects resulting from this rule. 

Should NSR be triggered it would at most be for just a few of the projected control installations.. In the 

limited circumstances where pollution control installations under the Mercury and Air Toxics Standards 

may trigger NSR, we also note that an expedited permitting process can occur with sufficient time to 

obtain permits and achieve emission reductions. For this reason, we strongly encourage permitting 

State Requirements Can Cause Delays

Some commenters said that states may have laws and other requirements that will cause companies to 

delay implementation of this rule. Some companies may construct replacement generation as a 

compliance strategy. State pre-construction permitting requirements depend upon each individual state. 

Some states do not require pre-construction permits while some others require public utility commission 

(PUC) approval. For states obtaining PUC pre-approval for cost recovery, authorization typically 

averages seven months and is obtained usually within one year.16 Furthermore, while PUC approval is 

necessary to recover investment costs through rate payers, it is not a prerequisite for obtaining credit or 

performing conceptual studies. EPA encourages all parties, state regulators, transmission operators, and 

companies, to work together in a coordinated and reasonable effort to implement this regulation within 

 

16 “Public Utility Commission Report” March 31, 2011 by M.J. Bradley & Assoc LLC; web site: 

http://www.epa.gov/ttn/atw/utility/puc_study_march2011.pdf
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the compliance time frame. The EPA continues to believe, based on the analysis discussed at the 

beginning of this section, that most, if not all, units will be able to comply with the requirements of this 

rule within 3 years. The EPA also believes that making it clear that permitting authorities have the 

authority to grant a 1-year compliance extension where necessary, in the range of situations described 

elsewhere in this document, addresses many of the other concerns that commenters have raised. 

Time frame for Compliance Is Too Short to Construct and Permit an FGD Landfill 

As we have said elsewhere in this document, the compliance deadline allows sufficient time for 

completing landfills for FGD solids disposal. For example, DP&L will construct a landfill within 18 

months to accept wastes generated from Stuart and Killen stations scrubbers. The EPA notes, however, 

that retrofitting units do not necessarily need to complete landfill construction ahead of commencing 

operation of the retrofit to achieve cost-effective emission reductions under the Transport Rule 

programs. Such a source may either utilize a completed portion of the newly permitted landfill under 

construction, transfer waste off-site to a permitted landfill within the owner’s fleet, or contract waste 

removal (and disposal) services. For example, Dallman station subcontracts coal ash disposal at a local 

abandoned mine. The EPA uses a disposal cost assumption of $30-$50 per ton for wet FGD, dry FGD, 

and DSI controls, which the EPA developed in consultation with an experienced power sector 

engineering firm.

EPA should Establish an Expedited Permitting Process

As explained above and in the Preamble to the rule, the EPA does not feel that a new expedited process 

is neccssary. If all parties work delilgently and proactively, state permitting will not prevent facilities 

from coming into compliance with this rule within the compliance period. If, however there is an 

unexpected delay that could not be prevented by the facility’s owner, the EPA expects the 1-year 

extention of the compliance time to be available.

Comment 64: Multiple commenters (16705, 17055, 17701, 17725, 17400, 17608, 17724, 17775, 17791, 

17812, 17815, 17834, 17868, 17868, 17868, 17887, 18441, 18497, 18500, 18023) argue that the EPA is 

unrealistic about the ability of utilities and state or regional energy authorities to avoid electricity

reliability issues after the rule is implemented. These commenters believe the rule may result in the 

shutdown of certain units that are critical to the reliability of electric supply on a timeline that is faster 

than the time necessary to replace the power or upgrade transmission. Commenter 17608 notes that the 

EPA’s assumption that industry can comply quickly with the rule was a key assertion in the EPA’s 

conclusion that reliability will be unaffected.

These commenters identified several logistical problems that they believe may take longer to overcome 

than the 3- to 4-year time period allowed by the rule. These include:

 Time for coordination of offline time for the installation of pollution controls on several plants in 

the same region.

 Time to obtain access to natural gas pipelines for repowering or replacing a plant with a natural 

gas generator.

 Time for planning, building, and interconnecting transmission lines to replace retired EGU

capacity.

 Time to construct new EGUs or other alternative energy sources.
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These commenters argue that the time needed to design, procure and permit new control equipment 

takes several years and that even if these steps could be accomplished in 2 years, there would 

realistically remain only 6 months in the third year when control equipment installation can occur (i.e., 

during the spring and fall periods of reduced electricity demand). Commenter 17775 notes that 

electricity demand is high the other 6 months of the years and that consequently most units must either 

be online or on standby to meet demand peaks. The commenter argues that failure to have an adequate 

number of EGUs available during this period could result in power curtailments or, in the worst case, 

brownouts or rolling blackouts. Commenter 17775 estimates that installation of new control equipment 

required by the EGU MACT would take at least 6 years to complete.

Response to Comment 64: The EPA’s authority for setting the compliance time frames is set out in the 

CAA. In developing this proposed rule, the EPA has performed specific analysis to assess the feasibility

(e.g., ability of companies to install the required controls within the compliance time-frame) and 

potential impact of the proposed rule on reliability. For that analysis entitled “An Assessment of the 

Feasibility of Retrofits for the Toxics Rule” dated March 9, 2011, the EPA has projected the quantity of 

each APC technology that may need to be newly retrofitted and in service by the compliance date(s). 

The EPA used its IPM model to analyze which APC technologies would likely be used, and in what 

quantities, to achieve compliance with the proposed Toxics Rule.

The EPA’s assessment shows that a reasonable, moderately paced effort of the power sector and 

supporting industry, including some early starts, would result in many of the needed retrofits being 

installed by January 2015 with some needing up to an additional year. In order for all retrofits to be 

completed by January 2015, most projects would have to start early and the sector would have to engage 

in a more aggressive deployment program. In the event that individual projects cannot be completed by

the January 2015 statutory deadline for compliance, the CAA offers affected sources the opportunity to 

apply for a 1-year extension.

Although the EPA assessed the ability to install the controls in 3 years (and determined that the controls 

could be installed in that time-frame), this would require the control technology industry to ramp up 

quickly. Therefore, the EPA also assessed a time-frame that would allow some installations to take up to 

4 years. This time-frame is consistent with the CAA which allows permitting authorities the discretion to 

grant extensions to the compliance time-line of up to 1 year. This time-frame also allows for staggered 

installation of controls at facilities that need to install technologies on multiple units. Staggered 

installation allows companies to address such issues as scheduling outages at different units so that 

reliable power can be provided during these outage periods or particularly complex retrofits (e.g., when 

controls for one unit need to be located in an open area needed to construct controls on another unit). In 

other words, the additional 1-year extension would provide an additional two shoulder periods to 

schedule outages. It also provides additional opportunity to spread complex outages over multiple 

outage periods. The EPA believes that while many units will be able to fully comply within 3 years, the 

4

th year that permitting authorities are allowed to grant for installation of controls is an important 

flexibility that will address situations where an extra year is necessary. The EPA expects that state 

permitting authorities will make the fourth year available where it is warranted. In addition where 

necessary to avoid a violation of applicable FERC-approved electric reliability standards the EPA can

use existing CAA authorities to allow additional time to come into compliance.

Comment 65: Commenter 17697 writes that the proposed rule is unrealistic about the ability of the 

Guam Power Authority (GPA) to avoid electricity reliability issues in 2014 when compliance with this 

rule begins. The commenter states that there will be a substantial impact on Guam’s electric rates
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Response to Comment 65: The EPA agrees that the unique considerations faced by non-continental 

EGUs warrant a separate subcategory for units that use liquid oil-fired units in non-continental areas 

such as those on Guam and has included such a subcategory in the final rule. At proposal, the EPA did 

not have all of the data from liquid oil-fired units in non-continental areas (e.g., Guam, Puerto Rico) and 

solicited comment on whether a subcategory should be established, based on the data to be received, for 

non-continental oil-fired EGUs. The EPA has now received these late data and, based on those data, is 

finalizing a non-continental subcategory for liquid oil-fired EGUs in Guam, Hawaii, Puerto Rico, and 

the U.S. Virgin Islands. The EPA is not aware of any liquid oil-fired EGUs in any of the other U.S. 

territories that meet the CAA section 112(a)(8) definition but, if there are such units, they would also be 

part of the non-continental subcategory.

The EPA agrees that the unique considerations faced by non-continental refineries, including a limited 

ability to obtain alternative fuels that lead to different emissions characteristics, warrant a separate 

subcategory for these EGUs. The EPA believes that units in this subcategory will comply through the 

use of cleaner oils or, for PM, through the installation of an ESP.

Comment 66: Commenters 17724 and 17805 ask that the EPA take into consideration the advance 

determination of prudence (ADP) process, which is a process to obtain concurrence from regulatory 

commissions that its decisions on options (and required expenditures) for future energy resources and 

modifications to existing energy resources are prudent. The commenters state that the ADP process, in 

states where it is available, takes almost 12 months to complete and is a critical step for investor-owned 

utilities seeking financing for modifications or new construction.

Commenter 17821 also mentioned prudency review by regulatory authorities.

Response to Comment 66:

Fiduciary Obligations Prevent Expenditures until Rule Finalized

Multiple comments claim initiating major capital expenses prior to the rule’s promulgation violates a 

public company’s fiduciary obligations. In all cases, the comments fail to quantify financial burdens to 

justify their position. A corporation’s obligations go beyond fiduciary trust: they include civic

responsibilities for public (and employee) health, as well as accountability for future direction (as 

determined by the board of directors). In response to these monetary assertions, the EPA recognizes the 

adversity towards financial risks associated with installing controls equipment prior to rule 

promulgation; however, the expenditures for determining compliance requirements (pre-award work) 

are minimal. The EPA funded a study to update and improve retrofit control costs modeled within IPM 

for the Cross-State Rule. From these studies, engineering and construction management costs (as a 

percentage of total installed cost) range from 4.1% to 7.3% (basis: 500 MW unit). Considering industry

typically limits conceptual engineering not to exceed 10% of total engineered cost, by extension, preaward work accounts for less than 1% of total installed price. [Conceptual engineering studies are 

defined as: establishing project scope, type of controls, control’s performance, auxiliary equipment, and 

permit plus funding requirements.] Since conceptual engineering is necessary to assess potential unit 

modification options, the EPA believes these pre-award minor expenditures do not violate fiduciary 

obligations; rather, they provide valuable planning information for future regulatory compliance. For 

example, Nebraska Public Power District (NPPD) commissioned a $2.4 million study to develop a 

“ready to issue” contract for an FGD retrofit estimated to cost $1 billion for the 1,365 MW Gerald 
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Gentleman Station.17 This represents 0.24% of installed cost. Since conceptual engineering is necessary

to assess potential unit modification options, the EPA believes that these pre-award minor expenditures 

do not violate fiduciary obligations; rather, they provide valuable information for future planning for 

regulatory compliance, which appears to serve a sensible fiduciary purpose. 

Negotiating Contracts, Competitive Bid Evaluation – More Time Required for Compliance

Contract negotiation through the competitive bid process is an agreement achieved between a buyer 

(utility) and seller (supplier). Ultimately, the buyer determines length of time spent in negotiation, and 

concludes negotiations by signing an award for goods and/or services. 

Owner’s Decisions & Options

Citing procedural difficulties (interfacing with multiple entities, meeting once a year, etc.) do not 

constitute sufficient basis for inability to meet compliance dates. The owner is ultimately responsible for 

assuring adequate and timely compliance by exercising imitative over a “business as usual” approach. 

Moreover, MATS is inherently flexible – it allows an owner multiple options to attain compliance 

deadlines; namely, purchase power, shift power generation to cleaner units (combined cycle plants, 

stations with emission controls, etc.), expedite retrofit work (utilize multi-shift schedule or extended 

overtime), fuel switching/blending, upgrade existing equipment, replace equipment/components, and 

retrofit existing equipment – or any combination there-of.

Comment 67: Multiple commenters (18023, 17608, 17638, 17716, 17752, 17756, 17820, 17821, 17840, 

17868, 17904, 17925, 17931, 18033, 18502) have concerns with “early planning” and “forward 

planning” recommended by the EPA. Commenter 18023 notes, “If EPA intended this to be a direct final 

rulemaking, it should have said so.”

Commenter 17911 states that municipalities may not make any significant financial or operational 

changes before the rule is promulgated, otherwise, they may be violating their fiduciary responsibilities.

Commenters 18428 and 19114 state that it would be imprudent planning for utilities to commit capital 

without knowing what the final standards are, as the risk of penalties and uneconomic investments is too 

great. The commenters state that more fundamentally, utilities contemplating retrofits to generating units 

in rate-regulated states such as those in which the commenter operates run a substantial risk of nonrecovery if they make capital commitments before a final rule is issued.

Comment 68: Commenter 18421 recommends that the EPA, the DOE, and the FERC work closely with 

regional utility planning and operation centers, the National Association of Regulatory Utility

Commissions, state PUCs, and utilities to ensure that the measures available preserve the reliability of 

the electric system.

Commenter 17741 is concerned that the compliance time will not allow adequate prep time, causing 

utilities to shutter multiple units or entire plants. The commenter is concerned about job loss.

Response to Comments 67 - 68: In the preamble to the proposed rule, the EPA urged power generators 

and others to perform advanced planning so as to be prepared to implement the regulation in the 3-year 

 

17 “S&L to Develop Cost Estimates, Plans for FGD at Gerald Gentleman”; Utility E-Alert #1030, June 

24, 2011; McIlvaine Company
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compliance timeframe. A number of commenters took exception to that. Many stated that they can’t 

begin planning until they know what the rule is for certain. Others said that they were in fact doing that 

planning so that they would be able to comply within the compliance timeframe. 

In the MATS preamble, the EPA stated that, although there are a significant number of controls that 

need to be installed, with proper planning, we believe that the compliance schedule established by the 

CAA can be met. The EPA pointed out that there are already tools in place (such as integrated resource 

planning, and in some cases, advanced auctions for capacity) that ensure that companies adequately plan 

for, and markets are responsive to, future requirements such as the rule. In addition, the EPA itself is 

reaching out to key stakeholders including not only sources with direct compliance obligations, but also 

groups with responsibility to assure an affordable and reliable supply of electricity including state Public 

Utility Commissions (PUC), Regional Transmission Organizations (RTOs), the National Electric 

Reliability Council (NERC), the FERC, and DOE. The EPA intends to continue these efforts during the 

implementation of this rule. It is the EPA’s understanding that FERC and DOE will work with entities 

whose responsibility is to ensure an affordable, reliable supply of electricity, including state PUCs, 

RTOs, the NERC to share information and encourage them to begin planning for compliance and 

reliability as early as possible. This effort to identify and respond to any projected local and regional 

reliability concerns will inform decisions about the timing of retirements and other compliance strategies 

to ensure energy reliability. The EPA believes that the ability of permitting authorities to provide an 

additional 1 year beyond the 3-year compliance time-frame as specified in CAA section 112, along with 

other compliance tools, ensures that the emission reductions and health benefits required by the CAA 

can be achieved without any risk of adverse impacts on electricity system reliability.

Comment 69: Several commenters (17403, 17716, 17821, 17902) note that delays are expected due to 

the number of involved stakeholders (state public utility commissions, RTOs, NERC, FERC, DOE, 

EPA).

Response to Comment 69: Some commenters thought that there would be delays in compliance with 

this rule attributed to the numerous stakeholders who would be involved. With proper planning, we 

believe that the compliance schedule established by the CAA can be met. There are already tools in 

place (such as integrated resource planning, and in some cases, advanced auctions for capacity) that 

ensure that companies adequately plan for, and markets are responsive to, future requirements such as 

the proposed rule. In addition, the EPA itself is reaching out to key stakeholders including not only 

sources with direct compliance obligations, but also groups with responsibility to assure an affordable 

and reliable supply of electricity including state Public Utility Commissions (PUC), Regional 

Transmission Organizations (RTOs), the National Electric Reliability Council (NERC), the FERC, and 

DOE. The EPA intends to continue these efforts during the implementation of this proposed rule. The 

EPA understands that FERC and DOE will work with entities whose responsibility is to ensure an 

affordable, reliable supply of electricity, including state PUCs, RTOs, the NERC to share information 

and encourage them to begin planning for compliance and reliability as early as possible. This effort to 

identify and respond to any projected local and regional reliability concerns will inform decisions about 

the timing of retirements and other compliance strategies to ensure energy reliability. The EPA believes 

that the ability of permitting authorities to provide an additional 1 year beyond the 3-year compliance 

time-frame as specified in CAA section 112, along with other compliance tools, ensures that the 

emission reductions and health benefits required by the CAA can be achieved while safeguarding 

completely against any risk of adverse impacts on electricity system reliability
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Comment 70: Several commenters (17402, 17752, 17758, 18428, 19114) note that the word “installed,”

when attributed to vendors, refers only to the physical construction of the controls but that the reality of 

control technology installation includes more than that.

Comment 71: Several commenters (17403, 17756, 17820, 17931) ask for additional time to allow for 

unit/control device testing/optimization after installation.

Response to Comments 70 - 71: The EPA is aware that installation of controls means more than simply

manufacturing the device but means that it is installed on the unit.

Comment 72: Commenters 18430 and 18023 note that interstate gas pipelines may need to be expanded 

to account for EGU fuel supply changes.

Response to Comment 72: The EPA’s analysis does not support this contention. The use of natural gas 

to comply with this regulation does increases modestly, by about 3% in 2015. However natural gas 

generation in 2015 with this rule will be more than 200,000 GWh less than generation from natural gas 

in 2009. This indicates that the shift to natural gas for compliance with this rule would be very modest 

and that it could be accomplished mostly with existing capacity.

Comment 73: Commenter 17815 notes that the short compliance timeline will jeopardize fuel diversity.

Commenter 16850 states that over the past 20 years, the vast majority of new capacity additions in 

Florida have been natural gas-fired. The proposed Air Toxics rule, the recent Cross-State Air Pollution 

rule, potential greenhouse gas regulations, and currently low gas prices may further encourage utilities to 

install natural gas-fired generation or repower existing oil- or coal-fired capacity to natural gas as a

compliance strategy. In order to provide Florida’s consumers with the benefits of a balanced fuel mix, 

utilities should be allowed to retain existing coal capacity without installing costly air compliance 

measures, if the utility commits to retire or repower the unit in the near future.

Commenter 17887 states that the EPA should recognize the needs of each state and region to deploy a 

portfolio of cost-effective supply- and demand-side resources based on unique circumstances – Over the 

past twenty years, the majority of new capacity additions in Pennsylvania have been natural gas-fired. 

Many states in the PJM footprint including Pennsylvania are actively encouraging the development of 

renewable resources such as wind and solar. In order to provide Pennsylvania customers with the 

benefits of a balanced fuel mix, generators should be allowed to retain existing coal capacity without 

installing costly air compliance measures, if the generator commits to retire the unit in the near future 

due to the availability of “cleaner” generation resources. Further, the EPA should retain the limited use 

provision that appears to allow generators to avoid installing costly controls on units that are rarely 

dispatched.

Comment 74: Several commenters (16549, 17403, 17682, 17917) are concerned that the rule will 

weaken reliability by removing coal-fired units as a resource. Commenter 16549 believes that that the 

EGU MACT may make it impossible to utilize the U.S.’s vast supply of coal. Commenter 17917 

believes the proposed rule threatens both existing facilities and future development of coal-fired EGUs. 

Commenter 17682 believes that the EPA is intentionally trying to increase the compliance costs for 

coal-fired plants to force coal plants to either close or be replaced by other sources, such as gas-fired 

EGUs and renewable energy alternatives (solar, wind, biofuels). This commenter believes the EGU

MACT amounts to a subsidy of alternative energy industries and is defacto tax on the public. 
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Commenter 17403 coal-fired retirements would have a significant impact on key midwestern and south 

Atlantic states.

Comment 75: Commenter 17386 expresses concern that the proposed rule would decrease generation 

capacity by forcing early retirement of oil-fired EGUs. This commenter believes that forcing early 

retirement of oil-fired EGUs and the consequential decrease in generation capacity and system reliability

is contrary to NERC’s objective to provide reliable service.

Comment 76: Several commenters (17701, 17791, 17807) are concerned that environmental regulations 

for EGUs will drive electric generators to a single fuel source, which they argue could unintentionally

weaken the stability of the power sector and increase cost for consumers. Commenter 17807 believes 

that the EGU MACT may result in electricity supply problems in Florida because the state is a 

peninsula, which limits opportunities to import power. The commenters note that fuel diversity is critical 

for electricity reliability in Florida, where supply problems may be particularly acute during extreme 

weather events like the recent cold snaps and hurricanes, when supply of natural gas may not be 

available for sustained periods of time. 

Comment 77: Commenter 16850 notes that significant controls would be necessary at many of 

Florida’s coal- and oil-fired generating units, and some units would be at risk of retirement. The 

commenter states that the EPA’s final rules should avoid compromising electric system reliability and 

allow the maximum compliance flexibility for electric utilities provided for under the CAA.

Commenter 18500 states that the EPA has also asserted that fuel switching of existing EGUs to natural 

gas and construction of new gas-fired generating units can replace the retired coal units but that the 

planning, contracting, permitting, financing and construction take longer than the restrictive timeframe 

proposed, and during that timeframe, some units are not available for dispatch. The commenter states 

that not all units will have ready access to sufficient gas supply to repower resulting in necessary gas 

transmission upgrades that can be time consuming and costly. According to the commenter, the reality is 

that the EPA’s own permitting rules present a time consuming obstacle to meeting the EPA’s deadline 

yet nowhere in the proposal does the EPA contemplate addressing accelerated permitting for pollution 

controls or exemptions from NSR requirements when making pollution control upgrades.

Response to Comments 73 - 77: The EPA does not dictate the compliance strategy that might be used 

by regulated companies. The EPA has carefully designed a rule that can be achieved by all coal types. 

Although the EPA’s analysis indicates that most plants will comply by retrofitting existing coal-fired 

plants with pollution controls, some may switch to cleaner fuels. Our analysis shows that in fact there is 

very little difference in the relative use of the three major coal ranks with and without the rule in 2015. 

There is a slight increase in the use of interior bituminous coal and a slight decreases in the use of 

subbituminous and lignite coals. Over all, coal remains the most important fuel for electricity 

generation. 

Some plants may retire. In most cases there is adequate excess capacity to avoid any threat of a problem 

for electricity reliability. Should there be a reliability concern, it can be addressed in a variety of ways 

including use of excess capacity, installation of new capacity, transmission upgrades, and demand-side 

strategies that can make over all compliance with this regulation much less expensive, and can be 

implemented relatively rapidly. The EPA projects that this rule will result in a very small increase in 

gas-fired generation, a very small decrease in coal-fired generation as a result of compliance with 

MATS.
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Comment 78: Commenter 17732 is concerned about the time it takes to receive land use approvals on 

Indian trust lands should site-specific constraints necessitate use of additional land.

Response to Comment 78: Sources can obtain an additional year to comply if necessary for the 

installation of controls. Unavoidable delays in obtaining permits necessary to install the controls would 

likely be sufficient to obtain the additional year to comply.

Comment 79: Commenter 17738 is concerned about plants which already have emissions controls and 

limitations established through case-by-case MACT determinations. The commenter suggests alternate 

compliance dates for these plants.

Response to Comment 79: Sources that are existing sources on the compliance date for the final rule 

would have 3 years to come into compliance.

Comment 80: Commenter 17386 recommends that the EPA and generation owners collaborate to 

develop and meet timelines while monitoring equipment installation to avoid negative impacts of delays 

that could occur. According to the commenter, such an approach would also ease concerns over grid 

security caused by mass outages on generators to install the required equipment

Response to Comment 80: The EPA’s analysis does not confirm that MATS will result in anywhere 

near the extent of outages that this commenter projects, and several outside analyses have reached 

conclusions consistent with the EPA’s analysis. The EPA does agree, however, with the commenter that 

a collaborative approach between the companies, the EPA, state regulators, RTOs and others involved in 

assuring grid stability would help to assure grid security.

Comment 81: Commenter 17930 stated that the EPA’s beyond-the-floor analysis [for Hg at facilities 

burning virgin low BTU coal] does not properly take into account the effect that the limit would have on 

energy requirements and reliability when lignite units are closed due to inability to meet the proposed 

beyond-the-floor limit. 

Response to Comment 81: As stated elsewhere, the EPA believes that the data used to conduct the 

beyond-the-floor analysis are consistent with results achieved in U.S. DOE Hg control technology

demonstration projects. The DOE’s National Energy Technology Laboratory (NETL) sponsored a 

project entitled “Mercury Control for Plants Firing Texas Lignite and Equipped with ESP-wet FGD”. In 

this project, URS Group evaluated sorbent injection for Hg control in an 85/15 blend Texas lignite/PRBderived flue gas. The authors of the final project report noted that, in short term parametric tests, three 

different brominated sorbents performed similarly with results indicating that 90 percent reduction of Hg 

was attainable at injection rates of 2 to 3 pounds per million actual cubic feet (lb/Macf) and greater than 

90 percent at higher rates. In longer-term (60-day) testing using a brominated sorbent, Hg removal 

averaged 80 percent at a modest injection rate of 2 lb/Macf. This compares favorably to the results of 70 

to 90 percent achieved in the short-term testing at the same injection rates. However, greater than 90 

percent could have been achieved at injection rates of 3 to 5 lb/Macf. Note that all of these results are for 

control across a cold-side ESP. Control across a fabric filter is normally expected to exceed that 

measured through an ESP. The EPA believes that its beyond-the-floor analysis is appropriate, including 

the costs analyzed. We do not anticipate any reliability problems due to lignite plants closing. Any shift 

away from lignite is made up for by other types of generating capacity and shifts to PRB.

Comment 82: Commenter 18033 said that the EPA has committed a “fundamental error” with its 

“undocumented and unsupported claims of key stakeholder collaboration to ‘safeguard[ing] completely
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against any risk of adverse impacts on electricity system reliability’.” The commenter could not find 

evidence of these consultations in the rulemaking docket.

Response to Comment 82: The docket will include documentation of all substantive meetings with 

persons outside of the executive concerning this rulemaking.

Comment 83: Several commenters (17627, 18034, 18037, 18907) are concerned that the reduced 

reliability resulting from the EGU MACT may result in an increase in emissions because industry will 

be forced to rely on small emergency generators. These commenters note that most of the emergency

generators are small diesel-fired units that are not capped or in many cases permitted. The commenters

note that higher emissions from these emergency back-up generators are not normally a concern because 

of their limited use during emergency situations and power outages. According to the commenters, if 

demand response programs become a necessary strategy to prevent or minimize the impact of reliability

issues resulting from loss of capacity, however, then localized net increases in emissions would be 

expected. Rather than improving air quality, the commenters argue that this rule would directly and 

adversely impact citizens in the urban cores where emergency generation is typically located.

Commenter 18037 stated that in its analysis of this year’s capacity auction results, PJM noted that the 

coal plant offers which included anticipated environmental compliance costs, likely did not clear the 

market because they were high relative to demand response (DR) offers. According to the commenter, 

this raises an important environmental contradiction and an issue that the EPA should consider in it cost 

-benefit analysis. The commenter states that ISO-RTO estimates that are available suggest that 50% or 

more of DR resources in the market are not demand reductions, rather they are merely a shift to 

customer-supplied behind-the- meter generation, and much of that generation is from small diesel units 

the emissions from which are not accounted for and in many cases not permitted. According to the 

commenter, this is particularly important on very hot, ‘high electric demand days” when DR generators 

are called upon. The commenter states that as the EPA was informed by the State of Delaware in the 

RICE NESHAP docket (EPA-HQ-QAR-2008-0708), there are tens of thousands of these diesel 

generators throughout the Northeast. 

According to the commenter, these “area sources” emit air toxics and are an increasingly significant 

contributor to the ground level ozone non-attainment problem as DR programs continue to grow 

exponentially; they represent tens of thousands of megawatts in the PJM, ISO-New England, New York 

ISO, Midwest ISO wholesale markets and throughout the US. The commenter states that at a minimum, 

since EGU units are clearly being displaced in the competitive markets by DR offers, and will not likely

be replaced megawatt-for-megawatt by cleaner, more expensive thermal generation which must control 

and account for its emissions, the EPA’s cost-benefit analysis is incomplete if it does not account for the 

growth in emissions from behind-the-meter generation participating in ISO-RTO DR programs, 

particularly those from uncontrolled diesel units.

Response to Comment 83: Not all demand response is a reduction in electricity demand, much of it 

shifts demand for electricity from peak demand periods to periods of lower demand thus reducing the 

need for peaking capacity. The commenter is talking about a use of generation from small diesel units 

during periods of peak demand. These units, not subject to this regulation, and may be responsible for 

increases emissions of pollution. The Reciprocating Internal Combustion Engine rulemaking which was 

final in March of last year, but which is under reconsideration, limits the operation of these sources, 

specifically to prevent an increase in emissions. These generators are less efficient to operate than other 

sources and thus are less desirable economically as well as environmentally. The EPA does not expect 

that the Mercury and Air Toxics Standards rule will increase the use of these generators.
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Comment 84: Commenter 18538 believes that the EPA has overstated the amount of generation 

available in future years by more than 10 GW by including generating plants that have retired and by 

failing to adjust wind generating capacity to account for the fact that wind is variable and often does not 

blow during times of peak energy use.

Response to Comment 84: The EPA disagrees with the claim that it does not account for the variability

of wind generation in its power sector modeling projections. The EPA recognizes that wind is a variable 

resource for power generation, and our modeling of MATS in fact takes this reality into account in a 

very detailed manner to simulate future generation from wind turbines. The EPA’s power sector 

modeling utilizes capacity factors for wind generators that reflect both wind class (ranging from class 1 

to class 7) and geographic region, and are explicitly designed to represent how often the wind blows to 

support power generation at different locations. The EPA worked with the U.S. Department of Energy’s 

(DOE) National Renewable Energy Laboratory (NREL) on a complete update of the wind resource 

assumptions for use in EPA’s IPM v.4.10. The result is a complete representation of the potential 

onshore, offshore (shallow and deep) wind generating capacity (in MW) broken into four cost classes in 

each IPM model region.

To represent intermittent renewable generating sources like wind and solar, the EPA’s IPM modeling 

(including the modeling used for MATS compliance cost projections) uses generation profiles which 

specify hourly generation patterns for a representative day in winter and summer. Each eligible model 

region is provided with a distinct set of winter and summer generation profiles for wind, solar thermal, 

and solar photovoltaic plants, such that projected generation from intermittent renewable sources would 

reflect the frequency that those resources are actually available in that region. The EPA derived its 

capacity factor assumptions for wind generation from the Energy Information Administration’s (EIA) 

Annual Energy Outlook (AEO) 2010. They are shown in Table 4-20, Table 4-21, and. Table 4-22 of the 

IPM documentation on EPA’s website. See IPM documentation.

Comment 85: Several commenters (17800, 17807, 17911) believe that the work practice standards will 

impact the reliability of electric supply. These commenters argue that most EGUs do not have annual 

planned outages that would allow time for implementing the work practice standards. Commenter 17800 

states that most planned outages are more than 18 months apart and planned major outages are typically 

3 to 5 years apart. The commenter further notes that by requiring outages every 18 months, the EPA will 

increase the number of outages and thus unit downtime. The commenter notes that inspections of 

burners for coal fired units require an internal boiler inspection, which means that an outage of at least 

15 days will be required (with 1-2 days to cool; 5 days to erect scaffolding; 2-5 days to repair or replace 

burner components; 3 days to dismantle the scaffolding). According to the commenters, additional time 

may also be required to order replacement parts, which could result in an extended outage of between 16 

to 26 weeks.

Response to Comment 85: The EPA does not believe work practice standards will impact reliability 

and notes that the frequency of the tune-ups required have been changed in the final rule. See Preamble 

discussion of work standards.

8. Survey of public power utilities.

Comment 86: Commenter 17868 shared results from a survey it conducted of public power utilities 

(utilities owning approximately 14 GW of coal based generation capacity responded to the survey). 

According to the commenter, these represent over 50% of the coal-based capacity wholly owned by 
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public power utilities, and respondents ranged in cumulative capacity between 55 MW and 2200 MW, 

and averaged 610 MW of coal based capacity):

a. About 20% of respondents planned to retrofit FGD and about 20% SCR (typically the same utilities 

were retrofitting both). About one-half planned to replace or supplement existing ESPs with new FFs

b. About one-fourth were moving forward with plans based on the notice of proposed rule (NOPR).

c. Half were waiting until the final rule is promulgated, and the rest intended to wait until other pending 

environmental rules were finalized before deciding on a compliance approach.

d. About three-fourths of respondents stated that they needed the assistance of engineering consultants 

for planning their compliance strategy. Such reliance is not unusual, even for IOUs, but several 

respondents cited their small size and/or remote locations as barriers to obtaining assistance from the 

larger, more qualified consulting firms. Additionally, several respondents cited a mandatory ―public

bid process for selecting contractors (and purchasing equipment) which deterred some contractors and 

created additional delays in reaching compliance.

e. Public power utilities generally must receive approval from political bodies, such as an elected Board 

of Directors and a City Council. Procedures vary by utility, but separate government approvals may be 

required for the compliance plan and the issuance of bonds to pay for the compliance projects. Several 

respondents noted that a public referendum is required in order for bonds to be sold.

f. Planning periods averaged 17 months, and financing 8 months. However several respondents noted 

that budgets were addressed only once per year, and that public reviews of plans and funding could 

result in extended delays, including what one respondent called “hostile interventions.”

Response to Comment 86: The EPA recognizes that, although many plants that are owned by public 

power authorities are well controlled and, thus, are well positioned to implement this rulemaking. Some 

of them, however, may have challenges privately owned facilities do not have. We think that the 

flexibilities that are offered under the CAA including the availability of a fourth year and other 

compliance time flexibilities will ease the burden these facilities face. 

9. Other.

Comment 87: Commenter 18027 notes that the language in section 112(i)(3) is inconsistent across 

paragraphs. Section 112(i)(3)(B) provides for a one-year source-specific extension to the principal 

compliance schedule established for the source category or subcategory whereas the preceding 

paragraph states that Congress provided for the compliance schedule established upon promulgation of 

the standards to apply to an entire category or subcategory of sources.

Response to Comment 87: The EPA does not agree with the commenter that the CAA section 112(i)(3) 

paragraphs are inconsistent. CAA section 112(i)(3)(A) authorizes the EPA to provide up to 3 years for 

initial compliance with promulgated standards, and section 112(i)(3)(B) allows the EPA or a state with 

an approved title V permit program to approve a 1-year extension of the compliance period established 

in the final rule if such time is necessary for the installation of controls.
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5C02 - Compliance: Emissions Averaging

Commenters: 17174, 17402, 17623, 17627, 17648, 17655, 17689, 17691, 17705, 17714, 17716, 17718,

17719, 17722, 17725, 17730, 17731, 17736, 17737, 17740, 17757, 17758, 17768, 17774, 17775, 17789, 

17795, 17798, 17800, 17813, 17816, 17818, 17820, 17821, 17856, 17870, 17873, 17877, 17881, 17885, 

17902, 17904, 17913, 17928, 18014, 18024, 18025, 18031, 18037, 18429, 18449, 18450, 18498, 18539, 

19114, 19120, 19121, 19214, 9738, 19536/19537/19538, 18023

1. Opposition to emission averaging compliance option.

Comment 1: Commenter 17174 states the emissions caps for existing affected sources choosing to 

demonstrate compliance by the emission averaging option cannot be effectively implemented or 

enforced. The commenter encountered many problems with the approval process in the vacated 

Boiler MACT in 2007, and now the EPA has proposed the same approval process here for the Utility

MACT, disregarding the known problems in implementing the emission averaging compliance option 

from the Boiler MACT. The commenter stated the emission cap should be included in the compliance 

calculations. The commenter believes that the requirement to establish an emission cap and submit an 

implementation plan to the permitting agencies for approval is problematic as written. The commenter 

states that because the emission cap is not used in the initial compliance demonstration or in 

demonstrating continuous compliance with the emission averaging option, the commenter states it is of 

little use. The commenter states that if the intent of this option is for facilities to not exceed the cap at 

any time, then the EPA should include a demonstration methodology that shows that a facility is not 

exceeding the cap in the compliance equations in section 63.10009. According to the commenter, if the 

cap is included in the compliance equations, facilities could certify compliance with the cap in 

the NOCS and within each required semiannual report. The commenter went on to say that if the initial 

and continuous compliance measures include the emission cap, the implementation plan will not be 

necessary and states will not have to spend valuable time and resources to approve these duplicative 

plans.

Response to Comment 1: The agency disagrees with the commenter’s suggestion that the emissions 

averaging option cannot be implemented or enforced effectively. The commenter’s concerns regarding 

emissions averaging plan approval is mistaken, as such an approval is required only if requested by the 

Administrator. While the plan may not need to be submitted for approval, the EGU owner or operator 

who wishes to use emissions averaging will need to develop, maintain, and make available a plan. 

Emissions from EGU units included in averaging, as opposed to individual EGU units, are not to exceed 

the otherwise applicable emissions limit. Deviations from meeting this requirement are already required 

to be submitted in notices of compliance status (NOCS), so no rule change is needed. Finally, states, 

local, or tribal agencies who are delegated the authority to implement this program will decide based on 

their own needs and requirements whether or not to choose to require submission and approval of plans.

Comment 2: Commenter 17818 opposes the averaging of HAP. However, the commenter supports 

allowance of limited emission averaging for existing units at sources that are within a single 

subcategory. Commenter further states that without averaging their existing units are already below 

existing HAP emission rates due to previous emission control projects, some of their units will be above 

new HAP emission rate limits and would require redesign of the existing controls to achieve unitspecific compliance. According to the commenter, averaging of units might facilitate state-of-the-art 

highly effective controls installation on other units at the source to achieve an approved averaging plan, 

and this may relieve the need to replace or modify controls that had been recently installed, in effect 

giving credit for the installation of those controls.
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Response to Comment 2: The agency agrees with the commenter that emissions averaging can provide 

a cost-effective, if not cost-saving, means of compliance, to EGU owners or operators. The emissions 

averaging provisions of the rule remain.

Comment 3: Commenter 18450 opposes allowing owners and operators of existing affected sources to 

demonstrate compliance by emissions averaging for units at the affected source that are within a single 

subcategory since it will allow large facilities to avoid installing air pollution controls to reduce HAP 

emissions on all affected units. Commenter recommends that the EPA remove the averaging provisions 

and establish a discount factor to compensate for the measurement variability inherent in stack testing 

for HAP.

Response to Comment 3: As mentioned in an earlier response, the agency supports the use of emissions 

averaging for existing sources for a number of reasons, ranging from increased flexibility to reduced 

costs for EGU owners or operators, as well as reduced emissions through use of a discounted emissions 

limit for those units subject to emissions averaging. The EPA disagrees that use of a discount factor is 

needed for this rule, as stack testing variability has already been incorporated in the rule’s emissions 

limits via use of the UPL calculation.

Comment 4: Commenter 19214 opposes the proposed average emission limits among multiple sources 

at facilities in the Best Available Retrofit Technology (BART) program. The commenter states that even 

though it appears to satisfy the criteria established by the EPA, in practice, it works only if all affected 

sources operate exactly as assumed in the formulation. According to the commenter, realistically, the 

better-controlled source may operate less than assumed (perhaps due to the greater costs of compliance), 

while the under-controlled source uses cost advantage to operate more than assumed. Commenter 

believes that the risks that actual emissions and potential human health and environmental effects will be 

greater than assumed, and not worth providing more flexibility to emit hazardous air pollutants.

Comment 5: Several commenters (19536, 19537, 19538) states that the EPA should not permit units to 

average emissions. According to the commenters, the proposed averaging would allow some coal- and 

oil-fired units to emit HAP in excess of the promulgated standards (so long as a neighboring unit 

operates below the standards) – a result prohibited by section 112. The commenters state that section 

112 states that “[a]fter the effective date of any emissions standard . . . promulgated under this section 

and applicable to a source, no person may operate such source in violation of such standard” unless the 

agency provides a more lengthy compliance schedule. 42 USC section 7412(i)(3).

The commenters point out that the agency’s discretion to construe the word “source” under the CAA is 

constrained by the congressional policies underlying section 112. Chevron, U.S.A. v. Natural 

Resources Def. Council, 467 U.S. 837, 866 (1984). The commenters state that Congress intended, in 

section 112, to ensure the maximum reduction of hazardous air pollution, and to that end, it constrained 

the agency’s ability to balance pollution-reduction with economic considerations. See 42 USC section 

7412(d). The commentesr assert that the agency has set most standards at the statutory minimum. 

According to the commenters, section 112 does not allow the agency to permit additional pollution in 

order to ease compliance (see 40 CFR section 63.41 (sources may not average emissions to avoid 

compliance with section 112 standards).

Response to Comments 4 - 5: As mentioned earlier, while the agency has reviewed the commenter’s 

concerns, the agency finds emissions averaging when coupled with appropriate safeguards such as those 

contained in the rule, including eligibility (existing units within a single subcategory) and frequent 

emissions verification (quarterly) can provide a flexible, cost-effective compliance approach.
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2. Support emissions averaging compliance option.

Comment 6: Numerous commenters (17402, 17623, 17648, 17655, 17705, 17716, 17718, 17722, 

17725, 17758, 17774, 17798, 17870, 17873, 17904, 17928, 18025, 18031, 19121, 18023) support 

emissions averaging for compliance.

Response to Comment 6: The agency appreciates the commenters’ support for use of emissions 

averaging subject to the rule’s eligibility requirements.

Comment 7: Commenter 17174 requests the EPA eliminate the requirement for delegated authorities to 

approve implementation plans and instead develop an emission averaging certification mechanism 

within the Notice of Compliance Status (NOCS), because the NOCS process is established, and states 

have experience implementing it.

Response to Comment 7: As mentioned earlier, the rule allows, but does not require, delegated 

authorities the ability to approve emissions averaging plans.

Comment 8: Commenters 17402 and 17648 note that emission averaging provides a flexible approach. 

Commenters also note that emission averaging achieves equivalent MACT emissions limits. 

Commenter 17402 states that facility-wide averaging will allow owners and operators to comply with 

emissions limits by over controlling sources within the group where it is cost effective to do so in order 

to offset exceedances of the standard by sources for which emissions control would be less cost 

efficient.

Response to Comment 8: The agency appreciates the commenters’ support for use of emissions 

averaging subject to the rule’s eligibility requirements.

Comment 9: Commenter 17174 states the requirement for delegated agencies to approve 

implementation plans is burdensome and unnecessary. The commenter suggests the EPA should provide 

specific guidance and examples on what constitutes an acceptable emission cap. The commenter notes 

that while the EPA attempted to correct the enforceability problem related to the emission cap in the 

final Boiler MACT by requiring facilities to report the emission cap in the NOCS (see 40 CFR

63.7545(e)(5)(i)), and certify compliance with the cap in the compliance reports (see 40 CFR

63.7550(c)(l3)), there is no guidance or clear process on what constitutes an acceptable and enforceable 

emission cap that delegated agencies can follow to approve the cap. If the EPA decides that the 

submittal and approval of implementation plans are necessary for the emission averaging compliance 

option, the commenter believes that the EPA should retain the authority to approve the implementation 

plans.

Response to Comment 9: The agency finds the commenter’s concern misplaced. While the rule allows 

state, local, or tribal authorities who have been delegated approval of this rule the ability to require 

submission of, as well as approval of, emissions averaging plans, the rule requires EGU owners or 

operators who choose to engage in emissions averaging to develop an emissions averaging plan and to 

maintain and present such a plan upon request. The rule establishes the formula for demonstrating 

compliance when emissions averaging is used, so there is no need for additional guidance. Should the 

commenter find developing a plan or determining compliance to be problematic, he or she could choose 

another compliance option available in the rule.
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Comment 10: Commenter 17174 suggests the emission averaging compliance option in the 

Boiler MACT and Utility MACT be consistent.

Response to Comment 10: The agency agrees with the commenter’s suggestion, and the rules are 

consistent to the extent possible.

Comment 11: Commenter 17798 states that both emissions averaging and staging controls provides 

flexibilities for utilities having to meet a new stage of reductions under the Cross State Air Pollution 

Rule (CSAPR).

Comment 12: Commenters (17870, 17873) state that emissions averaging represents an equivalent, 

more flexible, and less costly alternative to unit-by-unit emissions limits while still maintaining a 

regulation that is workable and enforceable. According to the commenter, this flexible compliance 

option will be particularly helpful to smaller generating units that are co-located with larger generating 

units, but may not be economic to retrofit with pollution control systems.

Response to Comments 11 - 12: The agency appreciates these commenters’ support of emissions 

averaging.

3. Request expanded flexibility for emissions averaging.

Comment 13: Multiple commenters (17718, 17816, 17820, 18037, 18539, 19114) state that the 

proposed emission rate averaging plan does not provide much flexibility because the emission rate limits 

are so low. According to the commenters, in order for a source to take advantage of these provisions, at 

least one unit would need to achieve a rate substantially lower than the MACT limit, and there is no 

evidence that such rates are achievable for any existing units. The commenters state that the mass-based 

approach would provide each facility with a total annual mass emission limit for HCl, PM, and Hg that 

could provide flexibility for the source to operate in the most economical way to meet that facility-wide 

limit.

Comment 14: Numerous commenters (17627, 17718, 17719, 17737, 17740, 17768, 17774, 17775, 

17813, 17816, 17820, 17856, 17885, 17902, 17913, 17928, 18024, 18037, 18539, 19114) state that the 

averaging provisions should not be limited to units at a facility but should be expanded to include 

adjacent units that have controlled access within a common fence line. The commenter states that the 

EPA can provide additional flexibility and cost savings on emission reductions by revising the facility

definition to include units within a common fence line. Commenter 19114 suggests that a unit could 

have the annual mass limit set as a multiple of the design heat input, the HAP limit for each constituent, 

and the average capacity factor for the unit for the previous 3 years. Commenter 17740 suggests that 

emissions averaging for units in different subcategories could easily be accomplished by requiring the 

units to develop an emissions averaging plan, similar to the plan required for NOX emissions averaging 

under the Acid Rain Program at 40 CFR 76.11. According to the commenter, such an approach could 

easily be used in the EGU MACT rule to allow units in different subcategories to meet 

the HAP emission standards through emissions averaging. Commenter 17928 further states that oilbased units are particularly disadvantaged by the proposed constraints on averaging because they are 

often stand-alone units that would not be able to average emissions with other units at a facility. 

According to the commenter, oil and coal units at a facility should be permitted to average emissions.

Response to Comments 13 - 14: The agency reviewed the commenters’ suggestions, and the rule 

continues to allow emissions averaging of a rate, not mass, from existing units within the same 
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subcategory. EGUs in the same subcategory located at one or more contiguous properties, belonging to a 

single major industrial grouping, which are under common control of the same person (or persons under 

common control), remain eligible under to rule to engage in emissions averaging. Should a commenter 

find these requirements problematic, he or she may use another of the compliance demonstration 

approaches contained in the rule.

Comment 15: Commenter 17627 requests that regulated entities should be allowed to bubble emissions 

from EGUs within a 50 kilometer (km) radius to determine source deposition mercury “hot spots”

in Technical Support Document: National-Scale Mercury Risk Assessment Supporting the Appropriate 

and Necessary Finding for Coal and Oil-Fired Electric Generating Units (p. 6). According to the 

commenter, allowing EGUs to average emissions from regional sources will still reduce the deposition 

from sources the EPA links to the Hg “hot spots” while also providing additional compliance flexibility 

for sources that have a limited number of EGUs.

Response to Comment 15: The agency has considered the commenter’s suggestion, but, apart from the 

contiguous property eligibility criterion mentioned in the rule, emissions averaging from EGUs within a 

specific area, but not on properties adjacent to each other, will not be allowed.

Comment 16: Commenters (17623, 17655, 17705) indicate that the emission averaging criteria are too 

rigid. Commenters (17623, 17655, 17757, 17758) request broader applicability and more flexibility in 

emissions averaging. Commenters (17623, 17758) believe the limiting criteria for emissions averaging 

provisions is too rigid to provide significant flexibility or cost reductions. Commenter 17623 notes the 

inflexible structure is not needed because all facilities will collectively be subject to the same emissions 

limit and all required reductions would occur. Commenter 17758 indicates that the EPA does not 

provide details as to why it has determined that a broader approach would lessen the MACT floor, does 

not enumerate any of the implementation or enforcement issues that could arise from allowing emission 

averaging in any of the scenarios the rule bars, and this lack of information deprives commenters the 

opportunity to assess, comment on, and address the EPA’s concerns. Commenter 17758 went on to state 

that the EPA does not explain why emission averaging provisions or limitations that were applied in 

other MACT rules are applied in Utility MACT or what characteristics of those other sources are 

comparable to Utility MACT sources (i.e., why are limits that were deemed necessary for synthetic 

organic chemical manufacturing appropriately applied to electricity generation). In fact, commenter 

17758 states that the EPA appears to assume that past rulemaking limits applied to emissions averaging 

create an enforceable “criteria” that must be satisfied in this rule for utility generators. Commenter 

17758 states that the EPA has not explained why any of the additional limiting criteria are needed if the 

owner or operator can demonstrated that total averaged emissions do not exceed the limits that would be 

applied to individual units. Commenter 17758 states the EPA has not demonstrated that limiting the use 

of emissions averaging would obviate the unspecified implementation and enforcement issues that the 

EPA suggests are of concern. Commenter 17758 further states the EPA fails to recognize the compliance 

and enforcement difficulties that would be created by imposing the proposed limitations on averaging; 

for example, it would be substantially more complicated and expensive to segregate, measure separately, 

and monitor the emissions of units that share a common stack to determine that each is in continuous 

compliance with the MACT standard for a particular pollutant than to allow these units to use averaging 

by measuring common emissions from the stack.

Response to Comment 16: The agency has considered all but disagrees with most of the commenters’ 

assertions and notes that the commenters provide no data to support their assertions. We specifically

disagree that broader averaging is consistent with the statute as explained in the preamble to the HON 

NESHAP:
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The fundamental problem with the broader averaging approach[, beyond sources in the same 

category or subcategory,] is that it allows averaging among multiple sources. The HON has 

defined the source, for the purposes of this standard, as the collection of SOGMI emission points 

within a major source. Many major sources containing such points will also contain other points 

not covered by this standard but to be covered by later, different MACT standards. Each of these 

standards will have a separate floor, and the statute requires that each standard be no less 

stringent than its floor. If averaging were allowed between sources covered by two separate 

standards, it is likely that one of the sources involved in the average would be emitting HAP's at 

a level that violates the standard applicable to it. Thus, averaging between multiple sources in 

different categories is not legally defensible.

Similarly, allowing averaging between new and existing sources at the same facility would also 

likely lead to one source failing to meet its applicable standard. There are separate MACT 

standards with separate floors for new and existing sources within the HON, just as there will be 

separate standards for sources in different categories at the same site. An average that included 

sources with different floors and different standards cannot be reconciled with the statutory

requirement that each source in the category comply with the applicable standard.

59 FR 19427 (April 22, 1994)

Based on the long standing interpretation of the statute, the rule is unchanged. Further, we note that 

commenters appear to presume that the agency must justify not allowing averaging on a broader level, 

but such an assertion is not valid. CAA section 112 does not expressly authorize averaging and the final 

rule would be consistent with the statute absent any allowance for averaging. The EPA’s policy

concerning averaging is based in part on our interpretation of the statute and commenters have not 

provided a viable alternative interpretation, nor have the commenters provided information that would 

call into question our policy justifications for limiting averaging in the manner proposed. That certain 

EGU owners or operators may not be able to avail themselves of the emissions averaging options (e.g. 

because they vent units in different subcategories to a common stack) or may choose not to because they

determine that the potential benefits of averaging do not justify compliance with the requirements to 

average does not render the provisions invalid.

Comment 17: Several commenters (17623, 17627, 17689, 17736, 18037) state that limiting emissions 

averaging to only units in the same subcategory shrinks the universe of sources that can use this option. 

Commenters 17655 and 17757 encourage the EPA to allow averaging between units at different 

facilities that are under the same/common control and operating in the geographic region or at adjacent 

facilities. Commenters 17655 and 17881 encourage the EPA to allow averaging new unit emissions with 

existing unit emissions. Commenter 17623 states that not allowing new facilities to participate puts new 

generation capacity at a disadvantage and reduces the effectiveness of the averaging program. 

Commenter 17623 states that allowing emissions averaging for new facilities will incentivize installation 

of state-of-the-art controls on new units. Commenter 17655 disagrees with the EPA’s argument that 

allowing new and existing averaging would be too cost effective and states this argument would not 

stand up to a test of arbitrariness. Commenters 17758 and 18037 suggest the EPA allow emissions 

averaging across all affected units (both coal and oil) on a facility basis, including both new and existing 

units and where averaged units share a common stack. Commenter 17758 suggests the EPA allow 

broader emissions averaging where it can be demonstrated that public health and environmental benefits 

are preserved. Commenter 17881 states that averaging across multiple new EGUs would minimize the 

risk of startup, shutdown or malfunction at a single unit resulting in an exceedance of an applicable 

emission limit.
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Response to Comment 17: As mentioned earlier, the agency believes emissions averaging subject to 

certain unit eligibility criteria, including existing units within the same subcategory using emissions 

testing on contiguous properties under common control, in the rule can provide a cost-effective, flexible, 

environmentally-friendly means of demonstrating compliance. Other suggestions, such as including new 

units that can be designed for appropriate emissions control devices from the onset or mixing units from 

differing subcategories with differing emissions limits, are not consistent with the statute as discussed 

above and, in any case, we do not believe such averaging would be appropriate in any case. The rule has 

not been revised for these suggestions. Note that the final rule contains work practice standards during 

periods of startup or shutdown.

Comment 18: Commeter17758 states that the EPA previously proposed emissions averaging for EGUs 

in its 2004 proposed standards and the rationale for including this option remains valid.

Response to Comment 18: The agency thanks the commenter for his support.

Comment 19: Commenter 17705 believes EGUs should be allowed to average actual emissions data 

from CEMS to determine monthly average weighted emissions for the units participating in an 

averaging plan, as this simplifies the demonstration of compliance.

Comment 20: Commenter 17705 notes that section 63.10022 requires facilities using emissions 

averaging to also comply with operating limits for control devices and fuel limitations for Hg and 

chlorine on top of numeric stack emissions standards. Commenter 17705 states this burden can be 

alleviated by allowing an averaging plan that based on CEMS usage, as CEMS data is a more accurate 

indicator of continuing compliance with a numeric standard than operating limits set during periodic 

performance tests or fuel analyses.

Comment 21: Commenter 17705 stated that the availability of the alternate SO2 standard coupled with 

use of emissions averaging based on use of existing certified CEMS is likely to be a preferred 

compliance option for sources with existing FGD technology and should be fully accommodated in the 

final rule language.

Response to Comments 19 - 21: The agency supports the commenters’ suggestions regarding use of 

CEMS for units subject to emissions averaging, and the rule has been revised so that units that use 

CEMS can participate in emissions averaging. Note that, as stated elsewhere, the rule no longer requires 

fuel analyses for pollutants.

Comment 22: Commenter 17402 notes emission averaging is permitted under section 112 and there is 

ample precedent for allowing it. Commenter 17402 notes the emissions averaging is permitted under 

section 112(d) of the CAA(particularly given the important limitations included in the rule) and there is 

ample precedent for allowing such facility-wide emissions averaging (cites 6 part 63 NESHAP rules 

with emissions averaging). Commenter 17758 further indicates that the CAA provides flexibility in 

allowing emissions averaging broadly and does not direct the agency to promulgate standards that are 

applicable unit-by-unit or facility-by-facility; the CAA does not mandate that the EPA apply MACT 

standards on an individual unit basis; CAA section 112(d)(1) provides that the EPA shall promulgate 

regulations “for each category or subcategory of major sources and area sources of hazardous air 

pollutants...” (emphasis added); and CAA section 112(d)(2) standards are applicable to “new or existing 

sources” (emphasis added).
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Response to Comment 22: The agency acknowledges the commenters’ support for emissions averaging 

and for the agency’s discretion in designing emissions averaging provisions according to program needs. 

No changes to the rule regarding expansion of emissions averaging across subcategories or to new units 

were made.

Comment 23: Commenters (17402, 17655) support weighting by heat input (based on the performance 

test results). Commenter 17655 agrees that existing DAHS can perform these calculations and produce 

reports.

Response to Comment 23: The agency thanks the commenters’ for their support of weighting 

emissions rates by heat input.

Comment 24: Commenter 17648 supported the four criteria required by the EPA to participate in 

emissions averaging and went on to state that the EPA should also apply a discount factor to assure that 

emissions from the affected sources as they are actually controlled will be at least as stringent as the 

total sum of emissions that would be achieved if each unit at an affected source were controlled 

individually to the level required by the rule, as it has done in prior NESHAP.

Response to Comment 24: The agency disagrees with the commenter’s support for use of a discount 

factor, for under the emissions averaging procedures contained in the rule, each group of units subject to 

emissions averaging will have to meet the emissions limits of a specific subcategory. While these 

emissions limits would otherwise apply on an individual basis, through emissions averaging, the group’s 

total emissions will be no greater than the sum of the emissions from individual units. Note that the 

emissions from units that engage in averaging under this rule are not bound by a cap, but by the 

otherwise applicable emissions limit. The rule does not include a discount factor.

Comment 25: Commenter 17774 states that disallowing the new facilities from emission averaging puts 

new generation capacity at a disadvantage and reduces the effectiveness of the program. According to 

the commenter, units subject to the NSPS would have to continue to comply with the individual PM 

limits in that rule even if the emissions averaging option is used, further reducing the utility of the 

option.

Response to Comment 25: The agency disagrees with the commenter, and the rule continues to exclude 

new units from emissions averaging. As mentioned in the preamble to the HON rule (see 59 FR 19425), 

the agency does not believe the statute authorizes emissions averaging for new affected sources. In 

addition, it is most cost effective to integrate state-of-the-art controls into equipment design and to 

install the technology during construction of new sources so, even if we concluded that such averaging 

was authorized, we would decline to allow averaging of new sources. One reason we allow emissions 

averaging is to give existing sources flexibility to achieve compliance at diverse points with varying 

degrees of add-on control already in place in the most cost-effective and technically reasonable fashion. 

This flexibility is not needed for new affected sources because they can be designed and constructed 

with compliance in mind.

Comment 26: Commenter 17798 recommends initial emission averaging by utility ownership and state 

staged to facility averaging 2 years later. The commenter states that the EPA provides a mechanism in 

the NESHAP rule for the agency to approve a 1-year compliance extension on an EGU sector-wide 

basis.
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Response to Comment 26: The agency considered the commenter’s recommendation, but did not 

change the rule to allow phase-in of emissions averaging. An EGU owner or operator will need to have 

his or her emissions averaging plan developed and results of all testing in hand on or before 180 days 

after the unit’s first compliance date in the rule.

Comment 27: Commenter 17881 states that in section 63.10006(o) if emission limits are consistently

being met, then reduced frequency of testing should be allowed for the units utilizing emissions 

averaging.

Response to Comment 27: The agency disagrees with the commenter, and the rule continues to exclude 

those units associated with emissions averaging from reduced emissions testing frequency.

Comment 28: Commenter 9738 states that the inclusion of an alternative compliance provision within 

the proposed rule that would allow owners and operators of existing affected sources to average the 

emissions by sources within the same category allows more flexibility for owners. According to the 

commenter, this may increase the feasibility of the compliance deadlines in two ways: First, if cost is a 

concern, owners and operators may be able to strategically implement technology to bring their plant 

into compliance on only some of the smokestacks. The commenter states that while this could ultimately

balance the total emissions of the plant, it would require the owners and operators to raise fewer funds, 

which should thus decrease the amount of time needed to prepare fiscally for the new standards. The 

commenter states that second, if an owner or operator chose to selectively implement such technology, 

less work would need to be performed, as only a portion of the smokestacks would require retrofitting. 

Thus, according to the commenter, this should also require less time to bring the facility into 

compliance, and this alternative provision allows for companies to strategically stagger their compliance 

efforts and increases flexibility. The commenter states that further, for facilities which have already

implemented some such technology, this alternative provision may eliminate the need for additional 

action. According to the commenter, this would achieve the goals of the proposed bill by promoting the 

same reductions in emissions, thus having the same societal impact overall.

Response to Comment 28: The agency appreciates the commenter’s support of emissions averaging 

within a subcategory.

4. Clarifications and modifications to emissions averaging.

Comment 29: Commenter 17402 suggests clarifications to improve emissions averaging for 

compliance. Commenter 17402 notes that section 63.10009(f)(3) and section 63.10022(a)(1) are 

somewhat contradictory and could be interpreted as requiring compliance in the first month of collecting 

data. Several commenters (17725, 17402, 17775, 17881) recommend clarifying in section 

63.10009(f)(3) that the first compliance period begins after 12 months of data have been accumulated, 

and in section 63.10022(a)(1) that compliance is demonstrated each month, and that compliance is first 

determined after 12 months of data are collected. Commenter 17775 states that requiring compliance 

with both a monthly average and a 12-month rolling average of those values makes no sense.

Comment 30: Several commenters (17821, 17856, 17902) recommend that the EPA allow sources to 

demonstrate compliance with an averaging plan over a 12-month period and not on 30-day rolling 

average basis. Commenter 17821 further states that the primary reason for this is that the EGUs require 

periodic outages for scheduled and unscheduled maintenance. According to the commenter, when a unit 

is in an outage, the remaining units could be forced to shut down during the same period if compliance 

with an averaging plan must be demonstrated based on only one month’s data. The commenter states 
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that if however compliance with an averaging plan were based on the average of 12 consecutive months, 

a facility would be in a better position to absorb the effects of individual unit outages over the course of 

a year. Commenter 17856 further states that revising the rule as suggested would provide needed 

flexibility to the regulated community, eliminate compliance and enforcement uncertainties, and achieve 

the same emissions reductions that the EPA seeks.

Response to Comments 29 - 30: The agency has reviewed the commenters’ suggestions, and the rule 

has been revised so that the results of the emissions testing are used for each 30 boiler operating day 

rolling average during the quarter in which the emissions testing is conducted.

Comment 31: Several commenters (17402, 17775, 17881) recommend operating parameters be 

removed from the averaging plan required under section 63.10022(a)(2) to (5). Commenters further state 

that if the operating parameters are required, the averaging period for control devices should be extended 

from a 3-hour average to a 30-day rolling day average period to account for variable 

conditions. Commenters recommend that in calculating the ESP power operating parameter, the 

calculation should use the lowest (or highest) value obtained during the performance test as opposed to 

the average low (or high) values of the performance testing. Commenter 17881 further states that the 

references in section 63.10022(a)(2) through (a)(7) to the “3 hour average parameters” established 

during the performance test does not clearly line up with the requirements of Table 4 or Table 8 and is 

confusing.

Response to Comment 31: The commenters’ suggestions are moot, for the rule no longer requires 

monitoring of control device operating parameters.

Comment 32: Commenter 17174 states the EPA should clarify the deadline to established emission 

caps to demonstrate compliance with the emissions averaging option for the emission level or control 

technology. The commenter notes that section 63.10009(c) and section 63.10009(g)(2)(i) appear to have 

a contradiction in dates (30 days vs. 60 days), and the EPA should correct this in the final rule.

Response to Comment 32: The agency considered the commenter’s suggestion, and the rule now has a 

consistent date (30 days).

Comment 33: Commenters 17648 and 17881 request clarification of emissions averaging provisions, 

with assertions that the preamble indicates emission averaging provisions do not apply to units that share 

a common stack with units in a different subcategory, while the rule text in section 63.10009(h)-(k) is 

confusing, and arguably may allow sources with units in different subcategories emitting through the 

same stack to average emissions to demonstrate compliance, without clarifying that all of the other 

relevant averaging provisions, such as the emissions cap, apply.

Response to Comment 33: The agency considered the commenters’ suggestions but the rule is 

unchanged. What the rule prohibits is units from differing subcategories being included in emissions 

averaging, not only units from differing subcategories sharing common stacks. The rule provisions cited 

describe how EGUs sharing common stacks can determine compliance with an emissions averaging 

program.

Comment 34: Several commenters (17705, 17718, 17737) state the EPA should clarify in sections 

63.10009(e)(1) (initial compliance, includes SO2) and 63.10009(f)(1) (continuing compliance, no 

mention of SO2) that the SO2 surrogate limit as an alternative standard for acid gases can be used under 

the emissions averaging compliance option.
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Response to Comment 34: The agency agrees with the commenters’ suggestions, and the rule has been 

revised to include SO2 as eligible for emissions averaging.

Comment 35: Commenters 17623 and 17775 suggest the EPA include more flexibility in the 

submission timing of the emissions averaging plan, and notes that submittal 180 days prior to 

compliance is a lengthy lead time that limits the effectiveness of the EPA program because facilities 

may not have yet finished control technology installation to formulate the emissions averaging plan.

Response to Comment 35: The agency considered the commenters’ request, and the rule has been 

revised so that an emissions averaging plan must be developed by 3 years after the rule has been 

promulgated. In addition, results from all initial emissions testing must be received and ready for use in 

compliance calculations by 3 years after the rule has been promulgated.

Comment 36: Several commenters (17655, 17718, 17795, 18429) agree that 30-day block averaging 

should supplant rolling averages in a unit averaging plan, as there are inconsistencies that would accrue 

from varied operating schedules of the affected units. Commenter 17795 further states that lengthening 

the averaging period would help achieve the flexibility the EPA intended by granting facility averaging. 

Commenter 18429 recommends that emissions averaging should be based on annual mass emissions 

rather than on a rate basis, and should be allowed between any groups of sources that contractually 

commit to an emissions averaging program similar to the original NOX compliance program under the 

Acid Rain Program.

Comment 37: Several commenters (17718, 17775, 17795, 17800, 18031) state that the EPA must 

clarify ambiguities in the proposed rule and explain exactly how the provisions must be implemented. 

According to the commenters, it is unclear how to account for units which are shut down for an outage 

or whether individual unit baseline testing is necessary. Commenter 17775 suggests that in the event of a 

unit outage, the EPA should allow use of at least a 3-month average. Commenter 17795 further states 

that if one unit operates slightly above the limits could not operate during the first year of compliance, 

and the unit used to average it into compliance was in outage, this would negate any benefit or flexibility

the EPA intended by incorporating the averaging provision into the proposed rule. Commenter 17800 

recommends that the EPA adopt the averaging time of a 12-month rolling average that the State of 

Illinois has determined to be appropriate in their Mercury Rule. According to the commenter, 

lengthening of the averaging time would help to account for normal process variations and account for 

emissions during normal startup, shutdown and malfunction events.

Response to Comments 36 and 37: The agency reviewed the commenters’ suggestions, but the 30 

boiler operating day rolling average remains and no other averaging periods have been added. Should an 

EGU owner or operator choose to use emissions averaging, he or she will have up to 3 years after the 

rule is promulgated to have his or her EGUs emissions testing completed and results provided, more 

than enough time to schedule and finish planned outages. With respect to unplanned outages, other 

EGUs will need to adjust their emissions rates in order to ensure the averages remain at or below the 

otherwise applicable emissions limit. Should these requirements prove too difficult for an EGU owner or 

operator, he or she should choose another compliance demonstration option. Note that the final rule

includes work practice standards during periods of startup or shutdown, so the request to lengthen the 

averaging time to account for such periods is moot.

Comment 38: Several commenters (17718, 17737, 17775, 17821, 18031) state that all of the equations 

(Eq.1, 2, 3 and 4) seem to specify that the emission rates to be used are “determined during the most 

recent performance test”. According to the commenters, the EPA should clarify that if CEMS (i.e., 
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PM, HCl or Hg) are being used to determine compliance with the limits, values from those monitors 

could be used. Commenter 17775 recommends that the EPA should revise 40 CFR 63.10009 to include 

procedures for CEMS, and make clear that units using CEMS to calculate average weighted emissions

do not have to comply with the operating limits for control devices in proposed 40 CFR 63.10022.

Comment 39: Commenter 17718 states that if SO2 data via CEMS is being gathered for comparison 

with the acid gas alternate SO2 limit, those values should be allowed for use as on a monthly

demonstration method for HCl.

Response to Comments 38 and 39: As mentioned elsewhere, the agency agrees that units using CEMS, 

including SO2 CEMS, are eligible to participate in emissions averaging, and the rule now clarifies how 

EGUs using CEMS in emissions averaging are to determine compliance. Those units would use the 

emissions rate determined from the 30 boiler operating day period ending at the end of each month s at 

the end of each calendar month in their calculations. Note that as mentioned elsewhere, operating limits 

are no longer required for units using CEMS.

Comment 40: Commenter 17718 recommends that in determining an emission limit from different 

subcategories that emit from a common stack (40 CFR 63.10009(j)), it would be more appropriate to use 

the maximum rated heat input (or capacity) for the combined units to allow more flexibility in 

determining the common stack emission limit.

Response to Comment 40: The agency disagrees with the commenter’s suggestion that the rule’s 

emission averaging provisions need more flexibility, and the rule has not been changed.

Comment 41: Commenter 17718 requests the EPA to clarify whether a “pre-test” be conducted so that a 

comparison can be made between a “30 day after” value and the initial compliance test. The commenter 

states that the EPA should specify the notification and submittal requirements for such a test and that the 

EPA should clarify what kind of documentation is needed for the “control technology” option to prove 

that it has not become “less effective.”

Comment 42: Commenter 17881 states that the provisions of section 63.10009(c), require that “the 

HAP emission rates observed during the initial compliance test must not exceed those being achieved on 

the date which is 30 days following rule finalization or that the control technology employed during the 

initial compliance test should not be less effective for the HAP being averaged than the control 

technology employed on the aforementioned date.” According to the commenter, the existing units have 

no inherent requirement to conduct testing or control device removal efficiency evaluations prior to the 

compliance date, which is 3 years following rule finalization.

Response to Comments 41 - 42: The agency considered the commenters’ suggestions, and as 

mentioned elsewhere, the rule now clarifies that an EGU subject to emissions averaging must have its 

emissions results available for use in calculations on or before 3 years, not 30 days, after rule 

promulgation. Moreover, the rule now clarifies that an EGU owner or operator needs to ensure that the 

“design efficiency of the emissions control technology has not changed”, as opposed to ensuring that the 

“control technology” has not become “less effective,” but does not specify the kind of documentation an 

EGU owner or operator would be required to provide.

Comment 43: Commenter 17718 states that the EPA should clarify why the presence of an ESP would 

require monthly fuel content determinations.
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Response to Comment 43: The comment is moot, as the rule no longer requires fuel analysis for 

pollutants.

Comment 44: Commenter 17725 requests revision to the compliance timeframe and the addition of a 

definition of an oil-fired facility. The commenter states that clarification is needed for dual fuel units to 

average emissions of oil only units. According to the commenter, the use of interruptible natural gas can 

offset oil-fired emissions, but the availability of natural gas is often restricted, especially in the winter 

months and during the summer high demand period, and without a supply of gas in all months, a facility

will not be able to use emissions averaging for compliance because it may not meet the proposed limits 

for the initial 12-month period on a month-by-month basis.

Comment 45: Commenter 17725 requests that the use of liquid fuel should not count towards the site 

averaging compliance demonstration when the gas supply to the EGUs is unavailable due to factors 

outside of the facility’s control or when the EGU must use oil rather than gas to comply with 

environmental or market based testing requirements.

Response to Comments 44 - 45: The agency reviewed the commenter’s suggestions, but no changes to 

the rule were made. The rule already defines an oil-fired electric utility steam generating unit, and the 

rule maintains the eligibility criterion of having only those EGUs in the same subcategory as available

for inclusion in emissions averaging. Should the commenter find that his EGUs would be unable to meet 

all emissions averaging criteria, he or she should use another option to demonstrate compliance.

Comment 46: Commenter 17730 states that the emissions averaging plan is an unnecessary element of 

the proposed rule and should be eliminated from the final rule.

Response to Comment 46: The agency disagrees with the commenter’s assertion, and the requirement 

to develop an emissions averaging plan remains in the rule. The agency finds such a plan helps the 

owners and operators understand what is to be done, which units are to be included, and how 

compliance is to be determined, as well as helping regulatory agencies understand a site and its 

emissions averaging program. Note that the rule also requires plan submission and, in some instances, 

plan approval should the Administrator or a delegated authority request one or both of those activities.

Comment 47: Commenter 17736 states that the emissions averaging provisions do not provide 

operational flexibility due to the short 30-day compliance period.

Response to Comment 47: As mentioned elsewhere, the agency and other commenters believe the 

rule’s emissions averaging provisions offer much flexibility. Should an EGU owner or operator 

disagree, he or she should choose another compliance demonstration method.

Comment 48: Commenter 17775 opposes the requirement for the source to document the type, design, 

and operating specifications of the control devices installed on the effective date of the rule if 

performance test results are not available.

Response to Comment 48: The agency reviewed the commenter’s suggestion, and, apart from 

identifying the control technology from each EGU, the rule does not require other information regarding 

the control devices.

Comment 49: Commenter 17821 states that section 63.10009(g)(2)(i) requests from all units in a 

potential averaging group, that sources identify the applicable emission level or control technology that 
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is in place 60 days after the publication of the final rule. According to the commenter, that would require 

stack testing and other forms of monitoring, which a number of sources would not have performed by 

the date of the final rule. The commenter states that this suggests that some sources will have to replace 

existing control technologies with different technologies.

Response to Comment 49: The agency reviewed the commenter’s suggestion, and, as mentioned 

elsewhere, the rule now requires information, including applicable emissions level or control technology

as well as emissions test results, to be available within 3 years after promulgation.

Comment 50: Commenter 17881 states that it is not clear about how to apply emission averaging for 

CEMS versus stack testing results; i.e, how to compare a 30-day average from a CEMS to monthly stack 

test results.

Response to Comment 50: The agency agrees with the commenter, and the rule now describes how 30-

day average CEMS values will be used with quarterly stack testing data to demonstrate compliance.

Comment 51: Commenter 17821 states that it is the EPA’s intention to prevent units from using a 

lower, less restrictive emissions value in an averaging program based on the initial performance test than 

a unit was able to achieve when the final rule becomes effective. According to the commenter, from a 

practical point, this provision is flawed and unenforceable for two reasons:

a. The EPA has specified no practical way to determine what level of HAP emissions each unit is 

achieving on the date of the final rule without having a battery of performance tests on each affected unit 

and/or a program of extensive monitoring.

b. Many units will be undergoing control retrofits, such as the installation of FGD systems, sorbent 

injection, ACI, and fabric filters that will change the configuration of a unit. Some projects on their own 

could cause an increase in a unit’s emissions, such as the potential for additional particulate related 

to ACI.

Response to Comment 51: As mentioned elsewhere, the rule now requires information from emissions 

testing be received and available for use in emissions averaging calculations on or before 3 years after 

promulgation. As the emissions averaging compliance approach may require additional testing or 

retrofits, an EGU owner or operator will need to include such factors in deciding whether or not to use 

emissions averaging as a means of demonstrating compliance.

Comment 52: Commenter 17881 states that the EGUs located at a single stationary source may not 

always have identical owners and/or operators contrary to section 63.10009(a). The commenter states 

that the language at 63.10009(a) would not preclude emission averaging amongst units under partial 

owners and/or operators, but perhaps the EPA should clarify this concept in the final rule preamble so as 

to eliminate any possible confusion in the future.

Response to Comment 52: The rule remains unchanged; EGUs under common control that otherwise 

meet the eligibility criteria, as described elsewhere, could be included in an emissions averaging group.

Comment 53: Commenter 17881 states that it is not clear if these provisions apply to each individual 

unit included in the averaging plan or all units in aggregate and notes that if multiple pollutants are being 

averaged, it is possible that new control devices targeting a given pollutant (i.e., acid gases) could result 
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in a decrease in the control efficiency of another pollutant (i.e., PM or metals) and that control of a 

specific HAP could necessitate a reduction in the control efficiency for a different HAP.

Response to Comment 53: The agency believes EGU owners or operators are in the best position to 

weigh considerations mentioned by the commenter when deciding which compliance option to use. No 

change has been made to rule language regarding this comment.

Comment 54: Commenter 17881 states that the calculations at 63.10009(e)(1) and (2) should be 

dropped in their entirety as there is a major flaw in the initial qualification calculations, specifically, 

equations 1 and 2 require that the maximum rated hourly heat input (i.e., MMBtu/hr) or steam output 

(i.e., pounds) for each unit is to be used in the calculations. The commenter states that as long as the 

HAP emission rate for at least one of the EGUs to be included in the averaging plan is less than the 

applicable HAP limit, it is theoretically possible for the average HAP emission rate for the group of 

units to be compliant, but that if the EPA persists in maintaining some form of these calculations, the 

heat input or steam output used in the calculations should represent the projected monthly or annual heat 

input which will be achieved under the averaging plan. According to the commenter, this would allow 

those EGUs which will rely on capacity factor as part of the averaging plan to account for such reduced 

utilization in the calculations.

Response to Comment 54: The agency disagrees with the commenter’s concern, and the rule has not 

been changed. An EGU owner or operator will have at least 3 years to get initial emissions testing 

complete and should be able during that time to have each of the EGUs fully operable for the time 

necessary to conduct emissions testing. If an EGU is unavailable, an EGU owner or operator could 

exclude that unit from the emissions averaging group or choose another method of demonstrating 

compliance.

Comment 55: Commenter 17881 states that the term “heat capacity” is improper in context of section 

63.10009(f)(1) and (2), as heat capacity generally refers to the amount of heat required to change a 

substance’s temperature by a specified amount; the term “heat capacity” should be replaced with “heat 

input”. The commenter states that for Equation 3, the term Hb is currently specified as “The average 

heat input for each calendar month of EGU, in units of MMBtu”; the units of MMBtu represent the total 

monthly heat input, not the average monthly heat input (which would generally be expressed as 

MMBtu/hr); and thus, the term “average” in the definition for Hb should be replaced with “total.”

Response to Comment 55: The agency agrees with the commenter that the equations 1 and 2 should 

refer to heat input, while equation 3 should refer to total monthly heat input, and the rule has been 

revised with these clarifications.

Comment 56: Commenter 17881 states that in section 63.10009(e) and (f), the equations 1 through 5 

must be revised or clarified. The commenter states that all emission rates are expressed in units of 

lb/MMBtu or lb/TBtu, which ignores the fact that compliance on a lb/MWh or lb/GWh basis is also an 

option per Table 2 of the proposed rule. According to the commenter, if the EPA intends to allow the 

use of emission averaging to demonstrate compliance with pound per unit of electrical output limits, it 

may be appropriate to include additional equations which use electrical output as opposed to heat input 

or steam output for weighting purposes.

Response to Comment 56: The agency agrees with the commenter that an emissions rate based on 

electrical output, as well as on heat input, is appropriate for emissions averaging, and the rule has been 

revised to include rates based on electrical output.
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Comment 57: Commenter 17881 states that the paragraph (g)(2)(vii) is confusing, which states that the 

averaging plan must include a demonstration that compliance with each of the applicable emission limits 

will be achieved. Commenter is confused about what emission rates should be used to make this 

demonstration.

Response to Comment 57: The rule’s emissions averaging plan is intended to describe how each EGU 

emissions averaging group meets its emissions limit. One way of accomplishing this is to provide the 

results of each emissions test, along with requisite heat input information and the equations and results 

of the equations, in the emissions averaging plan.

Comment 58: Commenter 17881 states that section 63.10009(h) does not include SO2 in the list of 

those pollutants which may be averaged for common stacks. The commenter states that if this is just an 

error, then the EPA should correct prior to rule finalization.

Response to Comment 58: As mentioned earlier, the rule has been revised to include SO2 in the list of 

those pollutants which could be used in emissions averaging.

Comment 59: Commenter 17881 states that the section 63.10009(i) stipulates that individual units 

sharing a common stack must vent through a common emissions control system. Commenter 

recommends that if EGUs associated with the common stack are all affected units within the same 

category, compliance should be allowed at the common stack based upon treating such averaging group 

as a single stack.

Comment 60: Commenter 17881 states that equation 6 of 63.10009(j)(1) is supposed to be used to 

determine the common stack emission limit in cases where it is shared by EGUs in different 

subcategories. According to the commenter, the current equation is lacking in several regards, and in 

cases where the common stack emission levels can comply with the most stringent of the applicable 

emission limits, this would negate the need to calculate custom common stack emission limits based 

upon prorating the emission limits for applicable subcategories.

Response to Comments 59 - 60: The agency agrees with the commenter’s first suggestion, and the rule 

has been revised to treat emissions from a common stack used by only EGUs eligible for emissions 

averaging as a single unit. The agency disagrees with the commenter’s second assertion, and the rule has 

not been changed. Existing EGUs from the same subcategory can share a common stack and be included 

in emissions averaging provided that EGUs not in the emissions averaging group (perhaps because they

are new or they belong to a different subcategory) can be turned off during emissions testing of the units 

within the emissions averaging group or that every EGU meets the most stringent emissions limit 

applicable to any EGU. Should an EGU owner or operator find these eligibility criteria burdensome, he 

or she should choose another compliance demonstration option.

Comment 61: Commenter 17881 requests that the heat input/steam output records as required by

section 63.10032(e) should be kept on a monthly instead of daily basis, as all related calculations in 

63.10009 are on a monthly rather than daily basis.

Response to Comment 61: The agency disagrees with the commenter’s suggestion because the rule 

contains a 30 boiler operating day rolling average, meaning that heat input is required on a daily, not 

monthly, basis.
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Comment 62: Commenter 17913 states that the emissions averaging demonstration should only be 

based on an averaging period consistent with the given emission standard. According to the commenter, 

for example, if emissions averaging is used to demonstrate compliance with a 30-day emission standard, 

then the compliance demonstration should only be based on each 30-day compliance period. There is no 

need or benefit to requiring instantaneous compliance with the standard during an initial performance 

test, as currently required by the proposed regulation. The commenter states that the requirement to 

demonstrate instantaneous compliance with a 30-day limit through emissions averaging 

using performance test data eliminates much of the benefits of allowing for an emissions averaging 

approach and doesn’t provide benefits for facilities that wish to limit use of less-controlled units.

Response to Comment 62: The agency agrees with the commenter’s suggestion, and the rule has been 

revised to stress compliance with the 30 boiler operating day rolling averages. Note that this means the 

quarterly emissions testing value is used each day during the quarter. Should an EGU owner or operator 

find such an approach problematic, he or she should choose another compliance demonstration option.

Comment 63: Commenter 19120 requests revision of the rule to allow for PM CEMS emissions data to 

be used in emissions averaging to show compliance with metal HAP emissions. The commenter states 

that this request could be completed through a site-specific alternative monitoring request per 40 CFR

63.8(f), but due to the potentially large number of facilities requesting a site specific approval to use 

alternative monitoring and emissions averaging plans, the EPA should include this option directly in the 

final rule. The commenter states that because approval from the EPA is required before a source may

use the alternative monitoring procedure, this could hinder the ability for sources to plan in advance and 

be proactive with installation of compliance monitoring equipment.

Response to Comment 63: As mentioned elsewhere, the rule now allows EGUs that use CEMS, 

including PM CEMS, to be eligible for emissions averaging. Note that data from a PM CEMS would be 

used to show compliance with the filterable PM, not non-Hg HAP metals, emissions limit.

5. Opposition to discount factor.

Comment 64: Numerous commenters (17714, 17718, 17402, 17623, 17689, 17705, 17716, 17725, 

17730, 17731, 17737, 17774, 17775, 17816, 17820, 17821, 17885, 17904, 18014,18025, 18449, 18498, 

18023) disagree with use of a discount factor. According to the commenters, imposition of a discount 

factor effectively lowers the allowable emissions for those sources without any justification. The 

commenters note that the EPA has used discount factors in other NESHAP where the agency believed 

there was variation in the types of units engaged in averaging. The commenters states that 

the EGUs covered by this rule are fairly homogeneous, and the current proposal does not allow 

averaging between units of different subcategories. Commenter 17904 states that a discount factor will 

simply act as a deterrent to emissions averaging.

Comment 65: Commenters 17402 and 17716 notes the discount factor increases the stringency of the 

emissions standards (amounts to an “above the floor” standard) for sources participating in emissions 

averaging. Commenter 18023 stated that tightening the standards by any percentage for sources that 

emissions average makes an impossible compliance situation even worse. Commenter 17402 notes that 

the discount factor is not being applied in the Utility MACT to account for variation in types of units, as 

was the case where discount factors have been applied for other NESHAP. Commenters 17402 and

17623 agree with the EPA that the “homogeneous” nature of the sources eligible for the Utility MACT 

averaging provision makes a discount factor unnecessary. Commenters 17402 and 17623 agree that 

requirements to monitor and demonstrate compliance assure environmental benefits are achieved and 
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also make the discount factor not appropriate. Commenter 17705 concurs that emissions averaging 

for EGUs that are co-located at a single facility should be straight-forward. Commenter 17705 indicates 

that the NESHAP numeric limits and the additional requirements for control device operating 

parameters and fuel limits already reduce the usefulness of emissions averaging as a compliance option, 

and if the EPA further adds a discount factor, the commenter suspects emission averaging will not be a 

viable compliance alternative for any sources.

Comment 66: Commenter 17648 states that using a discount factor would be more consistent with the 

HON Rule. Commenter 17648 notes that the HON Rule was clear that the cost savings for sources 

choosing emissions averaging should be considered in determining the appropriateness of a discount 

factor. 59 FR 19430. The commenter states that more recently, the EPA relied upon its reasoning in the 

HON Rule to apply the 10 percent discount in the emissions averaging provisions for ICI Boilers (see 76 

FR 15619; 75 FR 32035), and that its decisions in the HON and ICI Boiler NESHAP were well founded 

and necessary to assure that sources opting to use emissions averaging were emitting at levels no less 

stringent than would be required under a unit-by-unit MACT standard. The commenter states that the 

EPA offers no rational basis for failing to adopt the same approach in this rule.

Comment 67: Commenter 17714 states that allowing averaging without discounting would provide a 

positive incentive to encourage companies to upgrade or install controls that would achieve reductions 

beyond compliance requirements and allow the utilities to achieve more cost-effective reductions overall 

by investing resources where the greatest reductions can be made.

Comment 68: Commenter 17768 states that applying a discount factor would essentially penalize 

averaging and disincentivize sources from using this option and that is also possible that averaging may 

lead to fewer reductions in emissions and thus fewer benefits to the general public.

Comment 69: Commenter 17928 states that averaging provides valuable flexibility but is already

constrained by the differing schedules of plant outages at the same facility, as well as emissions 

variability. The commenter states that a ten percent penalty further limits the utility of this option.

Response to Comments 64-69: The agency reviewed the commenter’s concerns and suggestions, but 

decided not to change the rule by including a discount factor for those EGU owners or operators who 

choose to use emissions averaging. The agency agrees with many of the commenters who pointed out 

EGU homogeneity as being a reason why emissions averaging without a discount factor is well-suited 

for this rule. Requirements for units subject to the HON rule, which covers a broad number of unit types, 

products, and processes need not be forced upon EGUs which differ generally only in the fuel used to 

produce electricity. The agency believes that difference is accounted for in this rule by prohibiting units 

from differing subcategories – which are fuel based – from participating in emissions averaging. The 

agency believes the EGU owner or operator flexibility coupled with the lower cost advantage of 

emissions averaging makes such a program a viable choice, particularly for little used or soon-to-be 

retired EGUs. Should an EGU owner or operator disagree, he or she should choose from among the 

other compliance demonstration options.

6. Support of discount factor.

Comment 70: Commenter 17648 supports the four criteria required by the EPA to participate in 

emissions averaging and states that the EPA should go further and also apply a discount factor, as it has 

done in prior NESHAP. Commenter 17648 states the proposed emissions averaging provisions do not 

sufficiently recognize and compensate for the fact that averaging may not assure that all units are being 
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controlled aggregately to a degree no less stringent than they would need to be controlled if they were 

controlled individually. In failing to incorporate a discount factor, Commenter 17648 states the EPA 

may unfairly advantage multiple-unit sources over single-unit EGUs. Commenter 17648 notes that 

having accounted for variability in setting emission limitations by calculating MACT floors based upon 

the 99% UPL, the EPA has provided sources with ample protection from anomalous 

outcomes. According to the commenter, the 99% confidence level was established to account for 

variability, measuring the variability of single-unit, single measurements from the average, but under the 

EPA’s averaging provision, a multiple-unit facility will reduce variability by averaging both between 

units and over time. According to the commenter, the 99th UPL for facilities that average would be 

closer to the actual average of the top 12% than the 99th UPL for an individual measurement at an 

individual facility, and thus, sources with multiple units eligible for averaging may be able to take 

advantage of averaging to avoid installing or operating controls that would be required for individual 

sources. The commenter states that incorporating a discount factor is important to maintain a level 

playing field, to ensure that sources will in fact install controls that reduce emissions while providing 

flexibility to do so in the most cost-effective manner possible and that it is also the only way to ensure 

that the limit actually equals the average attained by the average of the best performing 12% of the 

sources within the subcategory.

Comment 71: Commenter 17648 disagrees with the EPAs suggestion that homogeneity of sources 

makes a discount factor unnecessary, and notes that the substantial subcategorization into 11 different 

subcategories in the ICI Boiler NESHAP undercuts the EPA’s rationale for not proposing a discount 

factor in the Toxics Rule. In the ICI Boiler NESHAP, commenter 17648 states that the subcategorization 

reduced variation among sources within the subcategory, and that NESHAP nonetheless retained a 

discount factor. 76 FR 15612. Commenter 17648 states that the EPA’s rationale also fails to account for 

the mathematical/statistical basis for requiring a lower limitation when averaging is allowed. According 

to the commenter, by basing the initial limit on the 99% UPL rather than the more conventional 95 

percent UPL in both rules, the EPA has already accounted for any greater variability within the pertinent 

subcategories. Commenter 17648 states that if there is less variability within the EGU subcategories, this 

would only suggest that the EPA should employ a somewhat smaller discount, and would not support 

eliminating the discount altogether.

Comment 72: Commenter 17648 supports the emissions cap for any individual regulated unit operating 

above the emissions limitations that would apply to that unit at the level achieved 30 days after 

promulgation of the Toxics Rule, however, this cap alone will not achieve sufficient assurance that 

emissions averaging will be at least as stringent as the conventional MACT.

Comment 73: Commenters 17648 and 17789 state that prior NESHAP have relied on additional 

safeguards such as the cap only as a supplement to the 10 percent discount and urge the EPA to continue 

to use the criteria to limit averaging.

Comment 74: Commenter 17718 states that imposition of a discount factor effectively lowers the 

allowable emissions. According to the commenter, a discount factor is unnecessary because the 

proposed rule incorporates a number of other safety factors that obviate the need for a discount factor.

Comment 75: Several commenters (19536, 19537, 19538) states that the EPA should add a discount 

factor requiring lower emissions from plants which comply by averaging the emissions of multiple units. 

According to the commenter, the agency’s variability analysis is based on emissions from three test runs 

from a single boiler, operating over a 2 (Hg and PM) or 3 (acid gases) hour period, and by allowing 

averaging, the EPA is effectively allowing compliance to be measured based upon a far larger number of 
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test runs, and operating hours – over which there will be far less variability and thereby allows sources 

to emit hazardous pollution well in excess of the actual emissions of the best performing similar plant or 

plants. The commenter states that the EPA should, as a general matter, establish standards that are 

consistent in their form with those the agency uses when it assesses variability; its standards will not 

otherwise reflect the performance of the best source or sources. According to the commenter, in this 

instance, if the EPA allows units to combine their emissions for purposes of compliance, it should recalculate the variability associated with multiple-unit emissions, and establish a corresponding 

“discount” in the standards for multiple units.

Response to Comments 70-75: The agency considered the commenters’ suggestions but did not change 

the rule to include use of a discount factor. As mentioned elsewhere, the agency agrees with the 

suggestion that other safety factors in the rule obviate the need for a discount factor. The agency notes 

that while emissions averaging could begin upon promulgation of the rule, it must start within 3 years of 

promulgation. Finally, the agency disagrees with the suggestion that another variability component need 

be considered for those EGU owners or operators who choose to engage in emissions averaging; the 

current UPL analyses was developed to take factors such as those mentioned by the commenter into 

account.

7. Facility averaging provisions should be modified to allow for alternative mass limits.

Comment 76: Commenter 17877 supports the idea of facility emission averaging, in as much as it may

provide real operational flexibility to sources. According to the commenter, however, the averaging 

provisions of the proposed rule are so restrictive that they are unlikely to be used, and the 10 percent 

“discount factor” of which the EPA is seeking comment will certainly deter averaging since artificially

lowering the standards will render the already complicated task of compliance even more difficult. The 

commenter states that there is no legitimate reason for imposing a 10 percent penalty on sources that 

seek to average emissions.

The commenter states that total emissions from a single facility have the same impact on public health 

regardless of whether each unit at the facility meets the MACT limits or all units meet the MACT limits 

in the aggregate -- the total emissions from the facility are the same, and the 10 percent penalty on 

operational flexibility has no public health benefit.

Comment 77: Commenter 18788 finds that in practice the draft model for source averaging would 

penalize a facility when the best performing units are not operating. The commenter states that at a 

facility where eligible units are combined under a weighted average emission rate, the emission rate 

average of the operating units will calculate higher when the best performing unit(s) are shut down and 

emitting no HAP what-so-ever, and that this effect is especially pronounced when the best performing 

unit is the largest among the group.

The commenter presented Example 1 below of a hypothetical facility, with all units online and in 

compliance with the total particulate limit of 0.03 lb/MMBtu on a facility basis.

Example 1: All Units Online

In the second example, the newest and best performing unit is offline and mass emissions from the 

facility are decreased by as much as 30% as compared to Example 1, but the facility is now out of 

compliance with the total PM limit on a weighted average basis. According to the commenter, the 

facility is therefore penalized for emitting less.
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Example 2: Unit 3 Offline

Commenter 17877 suggests that EPA could address the averaging penalty in one of two ways: First, the 

EPA could allow for the facility total heat input to be fixed at all times in the denominator of the 

averaging equation for each unit. According to the commenter, for the hypothetical facility, the hourly 

averaging calculation would be as so:

(Unit 1 Emission Rate * Actual Heat Input / 12,000)

(Unit 2 Emission Rate * Actual Heat Input / 12,000)

+ (Unit 3 Emission Rate * Actual Heat Input / 12,000)

Facility Average Emission Rate

The commenter states that according to this method, the facility is actually encouraged not to operate 

units and emit less, and enforceability is strengthened and facility compliance is simplified since the 

MACT limit can be clearly and consistently compared to the Facility Average Emission Rate at all 

times. According to the commenter, as currently drafted, the facility average method is of little use and 

creates a constant moving target for the agency and the regulated facility.

The commenter states that as an alternative, or in addition to the above, the rule could be written to 

include an alternate mass emission limit for the facility. According to the commenter, in this case, the 

annual mass emissions would be based on the allowed emission rate multiplied by the hourly heat input 

of the unit over the course of a year (included in document).

The commenter states that both of the proposed changes to the facility averaging provisions listed above 

fit squarely within the generally applied limits on the “scope and nature” of past rulemakings where 

facility averaging is allowed. The commenter asserts that if the EPA is serious about providing 

operational flexibility to facilities, then it must make substantial revisions to the averaging provisions of 

the rule.

Response to Comments 76 and 77: : While the agency appreciates support for use of emissions 

averaging without a discount factor, as mentioned elsewhere, the agency disagrees with the commenter’s 

views on the suitability of mass emissions for emissions averaging in this rule. The agency believes it 

would be inappropriate to introduce a new emissions limit based on mass only without appropriate 

notice and comment on that suggestion. The rule’s emissions limits remain unchanged. Should an EGU 

owner or operator find the rule’s existing emissions averaging procedures too stringent, he or she should 

choose from the other compliance determination options.
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5C03 - Compliance: Fuel switching 

Commenters: 16705, 17400, 17697, 17725, 17737, 17756, 17774, 17810, 17813, 17820, 17840, 17852, 

17853, 17881, 17901, 17902, 17904, 17912, 17930, 18038, 18421, 18428, 18477, 18502, 18575, 19536, 

19537, 19538, 18023

1. Coal switching.

Comment 1: Several commenters (16705, 17400, 17697, 18038, 18575) point out that the proposed 

rules assume that all coal types can still be used with available control technologies, but this may not be 

the case. Such fuel switching from one coal type to another or fuel blending can be very expensive for a 

municipal utility. Commenter 17697 adds that Guam is very restricted in fuel choices, and the GPA must 

rely on oil for the near to midterm.

Comment 2: Commenter 18023 states that while decisions will be made to change the fuel supply for 

some coal-fired units to natural gas-fired units based on the economics of available alternatives, it is 

important to note that any decisions to change the fuel for an existing coal unit to natural gas or oil 

would never be economic when compared to business as usual and would only occur because of the 

requirements imposed by the proposed rules. Commenter states that changing fuel to natural gas also 

presents important reliability considerations, including the capability for back-up fuel, such as oil, in 

case of supply disruptions because natural gas cannot be stored on-site.

Comment 3: Commenter 17881 states that rail congestion and increasing transportation cost limit the 

viability of the PBR coals option. Commenter adds that the chlorine content in western coal can vary

widely, making DSI a non-viable option for every unit.

Comment 4: Commenter 18421 cites the URS report which points out that coal switching is potentially

an option for compliance for some coal units burning lignite. Commenter adds that plants burning Texas 

lignite will need to remove mercury at high levels to comply, and switching to western subbituminous 

coal could significantly decrease mercury emissions due to Hg content of coal and improved ACI 

performance.

Response to Comments 1 - 4: The EPA has not mandated fuel switching as a compliance option – nor 

has the EPA used fuel switching to set emission floors or as a ‘beyond-the-floor’ option. The EPA does, 

however, recognize that fuel switching is a legitimate compliance option that will be considered and 

likely implemented by some facilities. Low sulfur sub-bituminous is now widely available and is burned 

across the contiguous U.S. states to comply with SO2 limits. The EPA is aware of facilities in the East 

(e.g., Florida, Georgia, Maryland, Connecticut, and Delaware) and in the West (e.g., Oregon, 

Washington, and Arizona) that are firing or co-firing sub-bituminous coal. The EPA maintains that 

control technology options are available to retrofit existing facilities to allow them to meet the existing 

source emission limits without having to switch fuels.

2. Opposition to fuel switching to natural gas.

Comment 5: Commenter 17881 states that natural gas transmission and storage infrastructure does not 

exist to support the option of fuel switching to natural gas and adds that it cannot be put in place within 

the constraints of a MACT time-line.
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Comment 6: Commenter 17881 states that exclusive use of natural gas at Consumers Energy’s Karn’s 

Oil/Gas Fired Units – 3 & 4 (currently rated at 638 MW each, but less than 5 percent capacity factor) 

would require these units to be de-rated 50 percent to about 300 MW each or have significant boiler 

modifications to allow the firing of 100 percent natural gas at the boiler design capacity. According to 

the commenter, the natural gas supply infrastructure would have to be significantly upgraded in order to 

supply the volume of gas needed to operate the units at full capacity. The commenter states that these 

units are called on only when electric load demand is high, as in the summer of 2011, and perform a 

vital role to meet load demand.

Comment 7: Commenter 17901 states that natural gas units are not covered under the proposed Utility

MACT, and the EPA has given no indication that it will establish any stringent limits for natural gas 

units comparable to those required from coal-fired units. Commenter states that the proposed MACT is a 

continuation of an ongoing pattern of disparate treatment for coal utilities. Commenter disagrees with 

the EPA’s consideration of requiring fuel switching from coal to gas as a potential “beyond-the-floor”

control, although the EPA properly rejected the use of natural gas as a control option. Commenter 

disagrees with consideration of fuel switching to an entirely different fuel with totally different delivery

systems, types of combustion, and emissions control systems to be a feasible option at all. Commenter 

supported this point by citing the EPA’s statement that, “natural gas pipelines are not available in all 

regions of the U.S., and natural gas may not be available as a fuel for many EGUs.” Commenter also 

states that the EPA notes that the relative cost of a switch to natural gas from coal was many times 

higher than the cost to install additional control equipment on coal plants.

Comment 8: Commenter 17912 states that switching from coal or oil to natural gas is not appropriate as 

a control option and not feasible for many units and concurs with the EPA’s proposal not to require fuel 

switching as a “beyond-the-floor” option for the EGU MACT. Commenter agrees with the EPA reasons 

for not requiring fuel switching to natural gas, which is delivered through pipelines, is not available 

everywhere in the U.S., where pipelines do exist, natural gas may not be available throughout the year 

(e.g., the heating season), and the cost of such fuel switching would be prohibitive in many

circumstances. Commenter urges the EPA not to modify or reconsider this proposal not to use natural 

gas as a “beyond-the-floor” option.

Response to Comments 5 - 8: The EPA has not mandated fuel switching as a compliance option – nor 

has the EPA used the potential for fuel switching to set emission floors or as a “beyond-the-floor”

standard. The EPA does, however, recognize that fuel switching is a legitimate compliance option that 

will be considered and likely implemented by some facilities. However, the EPA maintains that control 

technology options are available to retrofit existing facilities to allow them to meet the existing source 

emission limits without having to switch fuels.

3. Concerns with ability to meet liquid fuel-fired limits.

Comment 9: Commenter 17912 disagrees with the EPA’s suggestion that oil-fired units have the 

compliance option of using low-HAP oil, citing that the EPA fails to identify anywhere in the ICR fuel 

data any oil sufficiently low in HAP that a liquid fuel-fired boiler has used this method to comply.

Comment 10: Commenter 18502 points out that compliance with the proposed metals and HCl 

limits by residual oil-fired EGUs assumes a level of consistency in flue gas composition that has not 

been demonstrated as compared to coal-fired units. According to the commenter, there are some key

differences between coal and oil relative to compliance with the proposed emission limits:
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a. The concentrations of metals and chlorine in coal can be measured, but are generally below analytical 

detection limits for residual oil. The commenter states that during ICR testing, quantifiable levels of 

chlorine were detected in the fuel used by just two of the eight EGUs tested and nickel was the only 

metal detected in more than a quarter of the samples.

b. Coal is supplied to an individual EGU from suppliers in defined geologic and geographic areas 

that have definable fuel characteristics, whereas deliveries of crude oil to refiners and fuel oil to 

consumers are based on international market conditions. The commenter states that while fuel 

specifications regarding some parameters are possible (e.g., sulfur content), use of fuel 

specification to control chlorine and metals content of oil is untested.

c. Air pollution control technologies to reduce criteria pollutant emissions from coal-fired boilers is well 

documented and can be used to estimate reductions in HCl and metals emissions; however, control 

technologies are less commonly used with oil-fired boilers, and the correlation between reductions in 

PM and reductions in metals is not as well defined.

Response to Comments 9 - 10: As noted elsewhere in this document, EPA has reassessed its analysis of 

the oil-fired EGU data. The EPA believes the limits in the final rule, which are based on emissions data 

from existing liquid oil-fired EGUs, are achievable by oil-fired EGUs. Further, EPA is providing for an 

alternate compliance assurance alternative for the acid gas HAP of measuring the moisture in the oil in 

lieu of testing for HCl and HF.

4. Opposition to conversion of liquid-fired EGUs from RFO to DFO.

Comment 11: Commenter 17725 points out several challenges to converting liquid-fired EGUs from 

residual fuel oil (RFO, oil grades No. 4, No. 5, and No. 6) to distillate fuel oil (DFO, oil grades No. 1 

and No. 2), and states that these oils have distinct separate characteristics and they are not 

interchangeable:

a. According to the commenter, different ASTM Standard D396-10, Standard Specifications for Fuel Oil 

(Standards) include differing requirements (e.g., flash point, viscosity pour point) that affect different 

storage requirements. According to the commenter, many RFO storage facilities have heated storage 

tanks, an oil recirculation system, and heated conveyance piping to the boiler, and conversely, the 

storage of DFO does not require heated systems.

b. According to the commenter, combustion of RFO and DFO is not interchangeable within a boiler, and 

a fuel switch to DFO requires significant modification. According to the commenter, because of the 

different physical characteristics, the combustion process equipment is designed and installed to reflect 

the characteristics of the fuel being combusted. The commenter states that boiler burners and burner tips 

used to combust RFO cannot be used to combust DFO and that the converse is also true. The commenter 

states that once introduced to the boiler, proper combustion of RFO can only be obtained by using steam 

atomization or mechanical atomization, and conversely, combustion of DFO does not require an 

atomization system.

c. According to the commenter, an EGU using RFO will not have the same output (steam flow and the 

resulting generation) using the same amount of DFO because of the lower heating value of DFO. 

According to the commenter, the lower output of a DFO unit would be approximately 15 – 20 percent; 

for example, a rated 200 MW unit using RFO would only be a 160 – 170 MW unit using RFO.
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d. According to the commenter, conversion to DFO would entail modifications to the boiler combustion 

system, as well as a conversion of the oil storage tank system, including replacement of burners and 

burner tips and modifications to the burner management system. The commenter states that prior to 

performing the physical changes, a boiler combustion study must be performed to ensure the burners are 

properly designed for the boiler’s configuration.

e. According to the commenter, to prevent contamination from RFO, an existing RFO storage tank and 

the associated piping must be cleaned.

f. According to the commenter, change out of the piping and pumps are required so that the required 

amount of DFO (which has a lower heating value) can be delivered to the boiler to maintain full load 

capability.

g. According to the commenter, a spill or leak of DFO will tend to flow further and faster than a spill or 

leak of RFO, due to the lower viscosity.

h. According to the commenter, many existing storage tank systems would need retrofitting to provide 

adequate secondary containment for the lower viscosity DFO to address regulatory requirements for fuel 

storage (i.e., SPCC, OPA-90). According to the commenter, this is a significant undertaking for large 

RFO tanks, as they typically use earthen secondary containments, since RFO does not permeate into the 

soil when spilled; whereas, converting to DFO storage would require expensive impermeable liner 

installation and other changes. Commenter 17725 cites an example cost estimate for liner installation for 

a relatively small two million gallon tank being from $500,000 to $800,000 and adds that their Oswego 

facility has multiple 11 million gallon tanks, the cost of which to line one of these tanks would be on the 

order of two to three million dollars.

i. According to the commenter, the capital investment for a conversion to DFO is site specific 

but, NRG estimates that the conversion cost for their facilities ranges from $12 – 17/installed kW per 

site, and this is only for the capital expense portion.

j. According to the commenter, there are additional costs for testing the unit to ensure that the 

conversion will allow the EGU to meet the emission rate (prior to the actual compliance stack test). The 

commenter states that the tuning and testing will require EGU full load operations for approximately 40 

hours. A 400 MW unit can consume approximately 500 gallons per minute of fuel, and that for the 40 

hours of tuning/testing, this relates to 1.2 million gallons of fuel, or approximately 29,000 barrels of 

fuel. The commenter states that additional fuel use is required for the start-up and ramp up to full load 

and shut down of the unit. The commenter states that the additional cost for the 29,000 barrels of DFO is 

over $500,000, based on the 5-year average price presented (Commenter included Table 2.3.2, FiveYear Average Fuel Prices at New York Harbor, Docket No. The EPA-HQ-OAR-2009-0234).

k. The commenter states that beyond the capital expenditures to retrofit units for DFO, the use 

of DFO rather than RFO will increase the dispatch price of the EGU. According to the commenter, for 

an EGU with a 10,000 Btu/kW-hr heat rate, the dispatch price for the unit based on fuel alone will 

increase between 35 and 45 percent. The commenter states that as oil-fired EGUs are generally high on 

the supply curve due to their relatively high heat rates, they are primarily dispatched for reliability at a 

low level in preparation for spikes in demand (when their output will be increased), to cover for known 

outages of lower cost units, or to provide transmission support. The commenter states that conversion 

to DFO will increase their production costs up to 45% or more and put significant upward pressure on 

electric costs during times of system duress.
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l. According to the commenter, conversion to DFO presents compliance risks for EGUs, as compliance 

is based on the assumption that the source’s emissions will be in the same range as those DFOfired units setting the standard. The commenter states that it is highly doubtful that an engineering and 

construction firm would provide a guarantee that a conversion to DFO would in fact meet the proposed 

total metal limits. According to the commenter, the rule does not provide an exemption or waiver for 

an EGU that has been converted to a lower emitting liquid fuel and still cannot meet the total metal 

limit. The commenter states that faced with the possibility of making a significant capital investment 

with no assurance of ultimately achieving compliance, the EGU may be forced to retire as the 

uncertainty is too great. The commenter states that EGUs that may or could comply would simply not 

make an investment that large without reasonable assurance of being able to comply rendering 

unintended outcomes of the rule’s primary objective.

Response to Comment 11: The EPA acknowledges that capital expenditure may be needed to be able 

to convert from residual oil to distillate oil. However, we would also note that other commenters indicate 

that the switch is not as extreme or burdensome as commenters here note. Further, we are not 

subcategorizing distillate vs. residual oil in the final rule. We note that all of the distillate oil-fired EGUs 

for which we have data are in the limited-use subcategory noted elsewhere in this document. The MACT 

floor pool for liquid-oil fired EGUS is comprised of sources burning residual oil-fired EGUs with ESPs. 

Therefore, EPA maintains the final limits are achievable by residual oil-fired EGUs without the need for 

oil switching, although such switching is always an option to an EGU that does not want to install PM 

controls.

5. Opposition to use of proposed rule/limits to necessitate fuel switching.

Comment 12: Commenters 17813 and 17930 discourage the setting of limits that are so low as to 

possibly necessitate fuel switching, stating that this would be a requirement found nowhere in the CAA, 

is contrary to decades of precedent, and would set a dangerous policy that would undermine regional 

electric reliability and affordability. Commenters add that lignite-burning power plants are mine-mouth 

power plants wedded to their mines, and a switch to subbituminous coal to meet proposed emission 

limits would mean sacrificing significant financial investments in fuel delivery, transportation, and 

storage, not to mention boiler design. According to the commenters, boilers are designed for specific 

types of fuel, as well as ranks within a fuel type, and there are limits due to the heat values and amount 

of coal being burned that restrict lignite power-plants from increasing non-lignite coal consumption. The

commenters state that these issues were obviously considered and given weight when the EPA 

developed the subcategory for <8,300 Btu/lb coal.

Comment 13: Commenter 17840 states that the EPA should articulate how a future plant can comply

with all of the proposed standards, and draws a conclusion that the EPA is proposing a beyond-the-floor 

fuel switching measure for new sources, while inconsistently rebutting mandating fuel switching from 

coal to natural gas as “an unreasonable regulatory option.”

Comment 14: Commenter 17930 states opposition to requirements that impose fuel switching and notes 

that fuel switching is not a viable option for many lignite units in Texas. Commenter states that for 

many, the necessary infrastructure (e.g., rail lines, unloading stations, transport areas) does not exist to 

begin burning other types of coal. Commenter states that the EPA’s cost estimates for facilities to switch 

to other coal types and construct this infrastructure is incomplete and provides the following points as 

flaws in the EPA cost analysis:
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a. According to the commenter, the EPA’s cost estimate does not include all requisite infrastructure 

costs (e.g., dust collection, conveyors, fire protection, ventilation, ESP performance, water cannons, 

significant boilers modifications to burn 100 percent PRB coal.

b. According to the commenter, the EPA has not adequately taken into consideration the potential

escalation of PRB coal and transportation prices once the coal fleet responds to this and other pending 

regulations (e.g., the Cross-State Air Pollution Rule [CSAPR]).

c. According to the commenter, the EPA’s cost prediction for the “beyond-the-floor” limit is far too low 

because the EPA fails to include the cost of installing fabric filters in the price analysis. The commenter 

states that the EPA’s cost analysis assumes that all units within this subcategory will require capital 

investments in fabric filters that are attributable to the proposed MACT standard for PM (as a surrogate 

for non-Hg metallic HAP). According to the commenter, this analysis determines the marginal capital 

costs attributable to the BTF option requiring installation of ACI systems to reduce Hg emissions to 4.0 

lb per trillion Btu (Commenter cites a Beyond the Floor Letter, Shelley Johnson to Bill Maxwell, 

included in Docket No. The EPA-HQ-OAR-2009-0234). Commenter points out that this assumption is 

flawed for two reasons:

1. Fabric filters will not necessarily be installed at these units. According to the commenter, while 

surrogates may be a means of compliance for lignite-fired EGUs, the rule still allows for the control of 

the non-Hg metallic HAP themselves, which may not require a fabric filter.

2. The EPA cannot exclude the costs of a control technology installed to control Pollutant A (which 

incidentally controls for Pollutant B), while counting the benefits of the limitation on Pollutant B. The 

commenter states that benefits cannot be counted twice, while costs only counted once.

Response to Comments 12 - 14: The EPA has not mandated fuel switching as a compliance option –

nor has the EPA used fuel switching to set emission floors or as a ‘beyond-the-floor’ option. The EPA 

does, however, recognize that fuel switching is a legitimate compliance option that will be considered 

and likely implemented by some facilities. Low sulfur sub-bituminous is now widely available and is 

burned across the contiguous U.S. states for compliance with existing SO2 standards. The EPA is aware 

of facilities in the East (e.g., Florida, Georgia, Maryland, Connecticut, and Delaware) and in the West 

(e.g., Oregon, Washington, and Arizona) that are firing or co-firing sub-bituminous coal. Control 

technology options are available to retrofit existing facilities to allow them to meet the existing source 

emission limits without having to switch fuels. We maintain that the final limits were established in 

accordance with the statute and have considered costs to the extent required.

6. Request for expansion of provisions for exclusion from requirements.

Comment 15: Commenter 17737 agrees with the provision to exclude units that did not fire coal or oil 

for more than 10.0 percent of the average annual heat input during the previous 3 calendar years or for 

more than 15.0 percent of the annual heat input during any one of those calendar years from 

subpart UUUUU. However, Commenter recommends that this be expanded to include units that have 

burned coal for more than 10.0 percent during the 3 years immediately following promulgation of the 

final rule, or 15 percent during any one of those years, but elect to switch to burning natural gas for at 

least 90 percent of the annual heat input beginning prior to the date the units must be in compliance. 

Commenter adds that this provision should not require the unit(s) to be modified by making the coal 

burning capabilities inoperable or needing to modify the permit to remove the coal burning capabilities 

and cites that the proposed definition of “fossil-fuel fired” unit (76 FR 25020) seems to require that the 
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owner physically remove all coal burning capabilities and that coal burning would not be allowed in the 

permit. Commenter states that they (TEP) own and operate H. Wilson Sundt (Sundt) Unit 4, which is 

capable of burning coal and/or natural gas, and TEP would like to have the option to use this flexibility

to bum different types of fuel. TEP would like to maintain the ability to continue to bum coal in this unit 

for the next 3 years but switch to natural gas prior to the date the unit would need to be in compliance 

with subpart UUUUU. According to the commenter, under the present proposed rule, TEP would still be 

subject to the subpart UUUUU monitoring, reporting, and recordkeeping requirements even if it ceases 

to burn coal prior to the compliance date, posing an unnecessary regulatory burden without 

environmental benefit. Commenter suggests that if a unit is capable of burning different types of fuel, 

including coal, then the owner/operator should be required to maintain records of the quantity and type 

of fuel burned to assure that at least 90 percent or more of the heat input is from natural gas and that the 

operating permit would be revised to require the owner/operator to apply for a permit revision to comply 

with the requirements of subpart UUUUU prior to resuming to burn coal in quantities ≥ 10 percent of 

heat input.

Comment 16: Commenter 17756 cites that in order to convert a unit to natural gas or biomass and be 

exempt from the proposed Toxics Rule, the owner would need to convert the unit to 100 percent 

biomass or natural gas within three years and remove all capability to burn coal or oil. Commenter 

suggests that alternatively, the unit could convert to biomass or natural gas by 2012 and ensure that the 

heat input from coal or oil in 2012, 2013, and 2014 is below the annual 15 percent heat input 

requirement and the 3-year requirement of 10 percent heat input.

Comment 17: Commenter 17756 recommends that the EPA revise the definition to change the “lookback” period to begin three years after the unit’s final compliance date. According to the commenter, 

this change would not penalize a unit that switches to natural gas and retains the ability to combust coal 

or oil for having burned coal or oil in the period before compliance. Commenter also suggests that a unit 

that switches to natural gas and later switches back to highly controlled coal use should not be in 

violation of the 3-year average for the years it was burning natural gas.

Comment 18: Commenter 17820 recommends that the EPA change the “look-back” period under the 

applicability criteria for units that cease combustion of coal or oil to provide absolute assurance that 

units converted to natural gas or biomass are exempt from the rule.

Comment 19: Commenter 17902 recommends that section 63.9981 further clarify that existing coal or 

oil-fired EGUs that combust natural gas as of the required compliance date are not subject to the 

requirements of subpart UUUUU.

Comment 20: Commenter 17904 recommends that the EPA should revise the applicability language to 

allow generators to retain the option of simply restricting dual fuel-fired units as a compliance strategy –

but they should not be forced to begin fuel restrictions immediately. According to the commenter, this 

would amount to making the compliance date equivalent to the effective date of the rule. Commenter 

recommends that the EPA should revise the definition to clarify that any unit which actually burns 90 

percent natural gas during a calendar year is excluded from compliance obligations, irrespective of 

whether the unit fired some large percent of fossil fuel prior to the effective date.

Comment 21: Commenter 18428 supports the provision in the EGU MACT that a unit that burns on 

average at least 90 percent of fuel as natural gas during, “the previous 3-year period,” is considered 

natural gas-fired and therefore not subject to the EGU MACT. However, the commenter requests that 

the EPA add to this provision that units that switch to natural gas by the compliance deadline and 
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continue to operate that way thereafter should also not be subject to the oil-fired EGU MACT 

requirements.

Response to Comments 15 - 21: As noted elsewhere in this document, the EPA has revised the 

definitions to account for the “look back” provision noted by commenters.

7. One-year extension for compliance.

Comment 22: Commenter 17852 concurs that a 1-year extension can be appropriate when a utility is 

undertaking a technically complex project, such as converting an existing coal-fired boiler to burn 

natural gas or building a new NGCC, but only where the utility has timely gone about such action and 

can demonstrate that such action does in fact require an extra year to comply. Commenter adds that there 

are many things that utilities can do to achieve compliance within the 3-year time-frame, and cites the 

following:

a. Various sources have suggested that controls can be installed within the 3-year time-frame, including, 

Exelon Corporation which has said in reference to the Boiler MACT, “We know we can install controls 

in three years because many plants have already done it in that timeframe.”

b. Existing, high-efficiency NGCC units are underutilized and can immediately increase generation, 

allowing for older, uncontrolled coal plants to be retired, without an extension of the MACT regulatory

time-frame.

c. Various sources have shown that new natural gas generation can be built within the mandated 3-4 year 

time-frame.

Response to Comment 22: Responses to comments of this type are provided in the preamble to the 

final rule.

8. Blending fuels.

Comment 23: Commenter 17774 points out that the proposed Utility MACT definitions of various 

regulated subcategories seem to overlap in cases where a unit is not exclusively burning coal and 

requests clarification in the regulation of sources which blend fuels to clearly delineate which standards 

apply in cases where fuel blending is employed. Commenter cites an example where a coal-fired unit 

which burns more than 10 percent petcoke could arguably either fall under the solid oil-derived fuel 

subcategory or the coal-fired subcategory:

a. The commenter states that the proposed rule defines “oil” as “crude oil or petroleum or a fuel derived 

from crude oil or petroleum, including distillate and residual oil, solid oil-derived fuel (e.g., petcoke) 

and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).” The 

commenter states that the proposed rule further defines the “unit designed to burn solid oil-derived fuel 

subcategory” as “any EGU that burned a solid fuel derived from oil for more than 10.0 percent of the 

average annual heat input during the previous 3 calendar years or any one of those calendar years, either 

alone or in combination with other fuels.” According to the commenter, consequently, if a coal-fired 

unit burns more than 10 percent petcoke, it could arguably fall into the solid oil-derived fuel 

subcategory.
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b. The commenter states that however, the coal-fired subcategory also indicates that it includes units 

burning petcoke. The commenter states that the proposed rule defines a coal-fired unit as a unit that 

“burns coal or coal refuse either exclusively, in any combination together, or in any combination with 

other fuels in any amount.”

Commenter 17774 urges the EPA to clarify which standards apply to units burning coal and petcoke and 

suggests that the EPA require affected sources to comply with the standard applicable to the majority of 

fuel burned (e.g., greater than 50 percent).

Comment 24: Several commenters (19536, 19537, 19538) provides comment in response to the EPA’s 

request to comment on, “whether the proposed rule should address how sources that change fuel input 

(e.g., burn solid waste or biomass), or otherwise take action that would change the source’s 

applicability...must demonstrate continuous compliance with all applicable standards.” Commenters

state that EGUs designed to fire solid fossil fuels burn a mixture of coal types as well as other solid fuels 

including solid oil-derived fuels (petcoke), biomass, and other solid fuels. Commenters suggest that any

subcategorization must be based on design differences which materially affect the availability of cleaner 

fuels, or other methods of reducing pollution. Commenters take the position that where a plant 

voluntarily (or for economic reasons) chooses to burn a high-polluting fuel, that decision should not 

affect the standards applicable to the plant, with one exception: the agency is obligated to distinguish 

between EGUs that are waste combustors (and thus subject to stricter standards governing 

waste combustors) from EGUs that are primarily fossil-fueled. Commenters concur with the EPA’s 

proposed rule definitions for the solid fuel subcategories defining coal fired units as, “electric utility

steam generating unit meeting the definition of ‘fossil fuel-fired’ that burns coal or coal refuse either 

exclusively, in any combination together, or in any combination with other fuels in any amount (76 FR 

25122, Proposed section 63.10042 definitions). The commenters state that “Fossil fuel-fired,” in turn, is 

defined as, “to the extent that an EGU that is capable of burning primarily coal or other solid fossil fuels 

to generate electricity, and also elects to co-fire biomass to meet some other statutory requirement, it 

must continue to meet the MACT limits for the subcategory in which it is listed.” Commenters add that 

this is particularly important for biomass, as burning green wood produces more of various regulated 

HAP than does burning coal (Commenters cite Figure 1 in Docket No. The EPA-HQ-OAR-2009-0234). 

Commenters also add that it would be unlawful for the EPA to finalize a MACT subcategory that would 

worsen the HAP emissions profile of the EGU beyond what it would be absent the biomass burning.

Response to Comments 23 - 24: As noted elsewhere in this document, the EPA has revised the 

definitions to address commenters’ concerns.

9. Disagreement That the EPA Did Not Use Best Available Data/Information to Support Fuel 

Switching Analysis for Proposed Rule with Respect to Natural Gas

Comment 25: Commenter 17810 states that natural gas is currently under-utilized for power generation 

and could be called into duty very quickly to provide clean energy and an immediate pollution 

reduction. In addition to significant HAP reductions, the commenter states that emissions reductions in 

NOX and SO2 can be realized from fuel switching (coal to natural gas) in the power generation sector. 

Commenter recognizes that the EPA may not consider it realistic to require all coal plants to shift to 

natural gas by setting a beyond-the-floor standard based on natural gas combustion; however, points out 

that some owners and operators may find that converting to natural gas (retrofit, repowering, new 

construction, or use of underutilized existing plants) is a cost-effective compliance strategy. Commenter 

concludes that efficiency benefits of NGCC combined with natural gas and coal price projections 

make NGCC clearly preferable to advanced coal-fired boilers for new base-load generation, citing IPM 
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runs commissioned by commenter and review of the EPA’s IPM results. Commenter cites that the EPA 

shows in the IPM results that no new pulverized coal capacity is added through 2030, even in the base 

case, while 68 GW of NGCC capacity is added under the base case assumptions and 75 GW of NGCC 

capacity is added under the policy case assumptions through 2030 (EPA, IPM Analysis of the Proposed 

Toxics Rule, March 2011, available at http://www.epa.gov/airmarkets/progsregs/epa-ipm/toxics.html). 

Commenter states that it is important for the EPA to use accurate and current data to appropriately

characterize the most up-to-date natural gas infrastructure, supply, cost, and technology associated with 

natural gas availability, and cites several areas of disagreement with the EPA’s assumptions used in 

development of the Proposed Rule:

a. For existing EGUs, Commenter 17810 cites that the EPA determined that fuel switching (coal to 

natural gas) was not an appropriate beyond-the-floor option, citing two primary reasons: (1) natural gas 

supplies are not available in some areas, and (2) increased fuel costs cause a unit’s total incremental cost 

of electricity (COE) to be significantly higher compared to the incremental COE of other options. 

Commenter 17810 states that the EPA included only two documents to justify these conclusions 

(Technical Support Document [TSD] for the Transport Rule [sic], “Coal-to-Gas Conversion (C2G)”

(March 4, 2011) and Documentation Supplement for EPA Base Case v4.10_PTox – Updates for 

Proposed Toxics Rule (March 2011), available at http://www.epa.gov/airmarkt/progsregs/epaipm/docs/suppdoc.pdf, Docket ID No. The EPA-HQ-OAR-2009-0234). Commenter states that both 

these documents are associated with the cost of coal-to-gas conversion, but that neither addresses the 

natural gas supply issue, and cites several references to the contrary (Docket ID No. The EPA-HQOAR-2009-0234). Commenter 17810 states that there does not appear to be any evidence in the record 

to support the conclusions that natural gas pipelines are not available in all regions of the U.S., natural 

gas may not be available as a fuel for many EGUs, and even where pipelines provide access to natural 

gas, supplies of natural gas may not be adequate, especially during peak demand (e.g., the heating 

season). The commenter states that currently available information refutes the notion that there is 

insufficient supply or inadequate infrastructure to support increased demand for natural gas for EGUs. 

The commenter states that recent estimates from both the U.S. Energy Information Administration (EIA) 

and the MIT Energy Initiative indicate sufficient supply to meet increasing demand for natural gas-fired 

EGU capacity. According to the commenter, the actual delivery of supply to a specific consuming 

market occurs hand-in-hand with the development of demand, and the delivery of supplies into the 

vicinity of an EGU should not be expected to precede the demand from an EGU by a period of years.

i. According to the commenter, the EPA’s analysis of costs of constructing new laterals to distribute 

gas to existing coal-fired units demonstrates that some coal-fired power plants have relatively 

inexpensive access to natural gas mainlines, while other coal-fired power plants will have a more 

difficult time accessing natural gas mainlines, but the analysis appears to contradict the EPA’s 

statement that natural gas pipelines are not available in all regions of the U.S. The commenter states 

that the average coal-fired boiler at a power plant that does not already have access to natural gas 

would need 57.4 miles of pipeline to meet natural gas demand, and the median pipeline requirement 

is 26.2, meaning that 50 percent of coal-fired power plants would need 26.2 miles or less of 

additional pipelines. The commenter states that while this suggests that in some cases access to 

natural gas may require significant investment and construction, it does not support the idea that 

natural gas is unavailable.

ii. According to the commenter, the recently released INGAA Foundation study of midstream 

infrastructure needs indicates that natural gas producers are playing an important role in funding 

needed pipeline infrastructure as they compete to deliver their natural gas to markets.
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iii. The commenter states that according to the U.S. EIA, “the U.S. natural gas pipeline network is a 

highly integrated transmission and distribution grid that can transport natural gas to and from nearly 

any location in the lower 48 States.”

iv. The commenter states that Department of Energy figures indicate that the interstate and intrastate 

transmission network feeds over 1.1 million miles of regional lines in some 1,300 local distribution 

utility networks, collectively delivering natural gas to 62 million customers in the U.S.

v. According to the commenter, the natural gas industry has shown an ability to respond to changing 

market conditions. The commenter states that according to EIA, 3,893 miles of new natural gas 

pipelines were added in 2008 alone.

vi. The commenter states that the recent INGAA Foundation study includes FERC data showing 

from January 2000 to February 2011, interstate pipeline companies received approval to construct 

over 16,000 miles of interstate pipelines and add an additional 14,600 miles of expansion pipeline. 

According to the commenter, the INGAA Foundation projects similar development over the next 

10 years.

vii. The commenter states that according to a recent report issued by the MIT Energy Initiative on 

the Future of Natural Gas (“MIT Natural Gas Report”), the production and delivery infrastructure of 

natural gas in the U.S. is “both mature and robust.” The commenter states that major changes in U.S. 

gas markets have prompted significant additions to the country’s pipeline network over the last 

several years; between 2005 and 2008, pipeline capacity additions totaled over 80 billion cubic feet 

per day (Bcfd), exceeding those from the previous four-year period by almost 100 percent. Additions 

of 44.5 Bcfd in 2008 alone exceeded total additions in the five-year period between 1998 and 2002. 

According to the commenter, MIT’s Interim Report to the Future of Natural Gas noted, “On the gas 

infrastructure side, concerns have been raised about the availability of gas pipeline capacity for the 

additional gas requirements of this option [displacement of coal generation], but preliminary analysis 

indicates that the industry has the ability to meet the needs for additional pipeline capacity.” The 

commenter states that the MIT Natural Gas Report concluded that: (a) there are abundant supplies of 

natural gas in the U.S., despite their relative maturity, natural gas resources continue to grow; (b) the 

role of natural gas is likely to continue to expand under almost all circumstances, as a result of 

availability, utility, and comparatively low cost; and (c) increased utilization of 

existing NGCC power plants provides a relatively low-cost short-term opportunity to reduce U.S. 

carbon dioxide emissions by up to 20 percent in the electric power sector and significantly reduce 

sulfur dioxide, nitrous oxide, particulates, and mercury with minimal additional capital investment in 

generation and no new technology requirements.

viii. The commenter states that the FERC also noted significant recent increases in the storage 

capacity for natural gas. The commenter states that more than 107 Bcf of incremental working gas 

capacity was added in 2009, including more than 50 Bcf in the Gulf region. The commenter states 

that traditional production area storage allows suppliers to respond more adeptly to market signals, 

and as a result, those signals are moderated. The commenter states that reporting on 2010 storage, 

the FERC said, “Natural gas storage levels were high for much of the year and reached record levels 

in November.”

ix. The commenter states that generally speaking, estimates of the available domestic supply of 

natural gas have expanded significantly over just the past five years. According to the commenter, in 

a 2009 Report addressing the supply of technically recoverable natural gas in the United States at 
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2008 year-end, the Potential Gas Committee reported that the currently available total supply of 

natural gas was 1,836 trillion cubic feet (Tcf), which represented an increase of 39 percent (516 Tcf) 

over the Committee’s year end estimate for 2006. The commenter states that in the 2011 Report, the 

Potential Gas Committee increased this estimate to 1,898 Tcf. According to the commenter, the MIT 

Natural Gas Report also reviewed U.S. gas resource estimates from several sources, including the 

2009 Potential Gas Committee Report, and assumed a mean remaining resource base of 

approximately 2,100 Tcf. The commenter states that the U.S. EIA recently estimated that annual 

production of natural gas will increase by 25 percent from 2009 to 2035. According to the 

commenter, many of these sources attribute this dramatic increase in recoverable natural gas supplies 

in large part to the discovery of significant shale gas deposits and advances in technology for 

recovery of gas from these resources.

x. The commenter states that studies have concluded that not only is there an expanding supply of 

natural gas, but due to declining costs of recovering that gas, domestic gas production is likely to 

increase significantly. According to the commenter, as summarized in a recent report issued by the 

Bipartisan Policy Center and American Clean Skies Foundation, “While estimates of supply have 

increased, the cost of producing shale gas has declined as more wells have been drilled and new 

techniques have been developed and field tested. The commenter states that the MIT study estimated 

that between 250 and 300 Tcf of shale gas can be produced at prices below $8/MMBtu (in 2007 

dollars), and more recently, ICF International estimated that almost 1,500 Tcf are available at 

$8/MMBtu, while 500 Tcf are available at $4/MMBtu and 1,500 Tcf are available $5/MMBtu (ICF 

Figure 1 included in Docket EPA-HQ-OAR-2009-0234).

xi. According to the commenter, significant changes have occurred both with respect to natural gas 

supplies and storage infrastructure over the past 10 years that alleviate heating season supply 

concerns. With respect to storage, the commenter states that FERC reports in the State of the 

Markets Report that in late November 2009, U.S. inventories were 99 percent of capacity, suggesting 

that there is sufficient gas reserve capacity to address demand spikes during the heating season. The 

commenter states that greater reliance on shale extraction methods in the production process helps 

mitigate concerns about responsiveness on the supply side when demand increases. According to the 

commenter, unlike conventional production, in which a producing well needs to be kept “on” in 

order to maximize the amount of recoverable gas, production from shale wells is far more elastic, 

allowing producers to ramp up production in response to price signals, thereby helping to avoid the 

dramatic price swings that happen when it takes longer for production levels to respond to changes 

in demand.

b. For new EGUs, Commenter 17810 states that the EPA fails to consider best available data on supply

and cost when identifying beyond-the-floor options. According to the commenter, in making the 

determination that fuel switching to natural gas is not a reasonable option, the EPA falls back on a 

generic statement that natural gas supplies are not available in some areas; whereas, commenter posits 

that it establishes with the above references that natural gas is widely available throughout the country 

and new power plants can be sited with pipeline capacity and proximity as a key consideration. 

Commenter states that the EPA also suggests that “limited emissions reductions in combination with the 

high cost of fuel switching and considerations about the availability and technical feasibility makes this 

an unreasonable regulatory option that was not considered further.” Commenter states that this 

statement, without supporting data or discussion, is not sufficient to eliminate the consideration of a 

beyond-the-floor option. Commenter 17810 states that they are not aware of technical challenges 

associated with designing and constructing a new unit to combust natural gas instead of coal, and 

suggests that the EPA evaluate the cost of a new NGCC unit for providing base load power as compared 
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to a new advanced coal-fired boiler. Commenter cites the EPA’s modeling in support of the rule, which 

projects no new advanced coal-fired boilers to be constructed through 2030, even in the base case 

scenario without imposition of the rule.

c. Commenter 17810 cites other regulatory contexts where it says that EPA has read similar provisions 

of the CAA to include the use of lower-emitting processes and practices, including switching to cleaner 

burning fuels:

i. BACT Guidance issued in March 2011 includes switching to clean fuel as a “control option” for 

purposes of performing a BACT analysis under the PSD program.

ii. BART guidance under the Regional Haze program includes inherently lower emitting processes, 

such as processes using cleaner fuels, as “potentially applicable retrofit control technologies.”

Comment 26: Commenter 17852 states that switching from coal-fueled electric power generation to 

generation from natural gas or renewable energy can achieve substantial reductions in toxic air 

emissions, stating that natural gas plants emit no mercury and negligible other HAP in contrast to coal. 

Commenter adds that numerous modern, high-efficiency NGCC plants with significant unused capacity

are available to replace existing coal-fired generation and that dramatically expanded U.S. natural gas 

reserves and infrastructure have reduced gas price volatility (citing several references in the Docket 

EPA-HQ-OAR-2009-0234). Commenter 17852 recommends that the EPA re-evaluate the docket and 

issue specific guidance and indicate in the preamble to the utility MACT final rule that fuel switching to 

natural gas is a means to comply with the standard, providing guidance how various types of fuel 

switching to natural gas can allow coal/oil units to comply, including:

a. Converting existing coal boilers to natural gas;

b. Retiring coal plants and building new natural gas plants (either at the same location or a new 

location); 

c. Increased co-firing with natural gas; and

d. Increasing use of existing, underutilized natural gas power plants.

Commenter 17852 states that the EPA made several unsupported assumptions in rejecting natural gas as 

a compliance option and cites several references (included in Docket EPA-HQ-OAR-2009-0234) to 

support this point:

a. Commenter 17852 states that, in comparing costs for fuel switching to natural gas, the EPA only 

focuses on one type of fuel switching (converting existing coal boilers to natural gas, which results in a 

loss in boiler efficiency). Commenter states that a more logical evaluation would be to compare the 

expensive retrofits facing existing coal plants to retiring the aging plants and either using existing 

natural gas generation from unused capacity or building a new NGCC (at same location or new site). 

Commenter adds that the EPA’s analysis also ignores the possibility of co-firing natural gas in coal or 

oil-fired boilers. Commenter conducted such an economic evaluation and found that the break-even gas 

price for increasing use of existing NGCC vs. retrofitting coal plants with a scrubber and SCR is 

approximately $6/MMBtu. Similarly, commenter’s evaluation found that the break-even price for 

building a new NGCC is approximately $5.50/MMBtu. According to the commenter, thus, using the 

natural gas prices that the EPA assumes in their fuel switching analysis ($5.74/MMBtu), increasing the 
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use of available capacity from an existing NGCC is the economical choice, and building a new NGCC is 

virtually equivalent. Commenter adds that the economics for using natural gas improve when including 

additional costs that may be imposed on coal-fired power plants under other regulatory initiatives.

b. Commenter 17852 states that the EPA finds coal to gas retrofits more expensive than other retrofit 

options based on fuel prices of coal at $2.13/MMBtu and natural gas at $5.74/MMBtu, despite the 

capital and O&M costs of the coal to gas retrofits being less expensive than other options.

c. Commenter 17852 states that it should be recognized that the EPA’s assumed natural gas price 

($5.74/MMBtu) only assumed installation of scrubbers and SCR, but if additional controls are required 

(e.g., coal ash, cooling water issues), it can become more economical to shutter old coal plants and build 

new NGCC plants.

d. The commenter states that with respect to co-firing with natural gas, the EPA notes that, ”For the oilfired subcategory, we did not include data obtained from EGUs co-firing natural gas in the existing 

source MACT floor analysis because those emissions are not representative of EGUs firing 100 

percent fuel oil (76 FR 25045). Commenter 17852 recommends that the EPA should clarify in the 

guidance that co-firing with natural gas can reduce the emissions of either coal or oil-fired units and 

may be an effective means of compliance.

e. Commenter cites that the EPA has found that regulation of HAP emissions from natural gas power 

plants, “is not appropriate or necessary because the impacts due to HAP emissions from such units are 

negligible.”

f. Commenter refutes the EPA’s contention that natural gas may not be a cost effective option, stating 

that fuel switching to natural gas is made more feasible by the fact that dramatically expanded U.S. 

natural gas reserves and infrastructure have reduced gas price volatility and are projected to make 

natural gas affordable for the foreseeable future. Commenter cites that the EPA RIA for the proposed 

rule includes projections that natural gas prices are not expected to exceed their 2008 Levels through 

2035 and that the EPA projects that the proposed MACT standard would increase power sector 

delivered natural gas prices by only about 1% percent from 2015-2030, which is a negligible increase 

and shows the ability of natural gas to provide fuel to power plants without dramatically increasing 

natural gas prices (Figure 1, 2010 to 2011 Annual Energy Outlook of the EIA included in Docket EPAHQ-OAR-2009-0234).

g. Commenter 17852 cites their own reports and studies, adopted by a task force that represented natural 

gas producers and distributors, consumer groups, large industrial users, and independent experts, which 

found that abundant natural gas supplies coupled with increased storage and import capability, as well as 

the ability to use long-term contracts and hedging arrangements, provide for a stable natural gas price 

horizon and opportunity to expand use in the U.S. Commenter states that the EPA must take into 

account their recent studies, which show that available gas-fired generation capacity exists in most 

regions of the U.S. According to the commenter, their report found that in 2008, CCGT plants 

operated with only a 33% capacity factor. If only the more efficient group of CCGT plants (heat rate 

of 9,000 Btu/kWh) were operated at 60% of capacity instead of at 33 percent, ACSF’s report (which 

also cited a MIT report) indicates that could replace up to 60,000 MW of out-of-compliance 

base load units that may be retired. The commenter states that the geographic distribution of 

this available CCGT capacity is rather well aligned with the location of most vulnerable coal-fired units 

(Figure 2, Docket EPA-HQ-OAR-2009-0234).
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h. Commenter 17852 cites that the MIT report also found that there is sufficient surplus NGCC capacity

to displace roughly one-third of U.S. coal generation. The commenter states that according to MIT, 

substitution of this NGCC capacity would reduce CO2 emissions from the power sector by 20 percent 

and yield a major contribution to the control of criteria pollutants.

i. Commenter refutes the EPA’s contention that natural gas pipelines are not available in all regions of 

the U.S., citing the EPA’s own data. The commenter states that as part of the rulemaking, the EPA 

undertook an analysis for coal boilers in the U.S. to “determine the miles and associated cost of 

extending pipeline laterals from each boiler to the interstate natural gas pipeline system.” According to 

the commenter, this study found that the median connection length is only approximately 26 miles and 

the median incremental cost is only approximately $14 million. The commenter states that 

given that environmental retrofits for coal plants may cost hundreds of millions of dollars, $14 

million for the median cost of a new gas lateral connection is comparatively minor. Commenter adds 

that the EPA may have used assumptions that overstated the length and cost of these new gas 

connections. Commenter also cites that the Department of Energy (DOE) has found that that natural 

gas lines can, “deliver fuel to power plants in most locations in the lower 48 states.” Commenter 

recommends that the EPA correct the record.

j. Commenter refutes the EPA’s contention that, “even where pipelines provide access to natural 

gas, supplies of natural gas may not be adequate, especially during peak demand (e.g., the heating 

season).” Commenter points out that the development of shale gas has vastly increased onshore gas 

production, gas storage capacity has increased over the last few years, and the FERC has been 

responsive to the need for additional pipeline capacity to bring gas to new markets. Commenter 

acknowledges that, while it is possible that unforeseen emergencies may create temporary curtailment, 

these types of emergencies are manageable, and not unlike other energy delivery issues that occasionally

occur.

Comment 27: Commenter 17853 states that the EPA has the authority granted in section 112 of the 

CAA to consider fuel switching as an alternative to achieving emission reductions during the 

development of the Utility MACT and refutes the EPA’s statement in the preamble that “supplies of 

natural gas may not be adequate” with the following points:

a. According to the commenter, at current consumption rates, North America has over a 100-year supply

of natural gas.

b. According to the commenter, natural gas drilling and extraction technologies (including shale gas) 

have dramatically improved over the last 5 years, and the lead time to respond to increased demand has 

been significantly decreased thus reducing price volatility. The commenter states that the Potential Gas 

Committee of the Colorado School of Mines releases a biennial assessment of the nation’s natural gas 

resources, and review from the 2006 assessment to the 2011 assessment indicates an increase in natural 

gas total resource base from 1,321 to 1,898 trillion cubic feet (44 percent).

c. According to the commenter, in addition to the natural gas available within the U.S., the natural gas 

pipeline transmission systems of the U.S. and Canada are highly integrated, providing access to 

Canada’s vast gas reserves, which coupled with Canada’s relatively small population, provides the U.S. 

with an additional reliable source to help meet rising demand.

d. The commenter states that according to the U.S. EIA Annual Energy Outlook 2011 projections, 

production from shale formations in the U.S. grew by an average annual rate of 17 percent per year from 
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2000 to 2006, and in the years from 2006 to 2010, U.S. shale gas production grew by an average annual 

growth rate of 48 percent.

e. According to the commenter, the natural gas industry has proven the ability to develop and distribute 

natural gas required to meet increased demand from the EGU sector into the future.

f. Commenter states that the EPA’s analysis on fuel switching is flawed because it mistakenly presumes 

retired generation must be replaced by building a gas-fired unit in the same footprint. According to the 

commenter, with greater reliance on local resources, retiring coal-fired EGU capacity can be replaced by

natural gas-fired EGUs built closer to load, reducing dependence on interstate pipelines.

g. The commenter states that historical trends also demonstrate that concerns over natural gas 

availability and abundance are unfounded. The commenter states that according to the July

US EIA Natural Gas Monthly report, “nearly 237 GW of natural gas-fired power generation capacity

were added between 2000 and 2010, representing over three-fourths of total generation capacity 

additions over that period.” The commenter asserts that despite this growth in natural gas-fired 

generation capacity additions, natural gas prices in 2010 remained relatively low and production rates of 

natural gas continue to grow.

Commenter 17853 states that an immediate HAP benefit to the environment can be realized by 

increasing utilization of existing and new natural gas-fired EGUs and cites the results of the Utility

Study and the preamble to the proposed rule as accurately depicting that the emissions of priority HAP 

from natural gas-fired EGUs are negligible compared to coal. Commenter adds that natural gas-fired 

EGUs also deliver significant emission reductions of PM, SO2, NOX, CO2, VOC, and regional haze 

precursors.

Commenter 17853 points out that the EPA did not consider increased zero HAP emitting base-load 

capacity as a fuel switching alternative. According to the commenter, since natural gas is not the only 

source for power generation outside of coal combustion, the EPA could consider including a “fuel 

neutral” fuel switching requirement which provides offsets for increasing zero HAP base-load 

generation directly towards a corresponding decrease in coal-fired generation.

Response to Comments 25 - 27: The EPA declined to propose as a beyond the floor level of control a 

requirement that coal- and oil-fired EGUs convert to natural gas. For existing sources, we indicated that 

we did not believe the supply of and transmission infrastructure for natural gas were sufficient to convert 

all existing units to natural gas. 76 FR 25046. We also determined that the incremental cost of electricity

(COE) for converting all existing coal- and oil-fired EGUs to natural gas would be between 4 and 22 

times the costs of compliance with the MACT floor level of control. Id. For new EGUs, similar to that 

for existing EGUs, we determined that natural gas was not available in all parts of the country. We also 

concluded that we would decline to adopt a requirement that all new EGUs be natural gas-fired even if 

we concluded that natural gas supplies were available because it would effectively prohibit construction 

of new coal-fired EGUs and we did not believe that to be a reasonable approach to regulating HAP 

emissions from EGUs. 76 FR 25049. We are not revising our decision in this final rule in response to the 

comments and we address commenters’ specific points below. 

Commenters cite studies and reports that show that the supply of natural gas is growing, that the cost of 

natural gas is generally stable, and that the availability of natural gas is expanding. One commenter even 

notes that one study specifically considered such issues in the context of the proposed EGU NESHAP. 

Even assuming all the studies are accurately characterized, the results do not in any way support a 
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determination that conversion of all coal- and oil-fired EGUs to natural gas is cost effective or that the 

supply and transmission capabilities are sufficient to support such a conversion. We have not conducted 

specific studies of the cost of natural gas if we required all coal- and oil-fired EGUs to convert to natural 

gas, but we note that currently coal- and oil-fired EGUs account for approximately 45 percent of the 

nation’s commercial electric generation capacity. If that level of capacity were to be required to be 

replaced by natural gas, it defies all reason to assume anything other than that the price of natural gas 

would increase precipitously. In addition, the commenters maintain that the supply is currently sufficient 

and that the transmission capabilities are expanding, but no commenter indicates that the current 

situation (or the situation within three years) would allow a wholesale conversion to natural gas. The 

highest estimate provided by commenters is that one third of the coal-fired generating capacity could be 

replaced. We question whether even one third of current capacity could be replaced without some risk to 

reliability given the fact that there are annual natural gas curtailments in certain parts of the country with 

the current supply of natural gas. Even for new sources, the commenters have not shown that natural gas 

is available in all parts of the country and the DOE report that is cited indicates that “most” not “all” 

parts of the country have access to natural gas. In addition, we continue to believe that a final rule that 

expressly prohibits new coal construction is not reasonable. For all these reasons, we maintain that our 

proposed determination not to require switching to natural gas as a beyond the floor level of control 

remains valid. 

We also note that commenters appear to conflate the availability of natural gas as a cost effective 

compliance alternative with the availability of natural gas as a beyond the floor requirement applicable 

to all sources in a particular subcategory. We acknowledge that some sources will co-fire natural gas 

with coal or oil as a compliance option and that other EGUs will be converted to burn 100 percent 

natural gas. Both approaches are valid means to comply with the standards contained in the final rule; 

however, the availability of these compliance alternatives does support a determination that natural gas

conversion is available for all EGUs as a beyond the floor MACT standard. 

The EPA did not presume as one commenter suggests that all new natural gas units must be located at 

current EGU facilities, but when evaluating whether to establish a beyond the floor level of control for a 

existing sources the Agency does consider what the subject EGUs would have to do to comply with the 

beyond the floor standard. For new units, we do not have sufficient information at this time to support a 

determination that the electric transmission capabilities are sufficient to locate all EGUs near natural gas 

pipelines and assure the necessary delivery of electricity.

10. Concurrence and caution for delegation of state programs.

Comment 28: Commenter 17810 recognizes the EPA’s authority to delegate authority to implement 

section 112 rules and regulations in section 112(l) to states, provided that the state program is “no less 

stringent” than the federal program with respect to quantity of emissions, rule applicability, and level of 

control. Commenter has supported such state programs, including the Colorado Clean Air-Clean Jobs 

Act, and concurs with the EPA that these type of programs will ultimately result in significant emission 

reductions from coal-fired EGUs, as companies implement strategies (e.g., retirement/replacement with 

natural gas or other “cleaner” generation) and/or technologies (e.g., state-of-the-art controls) to meet the 

requirements. Commenter cautions that they expect that the EPA should look very closely at state 

programs or rules that have compliance dates beyond those contained in the federal rule to ensure that 

these programs merit greater reductions in HAP emissions beyond the federal rule to justify the 

extended compliance deadline.

Response to Comment 28: Response to this comment may be found in the preamble to the final rule.
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11. Concerns from non-continental EGU sources.

Comment 29: Commenter 18477 expresses concern that the proposed rule mistakenly assumes that 

switching to natural gas or co-firing with natural gas is a valid and cost-effective compliance option for 

liquid oil-fired units; however, there is no natural gas or liquid natural gas resource in Hawaii. The 

commenter states that as a remote island utility, it does not even have access to the small amount of 

refinery gas available to the refiners addressed by the Boiler MACT.

Commenter 18477 states that all oil-fired EGUs operating in Hawaii, Guam, and Puerto Rico 

exclusively combust residual fuel oil to generate electricity, and all are limited by the crude slates of 

their fuel suppliers. The commenter states that its contracts with on-island refineries contain fuel 

specifications for factors such as sulfur content, pour point, flash point, API gravity and viscosity, which 

the refiners are able to meet primarily by blending and some sulfur removal. However, they do not and 

cannot economically control for metal content. The commenter states that as the agency noted in the 

preamble to the Boiler MACT, the quality of the fuel produced by non-continental refineries is limited 

by the quality of the crude slate used in the refining process (76 FR 15,635).

Commenter 18477 states that it is not feasible for non-continental liquid oil-fired EGUs to comply with 

the proposed numeric emission standards based on their survey of equipment control vendors. The 

commenter states that the vendors surveyed uniformly responded that they cannot guarantee their 

equipment can meet the proposed HAP limits for liquid oil-fired EGUs. The commenter states that the 

ability to achieve HAP control with residual fuel oil applications and ESPs or multi-cyclones in utility

type boilers is currently being researched and is not a commercially demonstrated technology. 

According to the commenter, bag-houses are not a suitable technology for particulate matter control for 

residual fuel oil applications. The commenter states that reputable dry and wet ESP suppliers, such as 

Alstom, Babcock & Wilcox, PECO, Siemens, Southern Environmental Inc., Clyde Bergemann, Hamon 

Research-Cottrell, and Allied Environmental Solutions, Inc. were contacted to determine their current 

position on providing ESP guarantees to meet the proposed emission limits for liquid oil-fired units, and 

the companies that have provided feedback thus far will not guarantee that currently available 

technology can achieve the proposed emissions limits for residual fuel oil applications. Commenter 

included Attachment C as a summary of the vendor responses in the Docket No. The EPA-HQ-OAR2009-0234.

Comment 30: Commenter 18502 states that because they are a non-continental facility, the availability

of alternate fuels is limited. The commenter states that there are no fossil fuel resources on the island 

(Puerto Rico) and that the fuels presently used are delivered by ocean tankers, which is a 

possible source chloride contamination of the fuel as indicated by the erratic HCI measurements made 

during the ICR testing (HCI emissions varied by a factor of 20).

Commenter 18502 states that it has a long term plan for converting their steam generators, CCs, and 

CTs to co-fire natural gas (NG), but the infrastructure needed to deliver natural gas does not currently

exist. The commenter states that the long term plan involves participation in expansion of a local LNG 

facility operated by EcoEiectrica and actively pursuing installation of a NG pipeline. The commenter 

states that engineering evaluations and permitting for the pipeline is underway, but completion has not 

been established yet.

Response to Comments 29 - 30: As noted elsewhere in this document, the EPA is establishing a noncontinental liquid oil-fired subcategory in the final rule.
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5C04 - Compliance: Switching subcategories

Commenters: 17402, 17621, 17638, 17681, 17736, 17754, 17772, 17781, 17790, 17796, 17800, 17868, 

17881, 17902, 18014, 18018, 18444, 18449, 18498, 18502, 19033

1. Performance testing.

Comment 1: Commenter 17402 requests that the EPA allow facilities to set the capacity level at which 

a plant operates during a performance test. The commenter stated the EPA in allowing this will be 

providing another option for compliance, particularly as facilities transition and install new control 

equipment. According to the commenter, this approach will not cause an increase in emissions given 

that the facility would be limited in its ability to exceed the capacity level at which it is operating during 

the test.

Response to Comment 1: Pursuant to section 63.10007(c), performance tests are to be conducted under 

normal operating conditions. Unlike the proposed rule, there is no operating limit established in terms of 

110% of the capacity level used during the most recent performance test. 

Comment 2: Commenter 17754 states that the proposed rule should be revised to clarify that an affected 

source may elect to perform and/or rely on performance testing for the PM surrogate as the basis for 

initial and continuous compliance with total non-Hg HAP metals emission limit.

Commenter 17754 states that the EPA should not require an owner/operator of an affected EGU who 

elects to demonstrate compliance with total non-Hg HAP metals using the PM surrogate to conduct 

performance testing for both PM and total non-Hg HAP simultaneously. According to the commenter, 

the EPA should revise the rule to allow that if an owner/operator elects to comply by using the PM 

surrogate, the owner/operator is not required to conduct performance tests for both PM and total non-Hg 

HAP. The commenter states that the rule should be revised to provide that if a facility elects to conduct 

simultaneous performance testing of the PM surrogate and total non-Hg HAP metals, and as a result 

demonstrates compliance with one of the limits while exceeding the other, the affected EGU shall be 

deemed to be in compliance.

Commenter 17781 states it is inappropriate to require units relying on a surrogate to also conduct 

performance testing for the associated surrogate pollutant(s). According to the commenter, this approach 

is inconsistent with other 40 CFR part 63 standards which allow use of surrogates. The commenter states 

that the EPA has provided no rationale for the collection of this additional data.

Response to Comment 2: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and a surrogate pollutant. Facilities complying with a surrogate standard 

will conduct the performance test for that standard, and not for the corresponding HAP (and vice versa).

Comment 3: Commenter 17796 objects to the initial performance test requirement for all source owners 

and proposes that once the initial performance test is conducted for PM and non-HAP metals, fuel 

sampling will be adequate to demonstrate compliance in lieu of stack testing. According to the 

commenter, stack testing should be no more frequent than every 6 months.

Response to Comment 3: The final rule does not contain the proposed fuel sampling and analysis 

compliance demonstration approaches. See the final preamble and discussion under Comment Code 5A. 

The final rule uses either CEMS, where applicable, quarterly performance testing, reduced testing under 
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the LEE provisions, or annual testing with a PM CPMS for the filterable PM or non-Hg HAP metals 

limits that apply.

Comment 4: Commenter 17881 states this requirement creates confusion in regards to the actual 

compliance mechanism. The commenter asks that if a unit complying with the PM emission limit 

surrogate for non-Hg HAP metals conducts performance testing for both PM and multiple metals, what 

would happen if one or more of the individual metals were above the standard (or, although unlikely, 

total non-Hg metals are shown to be above the standard)?

Response to Comment 4: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and a surrogate pollutant. Facilities complying with a surrogate standard 

will conduct the performance test for that standard, and not for the corresponding HAP (and vice versa).

2. Test methods and methodology.

Comment 5: Commenter 17621 provided discussion of testing methods recommended for ICR data 

collection and compliance with proposed MACT limits.

a. Method 30B: Commenter 17621 states that Method 30B does not specify a MDL or require that one 

be determined. The commenter states that a tester must estimate in advance the minimum sample 

volume that will provide adequate mass of Hg for analysis for the specific source and analytical 

technique. This commenter states it is possible to state a minimum mass of Hg that must be collected on 

a sorbent tube to obtain an accurate measurement by a given analytical method. The commenter states 

that based on EPRI’s reviews of many ICR Part III test reports, almost all samples were analyzed using 

thermal desorption/CVAAS. According to the commenter, this research indicates at least 10 nanograms 

should be collected on the front bed of the sorbent tube to ensure accurate results. According to the 

commenter, there are two reasons for this: 1) to minimize inaccuracy due to instrumental gas flow 

fluctuations that can distort the desorption peak shape, and 2) to raise the sample mass sufficiently above 

the background sorbent mercury level. The commenter states that test runs with loadings below 10 

nanograms generally failed method quality criteria for one or more of the three samples.

Commenter 17621 states that EPRI has classified the adequacy of Method 30B to measure at the 

proposed MACT limit for new coal EGUs as uncertain based on reports from several stack testers that at 

high sample flow rates leakage and equipment failure has occurred.

Commenter 17621 believes it is uncertain whether Method 30B can, for liquid oil-fired EGUs, measure 

Hg accurately at the proposed MACT limit for existing EGUs, and will be unable to measure Hg for 

new units without excessively long (about 30 hours) test runs.

b. Method 5: Commenter 17621 states that it is not certain whether Method 5 sensitivity is adequate to 

support compliance monitoring at the MACT limits for total PM, as that will depend upon the relative 

proportions of filterable PM and condensable PM in the stack gas. According to the commenter, for a 

stack gas where PM emissions are predominantly filterable PM, the above methods will be able to 

measure accurately at the proposed total PM limit (0.03 lb/MMBtu) for existing coal-fired EGUs. The 

commenter states that at the proposed limit for new EGUs (0.05 lb/MWh, approximately 0.005 

lb/MMBtu), Method 5 should still be sufficient to measure accurately by gravimetric analysis and 

whether the overall method accuracy, considering sampling variability, will be adequate at that emission 

rate is unknown. Commenter adds that field studies conducted by EPRI and others have identified 

problems with the accuracy of Method 5 at low emission levels. According to the commenter, results 
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can be biased high or low depending on how the sample is collected. The commenter states that a recent 

study conducted by AEP and EPRI found that the material used for the particulate filter (glass fiber 

versus quartz fiber filter) can produce a significant bias in the results due to acid gas sorption on the 

alkaline material of glass fiber filters (EPRI, 2011). According to the commenter, the temperature of the 

sampling probe and filter also affects the amount of filterable PM collected, with the lower temperature 

collecting more filterable PM. The commenter states that the ICR Part III data include tests conducted at 

two different temperatures (250 °F and 320 °F) and with both types of filters, and that these variables 

introduce additional uncertainty into conclusions drawn from the ICR data, in addition to normal method 

variability.

c. Method 202: Commenter 17621 states that it is not certain whether the Method 202 sensitivity is 

adequate to support compliance monitoring at the proposed MACT limits for total PM, as that will 

depend on the relative proportions of filterable PM and condensable PM in the stack gas. According to 

the commenter, for a stack gas where the PM emissions are predominantly condensable PM, the mass 

collected in a 4-hour test will be sufficient for an accurate gravimetric measurement at the proposed total 

PM limit (0.03 lb/MMBtu) for existing coal units. The commenter states that at the proposed limit for 

new EGUs, approximately 0.005 lb/MMBtu, the collected PM residue is also sufficient to measure 

accurately by gravimetric analysis, but limited results of field testing indicate that the overall method 

accuracy may not be adequate at that emission rate. Commenter adds that a field study conducted by 

AEP at several coal-fired power plants found that revised Method 202 has high between-run variability

(EPRI, 2011). The commenter states that in four replicate tests conducted with the same sampling 

conditions (probe temperature, PM filter type, and sampling duration), the relative percent difference 

(RPD) of the CPM measurements ranged from 25–78 percent. The commenter states that these were 

samples taken at different times and were not parallel train samples; however, process monitoring 

indicated that there were no upsets during the sampling periods. The commenter states that filterable PM 

samples taken from the same sampling trains had lower (6–27 percent) variability. Condensable 

PM emissions in the samples ranged from 0.0032 lb/MMBtu to 0.013 lb/MMBtu. The RPD of the 

replicates at the lowest emission rate, about twice the proposed MACT total PM limit for new plants, 

was 78 percent. According to the commenter, these findings indicate that the method does not provide 

sufficient precision to support compliance monitoring at the proposed limit for new coal-fired EGUs and 

may not provide sufficient precision at the proposed limit for existing coal-fired EGUs. Commenter also 

adds that an EPRI laboratory study of OTM-28 determined that modifications from the original Method 

202 had reduced the positive bias due to aqueous-phase conversion of gaseous SO2 to sulfuric acid 

(a condensable PM species) compared to original Method 202 (EPRI, 2009). The commenter states that 

the study also found that OTM-28 did not appear to capture sulfuric acid aerosol effectively. According 

to the commenter, as sulfuric acid is the predominant condensable PM species in coal-fired power 

plants, this finding may indicate that the revised Method 202 has a negative bias.

d. Methods 5 and 202: Commenter 17621 states that the combination of Methods 5 and 202 is sensitive 

enough to provide accurate gravimetric measurement at the proposed MACT limits for both existing and 

new coal-fired EGUs. According to the commenter, the precision of Method 202 may not be sufficient at 

the new EGU limit to support that determination.

Response to Comment 5: The EPA does not agree that all components of a test method composed of 

composite analyses need to be above the minimum detection limit to provide reliably accurate 

quantification of the total emissions. While the commenter focuses on the four components used to 

quantify total particulate matter, other test methods and pollutants would present similar influences. 

While it is common to collect less than a measureable mass in the nozzle and probe portion of 

particulate sampling trains, this has an insignificant impact on the filterable or the total particulate matter 
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measurements when the quantity of material collected on the other components are above the levels 

which minimize measurement precision. In the test data from the mix of PM tests performed under the 

Part III ICR, there were few individual runs where the mass of particulate was below the mass that has 

routinely been determined to be the minimum detectable mass for the different components. For 

filterable particulate, only 51 test runs out of 1252 had less than 1.3 mg of particulate on the filter and 

probe wash. For inorganic condensable particulate, only 19 of the 772 runs reported a mass of less than 

1.5 mg. Last, for organic condensable particulate, 30 test runs out of the 772 runs reported a mass of less 

than 0.5 mg. These weights are the approximate detection levels for these components of total 

particulate. There were no sources where the mass for all components were less than these levels. 

Therefore we would not expect that any source would be challenged to demonstrate that their emissions 

were less than the proposed total particulate level we proposed. Since we have selected filterable 

particulate as the alternate equivalent standard for non-Hg metals, there are only two measured 

components and the filter component is expected to have the majority of the PM. In reviewing the 

filterable PM data, a 4-hour source test with 5 mg particulate on the filter (the approximate mass above 

which Method 5 has a consistent precision) would have emissions of approximately 0.0014 lb/MMBtu. 

This emissions level is much lower than the filterable PM emissions limit we have established in this 

rule. As a result, we do not expect any sources to have problems in accurately quantifying their 

emissions either when they are near the emissions limit or near the LEE emissions level. We agree with 

the commenter concerning the influences on filter selection and filtration temperature on the 

determination of mass on the filter. Sources and source test contractors will be advised to insure that the 

filter media they use meets the requirements of Method 5 with respect to the reactivity to acid gases to 

insure that their measurements are not biased. A similar bias may arise as a result of maintaining the 

wrong filter temperature.

Comment 6: Commenter 17881 states the use of PM filterable will simplify the associated testing 

requirements in that a single Method 5/Method 29 sampling train could be used to simultaneously test 

for both the PM surrogate and multiple metals. According to the commenter, use of a PM filterable 

surrogate would also allow a direct compliance determination via the use of PM CEMS (which are only

capable of measuring PM filterable emissions).

Response to Comment 6: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and its surrogate. Facilities complying with a surrogate limit do not have to 

perform periodic testing for the corresponding HAP. We agree with the commenter in that Method 29 

provides the ability to concurrently quantify filterable PM and the non-Hg metals which we are 

regulating. The final rule uses a PM CPMS approach. See the final preamble and Comment Code 5A07a 

for further discussion.

Comment 7: Commenter 18444 states that the particulate filterable temperature is defined as 320 °F ± 

25 °F, which is the temperature currently used for non-sulfate filterable PM testing, and this appears to 

be because the sulfate is to be counted with the condensables. According to the commenter, this is 

different than most of the EPA testing (248 °F ± 25 °F), so the filterable particulate results measured 

under these new requirements would likely be lower than what would be currently measured. The 

commenter states that since the limits are for the total PM (filterable and condensable) the total catch 

should in theory be the same regardless, but this would impact the PM CEMS (if used) since they will be 

measured on the filterable only. The commenter states that companies would have to test separately for 

compliance with different federal particulate limits based on these temperature differences, adding to the 

testing workload.
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Commenter 18444 states the filter temperature for metals testing is defined the same as for particulates 

(320 °F+ 25 °F) instead of the current practice (248 °F + 25 °F). The commenter states that the proposed 

rules mention determining filterable metals separately from total metals, and as with PM, this impacts 

limits set for Hg CEMS or sorbent monitoring (if used) since particulate Hg is not measured by these 

methods. According to the commenter, in this case, there will be higher mercury results on the 

CEMS or sorbent monitoring since the higher filter temperature would allow more Hg to pass through 

the filter. The commenter states that as long as the EPA adopts stringent PM limits, that particulate Hg 

emissions will not be significant; monitoring gaseous Hg should be sufficient and the filter temperature 

should not change the gaseous Hg results significantly.

Response to Comment 7: While we deliberated what filter temperature should be used in the collection 

of test data with Method 5, Method 29, and Method 26A, we selected 320 oF for multiple reasons. First, 

it is consistent with the temperature used for compliance with existing rules. As a result this allowed a 

mare direct comparison with that data and provided us with an understanding of the within source 

variability of emissions. It also provided a more direct ability to establish a particulate level for 

correlation or alternative applications of PM CEMS. The absence of SO3 on the filter and the collection 

in the impinger provides for more consistency in obtaining constant weights. Since little or no SO3 is 

retained on the filter, the highly hydroscopic SO3 does not cause weighing difficulties by absorbing 

water from the air. Also, by moving the SO3 to the impinger, the SO3 can be neutralized and thereby 

making it easier to achieve constant weight. Lastly, it provided a partitioning of the components of 

particulate similar to the majority of the existing emissions controls.

Comment 8: Commenter 19033 states that the proposed regulation section 63.10005(b) specifies that 

performance tests are to be conducted; as specified in Table 5. With respect to the proposed PM 

limit, the commenter notes that the testing requirements are Method 5 and 202, with the specific 

provision that tests using Method 5 must be performed at a filter temperature of 320° F. However, some 

state permit conditions require that filterable PM, as measured by Method 5, be conducted at a filter 

temperature of 250 °F. Commenter adds that filterable PM measured by Method 5 at 250 °F is expected 

to provide different (and higher) results than filterable PM measured by Method 5 at 320 °F, because of 

the condensation of sulfuric acid at 250 °F. According to the commenter, consequently, a mechanism is 

needed to allow EGUs required to perform Method 5 tests at 250 °F to concurrently demonstrate 

compliance with the proposed PM limit based on a Method 5 filter temperature of 320 °F. Commenter 

19033 suggests the following mechanism to accomplish the concurrent compliance demonstration:

1. Perform all required PS-11 PM CEMS correlation curve testing using EPA Method 5 at a filter 

temperature of 250 °F, if the state agency so directs.

2. Perform PM compliance tests with respect to the proposed limit at a filter temperature of 320 °F. 

According to the commenter, if compliance is demonstrated, the concurrent PM CEMS output 

(which will be biased high, because it will correlate to 250 oF) will become the filterable 

concentration limits, rather than the three-run filterable PM concentration limit measured at 320 °F.

Commenter 19033 recommends revisions in Tables 4 and 7, in order to implement the above described 

mechanism. In conjunction with the changes recommended for Tables 4 and 7, Commenter 19033 

also recommends that proposed regulation 63.10011 (d) be amended as follows:

... You must determine an operating-limit (PM concentration in mg/dscm) during 

performance testing for initial PM compliance. The operating limit will be the average of 

the PM filterable results of the three Method 5 performance test results, unless the state 

agency requires the Method 5 tests to be performed at a filter temperature of 250°F. If 
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the Method 5 tests are required to be conducted at 250°F, the operating limit will be the 

average of the PM filterable results reported by the PM-CEMS rather than the PM 

filterable results of the three Method 5 tests performed at 320°F, provided compliance 

is demonstrated by the Method 5 tests conducted at 320°F.

Comment 9: Two commenters (18444, 19033) express concern over the EPA requirement that the stack 

test filter temperature is set at 320 °F when other regulatory authorities and/or State agencies may

require a different lower temperature of 250 °F.

Response to Comments 8 - 9: The final rule has been revised to remove the requirements for Method 

202 and PS-11, so those comments are moot. The 320°F filtration temperature was chosen for the 

determination of compliance with the standard due to match the data collection temperature. If sources 

would like to harmonize their testing requirements with other limits at lower filtration temperatures, they

may request to do so per 63.7. The EPA agrees that there are biases associated with improper selection 

of filter material. Method 5 states that sources with SO2 or SO3 should select an unreactive filter to 

handle such issues. The EPA disagrees that Method 30B cannot measure the levels specified in the 

emission standards. The data used for the new source MACT limit were based on Method 30B 4 hour 

test runs that met all QA criteria with a catch under 10 nanograms. The EPA disagrees that we should set 

a specific ng catch for the method, but welcomes sources to devise test plans with those DQOs.

3. Test methods unreliable or inadequate.

Comment 10: Commenter 17736 states that including condensable PM raises concerns about the 

efficacy of monitoring technologies used to determine compliance. According to the commenter, 

measuring condensables separate from filterable PM is new and is not widely accepted by the industry

due to a lack of data supporting the method’s accuracy.

Response to Comment 10: As we state elsewhere, we evaluated the ability of all particulate 

components to be a surrogate indicator of non-Hg metals emissions. As a result of that evaluation, we 

have selected filterable particulate since it offers several advantages with respect to continuous 

monitoring and ease of demonstrating compliance. The comments regarding a supposed lack of 

condensable PM data and potentially inaccurate condensable PM test method are moot, not because we 

agree with either supposition but because the rule no longer contains a total PM emissions limit.With 

respect to accuracy, particulate matter is a pollutant that is sensitive to the method which it is collected. 

This includes not only how much material is in solid or liquid form but also the size distribution of the 

particulate matter. By establishing a truly standard collection hardware, conditions for the separation of 

the water and sample gas, temperature for collection and analytical finish we have also established the 

material which is retained and measured as PM.

Comment 11: Commenter 17881 states as currently written, section 63.10006(e) requires that the fuel 

factor methodology and equations in sections 12.2 and 12.3 of Reference Method 19 (40 CFR 60, 

Appendix A-7) be used to convert the results of the performance tests into units of lb/MMBtu of 

lb/TBtu, as applicable. This section should recognize that such calculations need not be conducted if 

an EGU has chosen to demonstrate compliance with the mass per unit of electrical output emission 

limits. The EPA should also allow the use of fuel factors determined in accordance with sections 3.3.5 

and 3.3.6 of 40 CFR Part 75, Appendix F. Of particular concern is the fact that Reference Method 19 

does not contain fuel factors for subbituminous coals, solid oil (i.e., petroleum coke) or tire-derived-fuel, 

any of which could be fired in solid fuel-fired boilers subject to the proposed rule.
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Response to Comment 11: The EPA agrees, and has made corresponding changes to section 

63.10007(c) in the final rule.

Comment 12: Commenter 18449 expressed the concern that, if the +1 μg/m3 alternate specification is 

tightened, an increased frequency of testing errors will cause even CEMS that are operating properly to 

fail. According to the commenter, the EPA should consider a mandatory periodic QA/QC program 

where it or another impartial agency loads sorbent traps supplied by the test group with the output from 

a NIST traceable elemental calibrator. The commenter states that this approach should be applied to both 

RATA testers and to suppliers of continuous sorbent testing services.

Response to Comments 12: The comment is moot because the final rule did not tighten the alternative 

specification.

4. Surrogates.

Comment 13: Commenter 17736 states that the EPA’s proposed rule creates a double standard, 

facilitating potentially inconsistent enforcement practices. The commenter states that non-Hg HAP 

metals compliance provisions should be written to provide a unit electing to comply with a surrogate 

with continuing compliance demonstrated not to be deemed in non-compliance for exceeding an 

emission limit during a stack test.

Response to Comment 13: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and its surrogate. Facilities complying with a surrogate limit do not have to 

perform periodic testing for the corresponding HAP, and vice versa.

Comment 14: Commenter 17881 states Table 4 of the proposed rule, as well as section 63.10005(d)(4), 

indicate use of the SO2 surrogate is predicated on the EGU both being equipped with wet or dry FGD 

and using an SO2 CEMS for the compliance determination but that section 63.10006(h) applies to those 

solid oil-fired and coal-fired EGUs without SO2 CEMS but with wet or dry FGD controls. The 

commenter states that such EGUs are required to conduct SO2 and HCl testing during the same 

compliance test period and under the same process (i.e., fuel) and control device operating conditions at 

least every year, as well as conduct SO2 testing at least every other month. The commenter states that 

this paragraph is confusing, as SO2 is being treated as a regulated pollutant even though its use as a 

surrogate would appear to be barred in the absence of an SO2 CEMS. According to the commenter, it is 

very unlikely that there are any solid oil-fired or coal-fired EGUs of sufficient size to be regulated under 

the proposed EGU MACT but not be equipped with SO2 CEMS, as such CEMS are generally required 

by one or more of the following: 40 CFR Part 60, 40 CFR Part 75, and State Implementation Plans.

Response to Comment 14: In response to comments, the final rule has removed all requirements for 

duplicative testing of a HAP and its surrogate. Facilities complying with a surrogate standard will 

conduct the performance test for that standard, and not for the corresponding HAP (and vice versa). The 

specific provisions cited in this comment have been clarified in the final rule such that only the HCl 

testing would be required under such circumstances.

5. Test requirements.

Comment 15: Commenter 17772 submits that the testing requirements are excessive and unnecessarily

redundant. According to the commenter, for units that do not use a PM CEMS, the proposed rule would 
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require testing every other month, which is unjustified and costly. This commenter also states it is 

unclear how compliance is determined under the multiple testing scenario.

Comment 16: Commenter 17796 supports testing for filterable particulates as well as condensable PM.

Comment 17: Commenters 17638 and 17681 state that the EPA should not require HAP stack testing 

for EGUs using a surrogate, and should remove the requirement that EGUs using PM as a surrogate for 

non-Hg HAP metals conduct a stack test for non-Hg HAP metals. EGUs using SO2 as a surrogate for 

HCl should not be required to stack test for HCl. Commenters also state that the EPA should not require 

stack testing of surrogates when a source chooses to comply with the HAP limit.

Commenter 17790 submits there is no justification for testing for the HCl surrogate (Method 502) if a 

company is complying with the HCl standard.

Commenter 17868 states that the EPA has no basis to require HAP stack testing for EGUs using 

surrogates or to require surrogate testing for EGUs not relying on surrogates. The commenter states that 

the requirements are duplicative and should be removed.

Commenter 17881 states it is inappropriate to require units relying on a surrogate to also conduct time 

consuming and costly performance testing for the associated surrogate pollutant(s). According to the 

commenter, this approach is wholly inconsistent with other 40 CFR Part 63 standards which allow the 

use of surrogates, and the EPA has provided no rationale for the need to collect this additional data. The 

commenter states that if the EPA is concerned about the relationship between the chosen surrogates and 

their associated HAP(s), then the EPA should initiate an additional ICR effort which will allow them to 

further study the relationships between HAP(s) and their potential surrogates.

Commenter 17881 states that the provisions of section 63.10006(i) are very similar to those in section 

63.10006(d) in that they require testing of both the surrogate (i.e., SO2) and the associated HAP 

(i.e., HCl) even though the surrogate cannot be relied upon for compliance for solid oil-fired and coalfired EGUs without a SO2 CEMS and without wet or dry FGD controls.

Commenter 18498 states that the requirement to stack test for both the pollutant and surrogate is 

redundant, and requests the EPA to remove the requirement that both the pollutant and surrogate be 

stack tested. According to the commenter, a performance test should only be required for the pollutants 

and surrogates with which a source is choosing to show compliance.

Multiple commenters (17638, 17681, 17754, 17772, 17781, 17790, 17800, 17881) express the concern 

that requiring testing for both a pollutant and its surrogate is unnecessary when only one should be 

adequate for demonstrating compliance.

Commenter 17800 states that requiring sources to test either for the actual HAP in cases where 

surrogates are being used for compliance is duplicative, has no rational to be required, and will increase 

the cost of compliance.

Commenter 17881 states that the provisions of section 63.10006(d) require that petroleum coke and 

coal-fired EGUs without PM CEMS (but with PM control devices) conduct all applicable tests for PM 

and non-Hg HAP metals testing during the same compliance test period and under the same process 

(i.e., fuel) and control device operating conditions at least every year, as well as conduct non-Hg HAP 

metals testing at least every other month. The commenter states that the PM surrogate only applies to 
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those units equipped with a PM CEMS, so it makes no sense that such units are required to conduct 

concurrent PM and non-Hg HAP metals testing, as PM is not a regulated pollutant for such units. The 

commenter states that as discussed in relation to 63.10005(a), the EPA should conduct an 

additional ICR if they feel it is necessary to collect additional data on the relationship between PM and 

non-Hg HAP metals emissions.

Response to Comment 15 - 17: We agree that a reduction in the frequency and types of measurements 

and monitoring that we proposed is appropriate and will still provide an assurance that sources are 

maintaining reasonable emissions control of HAP metals and acid gases. First, in response to comments, 

the final rule has removed all requirements for duplicative testing of a HAP and its surrogate. Facilities 

complying with a surrogate limit do not have to perform periodic testing for the corresponding HAP, 

and vice versa. Second, we have changed all requirements for periodic monthly or every other month 

performance testing to quarterly, with an exception for quarters with very low operating hours. We have 

clarified that no performance stack testing is required where a CEMS is used for direct compliance, and 

we have also established an annual performance test requirement for sources that elect to use a PM 

CPMS as part of the continuous monitoring approach for ensuring compliance with a filterable PM or 

HAP metals emission limit.

Comment 18: Commenters 18014 and 18498 state that the minimum sampling time of four hours 

required by section 63.7520(d) for compliance tests is excessive. According to the commenters, the EPA 

should re-evaluate the required sampling times for each method and/or provide alternative minimum 

volumes for each method.

Response to Comment 18: We have selected the appropriate test duration that we believe is required to 

achieve the necessary measurement precision needed to determine compliance. Source testing 

companies are encouraged to perform an assessment of the ability of an alternative sampling duration, 

sampling rate and analytical finish which provides for comparable reliable, precise and accurate 

measurements and that is representative of the sources operation.

Comment 19: Commenter 18018 states that the EPA’s proposed compliance requirements are overly 

burdensome and should be modified due to certain compliance requirements for the proposed air toxic 

rule that may result in periods of noncompliance by some EGUs that may be capable of complying with 

the emission limits under normal operations. According to the commenters, the following change would 

facilitate compliance with the proposed rule: PM compliance testing should involve only filterable 

particulates. Including soluble particulates will complicate compliance testing without providing 

significant additional compliance assurance.

Response to Comment 19: The final rule uses filterable PM as the surrogate for non-Hg HAP metals. 

See further discussion of this issue in the preamble and elsewhere in this document.

5. Other.

Comment 20: Commenter 17902 states the proposed rule definition for a unit designed to burn solid-oil 

derived fuel and its application is unclear for units that co-fire pet-coke and coal together. The 

commenter states that the application of Table 1 and Table 2 emission limits needs to be clarified 

including how emission limits will apply for units that move from one subcategory to another. 

According to the commenter, the relevant MACT emission limits should be applied based on the 

majority of fuel actually combusted annually on a heat input basis.
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Response to Comment 20: According to the definitions of coal-fired electric utility steam generating 

unit and oil-fired electric utility steam generating unit in §63.10042, should an EGU that co-fires pet 

coke and coal such that more than 10 percent of the annual heat input for 3 years or 15 percent of the 

annual heat input for one year is from coal, the EGU is a coal-fired electric utility and would be subject 

to the coal-fired emissions limits.

Comment 21: Commenter 18502 expressed concern that natural sources of atmospheric chlorine in 

coastal areas that a facility cannot control can cause wide variations in emission rates. The commenter 

states that these include chloromethane formed by action of sunlight on marine biomass and chlorine 

from sea foam, possibly influenced by wind direction.

Response to Comment 21: The rule has been revised to address this concern for liquid oil-fired EGUs, 

such that an owner or operator need not conduct HCl or HF emissions measurement if the owner or 

operator conducts fuel moisture analysis or provides certification from a fuel supplier and that analysis 

or certification shows fuel moisture content does not exceed 1 percent.
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5C05 - Compliance: Treatment of Common Stacks

Commenters: 15678, 17733, 17739, 17775, 17781, 17796

1. Unit-by-unit control.

Comment 1: Commenter 15678 supports the EPA’s application of emission standards to each operating 

EGU instead of to the overall site consisting of several EGUs. This commenter stated that this approach 

is especially important for areas with large amounts of impervious land cover where increased 

stormwater runoff will contribute more land deposited Hg to the food chain via bioaccumulation in 

seafood. The commenter strongly supports applying the MACT standard to all EGUs.

Response to Comment 1: We have responded to comments relating to emissions averaging across 

EGUs at a common site in a given subcategory elsewhere in this document.

Comment 2: Commenter 17733 states that in order for the EPA to meet its responsibilities under the 

Trust Responsibility and the Environmental Justice Doctrine, the EPA should apply the most stringent 

applicable standard under the EGU MACT Rule to all IB units in a contiguous area and under common 

control. The commenter states that this approach is necessary to be consistent with the rule’s description 

of a source and helps insure the rule can take advantage of economies of scale by having all IB units at a 

source apply the same level of control technology. According to the commenter, this approach prevents 

IB unit owners from avoiding stringent EGU MACT rule requirements by dismantling shared pollution 

control device exhaust stacks. The commenter states that the EPA should require all IB units as a source 

to meet the most stringent EGU MACT standard applicable to any EGU at a source.

Response to Comment 2: To the extent commenter is referring to industrial boilers, those comments 

are outside the scope of this rulemaking and are not addressed. To the extent commenter is referring to 

EGUs, we have addressed comments related to emissions averaging across EGUs at a common site in a 

given subcategory and to common stacks elsewhere in this document.

2. Use of combined stack data.

Comment 3: Commenter 17739 states that the EPA’s use of combined stack data is inconsistent with its 

treatment of data below the MDL. The commenter states that in the Boiler MACT, the EPA concluded it 

was inappropriate to use values below the MDL for the simple and correct reason that “such values have 

not been demonstrated to have been met” (76 FR 15624) and that the same is true with respect to data 

from combined stacks; no unit actually “met” the reported value, let alone two. According to the 

commenter, the data point of the combined emissions is a fiction that represents the combined 

performance of the suite of control trains and boilers, and there is no basis to know whether one unit 

would measure higher and the other lower if tested separately, rather than assuming they would both 

measure exactly the same. The commenter states that in fact, the one result of which we can be 

absolutely sure is that both units would not produce identical emissions. The commenter states that the 

EPA’s creation of multiple data points from a single combined stack data point are simply a fiction that 

is not permissible under the MACT standard setting criteria.

Comment 4: Several commenters (12991, 17739, 18023) disagree with the EPA’s use of data from 

multiple units exhausting through a common stack. Commenter 17739 states that the EPA makes two 

errors: 1) EPA unreasonably treats data from multiple units exhausting through a single stack as multiple 

data points, and 2) EPA applies this incorrect approach inconsistently. While it may be acceptable for 
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the EPA to surmise that the combined performance of multiple boilers and pollution control devices 

represents an emissions control strategy that could be a best performer, thereby entitling the agency to 

use the data at all, the fact is there is only one performer not two. Apart from being inconsistent with 

applicable MACT case law, commenters assert that counting combined stack emissions as two or more 

data points is unreasonable because it dampens variability and over represents the emissions data by 

creating multiple “performers” or sources when there is in fact only one. In the Boiler MACT, the EPA 

argues its approach of creating two data points from a single combined stack data point is reasonable 

because it cannot separate the commingled fraction of the emissions from the different emission points. 

Commenters state that is irrelevant and there is no basis to separate these emissions because the MACT

floor is based on best performing sources and there is only a single source. Indeed, the opposite is true. 

Commenters state that the EPA cannot determine what amount of the overall performance of a 

combined stack data point is the specific result of the combination. The EPA also argues that applying 

the emissions equally to multiple units exhausting through a single stack “accurately represents the 

emissions of those units on average. Commenters assert that is simply not correct and there is no 

plausible factual basis for that statement. There is no unit that “achieved” those emissions. Rather, the 

data represent the combined weighted average of two units, without knowing how either unit actually

performed.

Commenter states that in the Boiler MACT, the EPA asserts that adding multiple data points for 

common stack units provided additional data where the EPA’s databases are sparsely populated. 

Commenter states that counting a single stack unit twice to have more data is not necessary in the utility

MACT, which is not lacking for data. Commenter also states that counting as two a single stack may 

dampen variability unlike the EPA’s claim in the Boiler MACT. Commenter states that the practice of 

treating plants that have multiple boilers exhausting through a single stack as if they were separate 

sources is fairly systemic and results in a widespread population of the database with fictional values.

Commenter 12991 disagrees with the use by the EPA of duplicate records for determining the Hg 

MACT floor. The commenter states that in several instances when a facility operated tandem or multiple 

units but only submitted a single stack measurement, the EPA used the single stack measurement to 

represent Hg emissions from the facility’s other stacks. According to the commenter these duplicate 

records should not have been used because the agency did not systematically select the units; that is, the 

selection of units was not entirely random nor was it purposefully intended to identify the bestperforming units within the total population of units. According to the commenter, the EPA did 

randomly select some units while intentionally selecting some of the best performing units resulting in a 

biased selection represented by a greater percentage of baghouse-controlled units than exists in the 

population of coal-fired utility sources. The commenter states that the duplicate records are redundant 

and should not be included because they cannot be considered to represent the best performing sources 

or to be an unbiased or random sample.

Commenter 18023 states that the EPA’s MACT floor database lists the four units at Georgia Power 

Company’s Plant Hammond as four separate sources. These units, however, share a common FGD and a 

common stack. It would be impossible to differentiate the emissions resulting from each unit. This error 

is not limited to Georgia Power Company’s Plant Hammond. This error occurs in 19 of the 130 lowest 

emitting units for Hg, 25 of the lowest emitting units for PM, and 19 of the lowest emitting units for 

HCl. The EPA should treat the emission value from units with a common stack as a single source in the 

MACT floor calculation. Furthermore, the EPA must be consistent in how it treats units with a common 

stack. Contrary to the manner in which the EPA analyzed Plant Hammond, the EPA has considered at 

least five multiple-unit, single-stack plants as being a single source (Elmer Smith 1 & 2, Grant Town 1 
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& 2, Morgantown Energy Facility 1 & 2, Scrubgrass 1 & 2, and Seward 1 & 2). At a minimum, the EPA 

must be consistent on this point in order to avoid additional methodological error.

Response to Comments 3 - 4: The EPA disagrees with commenters. As in the Industrial Boiler 

NESHAP, the EPA continues to believe that the emissions from the common stack represent the average 

emissions of the EGUs exhausting to the common stack and are representative of both EGUs. 

Commenters have provided no data to support the contention that this assumption is false. In addition, 

commenters contention that distinct EGUs (i.e., boilers) are one source if they emit out of a common 

stack is not consistent with the CAA section 112(a)(8) definition, which clearly applies to the individual 

boiler units with a capacity of more than 25 MW. It would not be reasonable in light of that definition to 

consider the emissions from two boilers to a common stack as the emissions of one EGU. The EPA used 

data from combined stacks only where both EGUs were operating or where the owner/operator certified 

that no air in-leakage could occur. . The EPA expects that companies will comply with the final rule by

conducting testing at the common stack as that is usually where the sampling locations are (rather than 

in the intermediate ductwork) and will report the results as being for each EGU.

The EPA has reviewed the data based on comments received and does not believe that there are any 

inconsistencies in the data set used for the final rule. In the MACT floor analysis, the EPA used data 

only from stacks that were tested or for which test data were provided. These stack measurements were 

not used to represent emissions from other, non-tested, stacks in the MACT analysis. 

The ICR required owners or operators to provide the agency with information from individual EGUs, 

and those owners or operators certified the results submitted to the agency as being true, accurate, and 

complete. The agency has no ability to and needs not change such submitted data, for if after 

submission, an owner or operator believed his/her EGU data from a combined stack were inaccurate, he 

or she could have and should have conducted additional testing to isolate emissions. The agency

maintains its use of submitted data for rulemaking purposes remains valid.

3. Common stack provisions.

Comment 5: Several commenters (15678, 17733, 17796) support the approach of applying the most 

stringent standard to each EGU when they share the same stack and/or controls. Commenters (17733, 

17796) add that this should apply when there are similarly fueled units. Commenter 17796 states this 

would eliminate any possible confusion about the applicable regulatory requirements for both regulators 

and source owner.

Response to Comment 5: We agree with the commenters and have included such requirements in the 

final rule.

Comment 6: Commenter 17775 states that the EPA’s proposed common stack provisions fail to provide 

sufficient flexibility for EGUs with different control technologies that vent to a common stack. The 

commenter states that under proposed section 63.10009(h)(i), two or more units that vent through “a 

common control system” to a common stack may be treated as a single unit, and some units with one 

common control (e.g., an FGD) may not share other controls (e.g., SCR). The commenter asserts that 

although such units may be able to meet the proposed emission limit at the common stack during normal 

operation, any significant outage at one unit could make compliance on a 30-day rolling average basis 

impossible. The commenter states that the EPA addressed the issue of outages for single stack units 

participating in averaging plans under section 63.10009(b) by providing a 12-month rolling average 

compliance period and should provide the same for common stack units that use averaging to comply.
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Response to Comment 6: We have addressed common stack issues elsewhere in this document. We 

continue to believe that the emissions of the common stack represent those of all of the EGUs ducting 

through that common stack. Should this present problems for the owner/operator, they are free to 

conduct their compliance or CEMS testing in the ductwork prior to the common stack so as to measure 

emissions from the individual EGUs.

Comment 7: Commenter 17781 states as currently written, paragraphs (h), (i) and (j) do not seem to 

address the likely situation where each of the EGUs associated with a common stack are affected units 

within the same category, but they do not utilize common control devices (i.e., each EGU is equipped 

with its own control device(s)). The commenter states that if the EPA is concerned about a possible 

conflict in testing frequency in cases where different control technologies are employed 

by EGUs sharing the common stack, the EPA could stipulate that the testing frequency for the common 

exhaust stack is based upon the most frequent testing schedule for any of the individual units sharing the 

common stack based upon the individual EGU control technologies and common stack compliance 

method.

Response to Comment 7: The final rule includes simplified testing frequency requirements and there 

may be fewer situations of multiple and different testing frequencies applying to units sharing a common 

stack. We agree with the commenter that in any case the more frequent testing requirement must apply

to testing for that common stack.
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5C06 - Compliance: Startup, Shutdown, and Malfunction

Commenters: 15678, 16849, 17174, 17197, 17283, 17316, 17383, 17386, 17402, 17622, 17623, 17627, 

17637, 17638, 17648, 17675, 17677, 17689, 17691, 17702, 17704, 17705, 17712, 17714, 17715, 17716, 

17720, 17722, 17724, 17725, 17728, 17729, 17730, 17732, 17736, 17737, 17740, 17752, 17755, 17756, 

17757, 17758, 17761, 17767, 17772, 17774, 17775, 17776, 17795, 17796, 17801, 17807, 17808, 17813, 

17815, 17816, 17820, 17821, 17851, 17856, 17868, 17870, 17876, 17877, 17878, 17880, 17881, 17885, 

17886, 17902, 17904, 17909, 17912, 17923, 17925, 17928, 17930, 17975, 18014, 18018, 18021, 18025, 

18034, 18037, 18428, 18429, 18447, 18449, 18450, 18498, 18500, 18539, 19032, 19040, 19114, 19120, 

19121, 19122, 19536, 19537, 19538, 18023

1. Emission standard applicability during SSM.

a. Support or oppose SSM approach.

Comment 1: Commenters (15678, 17880) support the EPA’s approach that emissions standards apply at 

all times. Commenter 17648 states that the EPA proposed reasonable and appropriate emission 

limitations applicable to SSM periods, and cites the Sierra Club decision. Commenter 

19536/19537/19538 states that sources must comply with emission standards at all times, including 

startup, shutdown and malfunctions. Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008). Commenter 

18450 supports that emission limits include startup and shutdown, since these emissions are readily 

quantifiable.

Comment 2: Commenter 17851 states that the EPA’s requirement to meet steady-state standards during 

SSM events is not logical and is not lawful. Commenter 17851 states that from a physical and legal 

standpoint, it makes no sense to group SSM and normal operation events under the same set of 

standards. Commenters (17740, 17772, 17821, 17868) state that including SSM in the standard is 

unreasonable.

Commenter 17772 states that the CAA unambiguously requires that the EPA look to the actual 

performance of actual units including performance during periods of start-up, shut-downs, malfunctions. 

Instead, the EPA started with very limited data from EGUs operating under ideal conditions- generally

three hours of operation at full load. As a result, the data were skewed towards a performance level that 

none of the EGU’s from which data were collected can “achieve in practice.” Each of those EGU’s, and 

every other EGU in the country, has start-ups, shut-downs and malfunctions where emissions will be 

substantially higher than the performance that can be achieved under full load and ideal operating 

conditions.

Commenter 17868 states that the test operations and statistical treatment of the test data do not represent 

periods of startup, shutdown, or malfunction. Therefore those periods of operation should not be subject 

to the standards. A work practice approach, similar to that promulgated for industrial boiler HAPs, 

would be appropriate for these abnormal operating periods. Second, the continuous compliance 

assurance requirements – which include enforceable limits on various fuel and hardware variables like 

the pressure drop across a control device – are effectively more stringent than the emission standards 

that they support, and therefore were not “achieved in practice” by the best controlled units.

Comment 3: Multiple commenters cite concerns about how the rule addresses SSM emissions and made 

statements such as the following regarding SSM:
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 MACT standards are too stringent (17383, 17623, 17689, 17712, 17740, 17761, 17772, 17774, 

17813, 17816, 17877, 17885,)

 Emission limits are too low for coal- and lignite-fired units to meet and still remain economically

operational (17930)

 SSM makes the standard more stringent (17730, 17868, 17902)

 SSM is a significant burden (17774, 18447)

 Concerned that the emission limits apply at all times, including SSM periods (17197, 17675, 

17725, 17728, 17729, 17732, 17736, 17737, 17756, 17758, 17761, 17774, 17775, 17808, 17815, 

17870, 17886, 17904, 17912, 17928, 17930, 17975, 18037, 0234-19536/19537/19538, 0234-

18023)

 State limits should not apply during SSM periods (17383, 17704, 17712, 17724, 17720, 17725, 

17730, 17736, 17752, 17774, 17813, 17820, 17868, 17876, 17885, 17904, 17909, 17925, 18014, 

18429, 18498, 19032, 19120)

 SSM data should not be included in the 30-day average (16849, 17627, 17767, 17772, 17774, 

17904, 18428, 19120)

 Including SSM could result in exceedances of the 30-day standard or noncompliance (17730, 

17868, 17930)

 Requests an exemption during SSM periods (17637, 17820, 18498).

Comment 4: Commenter 17930 states that the EPA has a long history of exempting SSM periods from 

NSPS and NESHAP, and this should continue. Commenter 19121 states that startup and shutdown 

emissions have historically been exempt. Commenter 17851 states that before the Sierra Club v. EPA

decision, the D.C. Circuit consistently held that technology-based standards must contain exemption or 

less stringent standards during SSM than would apply during steady state periods, and cites several court 

cases regarding the EPA’s previous treatment of SSM events, including, Portland Cement Ass’n v. 

Ruckelshaus (1973), Essex Chem. Corp. v. Ruckelshaus (1973), NRDC v. EPA (1988), Marathon Oil v. 

EPA (1977), and National Lime Ass’n v. EPA (1980). Commenter 17851 states that now that the court 

decided that MACT standards must apply during SSM, the EPA must develop standards that are 

“achievable” during those events.

Comment 5: Commenter 17856 sees many compliance and enforcement issues arising from the startup 

and shutdown provisions. Commenter suggests the EPA adopt reasonable startup and shutdown 

provisions.

Comment 6: Commenter 17868 provides an example calculation and a graph showing the hours of 

SSM it would take to exceed the 30-day standard as a function of normal emission rate, given various 

SSM emission rates in lb/MMBtu. In the example calculation, commenter 17868 states that if the normal 

emission rate is 0.02 lb/MMBtu and the startup emission rate is 0.45 lb/MMBtu, then a unit could have 

only 16.7 hours in startup before exceeding the standard. Commenter 17868 states in another example, 

that for a normal emission rate of 0.28 lb/MMBtu PM and a startup emission rate of 0.45 lb/MMBtu, 

then the unit could have only 3.4 hours before exceeding the standard.

Commenter 17867 states that unlike the Industrial Boiler MACT, which requires work practice 

standards be met during periods of startup and shutdown, the Utility NESHAPs Rule requires numerical 

emission limits. The EPA asserts that startup and shutdowns are predictable and routine aspects of 

source operations; thus, a 30-day averaging period should be sufficient to smooth any startup and 

shutdown emissions. The commenter disagrees with this assertion. Startups and shutdowns are not 

always routine and a 30-day averaging period will not always be enough to smooth out the emission 
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averages. The EPA has not provided justification as to why the work practice standards, as allowed 

under CAA 112(h), should not apply during periods of startup and shutdown. The commenter

recommends that the EPA should adopt work practice standards during periods of startup and shutdown 

for sources subject to the rule.

Response to Comments 1 - 6: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. 

b. Economic.

Comment 7: Commenter 17772 states that the capital cost of compliance is related to how 

startup/shutdown periods are handled and the filterable PM limit, in that including startup/shutdown 

emissions in 30-day rolling averages may force companies to install additional multimillion dollar 

controls that may not otherwise have been necessary. Commenters (17815, 17904) state that installing 

additional APCDs to target startup/shutdown emissions does not make economic sense considering the 

startup/shutdown time and the amount of emissions contributed to overall EGU emissions.

Response to Comment 7: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion.

c. No APCD experience.

Comment 8: Commenter 18498 states that facilities have no experience with the APCD and additives 

necessary to comply with the standards, and facilities cannot predict what emissions may occur during 

startup/shutdown or how compliance can be achieved during those periods. Commenter 17912 fails to 

understand how a new or reconstructed facility can design, build, or operate APCD that must meet a 

standard at all times, including SSM periods, when the facility has no way of knowing through any

scientific means or method what the “compliance standard” for continuous compliance will be until the 

equipment is first tested. Accordingly, the commenter requests that the agency remove this requirement 

and replace it with a number derived from the ICR data base with a reasonable allowance added for the 

operational flexibility needed to assure compliance under the “worst foreseeable circumstances.”

Response to Comment 8: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. 

d. Not able to achieve the standard.

Comment 9: Multiple commenters (17383, 17689, 17712, 17740, 17813, 17876, 17885, 17930, 19032) 

state that applying MACT limits during startup/shutdown places the source at risk of noncompliance. 

Commenter 17775 states that limited data from startup and shutdown events show these events can 

cause significant compliance concerns. Commenters (17774, 17877) state that the EPA has no factual 

basis to conclude that even the best performing sources can achieve the standards. Commenter 17736 

states that the EPA’s flawed assumptions are devastating in that some of the most technologically

advanced units (controlled with overfire air; SCR; FGD; and FGD plus SCR) will not be able to achieve 

the MACT limits during SSM periods. Commenter 17795 states that some units may be forced to 

operation at economic loss for no reason other than to generate enough full load operating data to 

comply, and potentially displacing units that have fewer emissions.
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 Commenters (17736, 19122) state that just a few hours of noncompliance during SSM can 

destroy/exceed the 30-day rolling average.

 Commenter 17925 states that several startups can occur in a 30-day period and cause 

noncompliance.

 Commenters (17383, 17689, 17712, 17724, 17813, 17876, 17885) note that more than one 

outage could mean noncompliance.

 Commenter 17868 states that one outage could cause an exceedance.

 Commenter 19032 states that outages could put a unit in noncompliance.

 Commenter 17868 states that forced outages are out of the utility’s control.

 Commenters 17756, 17775, 17820 state that units with more than one SS will be penalized with 

significantly higher emissions and also a smaller number of operating hours.

 Commenter 17767 states that if a unit that experiences a difficult, lengthy startup, compliance 

with the 30-day averages would be difficult or unachievable. 

Response to Comment 9: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. 

e. 30-day average not sufficient.

Comment 10: Commenter 17904 believes the EPA has taken a positive step in establishing a 30-day

average. Commenter 19121 generally supports the 30-day average, if non-Hg HAP are to be regulated.

Comment 11: Commenter 17877 states the 30-day averaging period is not sufficient to allow 

compliance. Commenter 16849 states the 30-day average period is too short. Commenters (17807, 

17886, 17925) state that the EPA has not demonstrated the 30-day averaging period will enable 

compliance. Commenter 17740 states that varying operating modes experienced by EGUs make a 30-

day averaging period impractical or impossible. Commenter 17930 states that 30-day average is not 

sufficient to account for the variability of lignite.

Comment 12: Several commenters (17775, 17795, 17877, 17925) state that a 30-day averaging period 

is not sufficient to account for startup/shutdown emissions. More specifically:

 Commenter 17877 states that 30-day average is not sufficient where multiple SS occur.

 Commenter 18428 states 30-day average is not sufficient to account for varying load conditions 

and SS. 

 Commenter 17728 states the EPA cannot assume that a longer averaging period accounts for 

startup/shutdown, and the EPA provides no data to support the assumption.

 Commenter 17740 states that examination of EGU operations demonstrates that a 30-day

average is insufficient to account for variable emissions from multiple startups and shutdowns.

 Commenter 16849 states that every SSM produces emissions that will be problematic for the 

averaging period.

Comment 13: Commenter 17740 states that EPA’s statement that EGUs “do not normally startup and 

shutdown frequently” effectively, and incorrectly, assumes that all units are operated as base load units. 

As the Seventh Circuit recognized in United States v. Cinergy, “[u]tilities operate power generation 

equipment in three general ways: base load, cycling, and peaking.” 623 F.3d 455, 459 (7th Cir. 2010). 

Non-base-load units start up and shut down frequently, and even supposed “baseload units” are often, 
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and unpredictably, shut down for unit “trips” (i.e. unplanned outages). The EPA further assumes that 

basing the proposed standards on a 30-day rolling average will account for any increased emissions 

during periods of startup and shutdown. The EPA made this same faulty assumption in the proposed rule 

that preceded the Boiler MACT (see 75 FR 32,012-13) and rejected it in the final rule (see 76 FR

15,642). The EPA has not demonstrated that the 30-day rolling average will address the substantial 

operating variations among EGUs or even within an EGU. Further, while a number of the MACT pool 

EGUs are newer, well-controlled, base load units, the EPA cannot assume that the entire universe of 

coal-fired EGUs, even base-loaded units, will operate as reliably as newer units. As EGUs age, they tend 

to experience more forced outages than when they were newly constructed. Thus, an older EGU with 

highly efficient controls may not be able to meet a 30-day standard in months in which it experiences a 

number of forced outages.

Response to Comments 10-13: For periods of startup and shutdown, the EPA is finalizing work 

practice standards instead of numeric emission limits. See the preamble for discussion. The EPA’s 

rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this 

final action.

f. Normal plant operations/outages/describe SSM periods.

Comment 14: Commenter 16849 states that SSM are part of power plant operations and facilities 

should not be penalized for these occurrences. Further, commenter asserts that providing no exemption 

during startup/shutdown is an unrealistic expectation. Commenters (17878, 19114) state that SS(M) are 

part of normal operation. Commenter 17737 states the EPA should consider startups part of normal 

operation. Commenter 17772 states that even top performers will have occasional malfunctions and will 

have multiple startup/shutdown periods during a year.

Commenter 17740 states that the EPA ignores the fact that EGUs require an extended period of startup 

during which equipment (boiler, control devices) are not operating in their normal conditions, and this 

extended period cannot be shortened or avoided. Commenter 17737 states that several factors can lead to 

multiple startups or long periods of startup, including equipment problems (burner management logic, 

ignitors), or problems related to water chemistry, that would prolong the unit getting to temperature. 

Commenter 17737 notes that when outage does occur, there may be multiple or long startup attempts 

that are more relevant in terms of the EPAs compliance standard based on 30 boiler operating days. 

Commenter 17737 provided a list of startups and corresponding bypass times allowed in their Title V 

permit in 2010.

Commenter 17795 states that their units startup and shutdown frequently, and note it is not uncommon 

for units to have more than four startups in a 30-boiler day operating period. Commenter 17795 provides 

a table showing the number of startups during the first 30 days of 2010 for several typical units: unit 1 

had 12 startups; unit 2 had 5 startups; unit 3 had 20 startups; unit 4 had 7 startups; and unit 5 had 4 

startups.

Commenter 16849 states that cold startup can take 16 hours, and two or three startups in a month will 

not allow the facility to meet the SO2 surrogate standard. Commenter 18498 states that the time for 

startup depends on the type of startup (cold, warm, hot). Commenter 17740 notes that startup duration 

varies depending on the condition of the boiler at the time of startup, i.e., cold starts can take 

approximately 72 hours, warm starts up to 18 to 20 hours, and hot starts can take 6 to 8 hours.
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Commenter 18025 states the majority of APCDs require a period of time to reach peak performance 

(temperature and flows). Commenter 18498 states that adequate time is needed for APCD to operate 

prior to measurement of filterable PM. 

Commenter 17774 states that many units have multiple startup/shutdown events within 30-day period 

due to varying load demand or maintenance, and outages that may or may not meet the criteria of 

malfunction. Commenter 17740 states it is not uncommon for their plant and other similar units to 

experience more than one startup within 30 days due to forced outages and planned maintenance. 

Commenter 17316 states that the averaging period is only appropriate if the number of startups is small 

and the duration is normal. Commenter 17877 states it is unreasonable to assume a large EGU will only

SS once during a 30-day period.

Commenters (16849, 17923) describe the EGU forced outage rate curve throughout its life cycle as an 

inverse bell curve: high forced outage rate when new until issues are resolved, reduced forced outage 

period until parts reach their useful life, then increased forced outage rates again as parts must be 

replaced.

Response to Comment 14: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action.

g. Peaking units.

Comment 15: Several commenters (17725, 17820, 18014, 18498) state that even with relatively long 

averaging periods (30-day rolling averages), the emissions from nonrepresentative periods could 

significantly affect averages, especially for peaking units or other units that come online and offline 

frequently. Commenters (17715, 17757, 19114) state that including startup/shutdown periods have a 

great effect on peaking units that startup and shutdown more. Commenter 17736 states the EPA failed to 

account for the critical operation of peaking units which go through these periods frequently. 

Commenters (17316, 17386) state that the averaging period will not work for EGUs (e.g., dispatchable) 

that are in service for short periods (e.g., part of a day) and startup/shutdown periods represents a 

significant portion of the operating day.

Commenter 17820 states that units that are required to follow load demand will be penalized. 

Commenter 17774 states that the EPA does not account for load-following units or units used on a 

sporadic basis. Commenter 17774 states that a number of their units follow load, cycle, or are otherwise 

subject to numerous startup/shutdown periods. Commenter 17623 states the EPA’s analysis is flawed 

because it did not account for load following or load cycling facilities, which startup and shutdown on a 

more frequent basis and have additional SSM periods.

Commenter 17720 states that use of 30-day averaging period will not smooth out any emission increases 

associated with startups/shutdowns that are driven by dispatch decisions by distant RTOs. Commenter 

17772 states that many EGUs are RTO members and must follow RTO directives to shutdown or run at 

minimum loads.

Comment 16: Commenter 17930 agrees generally that coal-fired baseload units do not SS often, 

however this is likely to be less of the norm. Commenter 17704 agrees that base load units do not 

typically startup and shutdown frequently, however, that is changing and cite a new nodal system in 

Texas that may increase the frequency of startup/shutdown events. Commenter 17795 states that recent 
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regulation changes, Cross State Air Pollution Rule (CSAPR), could cause units to cycle more in the 

future placing greater emphasis on potential effect on SSM on average emissions.

Comment 17: Several commenters (17720, 17758, 16849, 17930) discuss the use of renewable fuels. 

Commenter 17720 notes that the EPA’s assumption that startup/shutdown periods are predictable and 

routine does not take into account the increasing impact of renewable resources and the increasing 

control of RTOs. Commenters (17758, 16849, 17930) note that the use of renewable fuels will cause 

additional startups/shutdowns for fossil-fuel units. Commenter 17758 states while routine maintenance 

and repair and transmission upgrades are predictable and routine, the increased cycling (unplanned 

outages) to accommodate renewables results in increased startups and shutdowns. Commenters (17758, 

16849) note that the overall impact of cycling reduces overall emissions because fossil units are used 

less and renewables are used more. Commenter 17758 states the small emission increase during 

startup/shutdown periods is likely dwarfed by avoided emissions due to renewable facility operation. 

Commenters (17758, 16849) state the EPA should not penalize environmentally friendly practices. 

Commenter 17758 states the emission benefits associated with increase operation of renewable 

resources exceed those realized by imposing numeric standards during startup/shutdown periods. 

Commenter 17868 states that including SSM activities are a concern because of the increasing number 

of “load-following coal-fired power plants that backup wind and solar power plants. Further, commenter 

17868 states that ramping up and down and the startup/shutdown activities will increase emissions.

Comment 18: Commenter 17796 states that EPA should allow an emission calculation based on an 

emission factor for SSM, and suggested a simple calculation based on fuel feed rate multiplied by a 

predetermined emission factor will give an accurate measurement of emissions, rather than the onerous 

requirement to monitor fuel flow rates and sample fuel to determine heat content and composition.

Response to Comments 15 - 18: For periods of startup and shutdown, the EPA is finalizing work 

practice standards instead of numeric emission limits. See the preamble for discussion. The EPA’s 

rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this 

final action.

h. Monitoring plan/suggested startup/shutdown approaches.

Comment 19: Commenter 17316 recommends that facilities establish a maximum allowed duration for 

startup/shutdown periods in the Monitoring Plan. Commenters (17316, 17386) state if startup/shutdown 

hours exceed a certain proportion of total operating hours in the 30-day operating period (e.g., more than 

20 percent), then startup/shutdown periods should be excluded from the 30-day average.

Response to Comment 19: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion.

i. Not clear how SSM included/no basis for standard.

i. General.

Comment 20: Multiple commenters indicate that data used for the MACT floors are not representative 

of startup/shutdown conditions, and provided various comments including:

 MACT floor or limit does not account for SS(M) emissions (17623, 17715, 17725, 17757, 

17774, 17820, 17851, 17868, 17877, 18014, 18037, 18429, 18498, 19114, 19121, 0234-18023)
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 EPA does not account for required shutdowns (17761)

 EPA does not have emissions data for startups/shutdowns for EGUs (17732, 17756, 17851)

 EPA never collected and analyzed a sufficient amount of data (17736)

 Facility does not have startup or shutdown emission data (17722, 17737)

 EPA does not have sufficient information or data on SS(M) emissions (17795, 17736, 17402)

 Data was during regular operation (17732)

 Application of the MACT standards during SSM periods is inappropriate (17623, 17774, 18037)

 EPA has not accounted for emissions, or higher emission levels, from SS (17730, 17736, 17761, 

17772, 17816, 17821)

 EPA cannot apply a single standard that applies at all times (17732, 17774)

 Commenter 18429 states it is inappropriate to include SSM in the compliance demonstration

Commenter 17740 states that the EPA fails to consider whether performance standards would be 

practicable at EGUs during startup/shutdown periods. Commenter 17722 questions whether the EPA has 

correctly evaluated startup/shutdown periods in setting the limits. In addition:

 Commenters (17197, 17627, 17704, 17715, 17716, 17722, 17724, 17725, 17728, 17730, 17732. 

17736, 17752, 17757, 17761, 17767, 17774, 17775, 17808, 17820,17870, 17876, 17877, 17878, 

17886, 17904, 18014, 18037, 18428, 18498, 19114, 18023) state that stack testing data submitted 

(under the ICR) did not include SSM periods but was for normal, steady-state 

operation. Commenter 17851 states that all data was collected under steady-state conditions. 

Commenter 17736 states the MACT limits are based on full load steady state testing, and not on

the full range of operating conditions, including changes in operating variables. Commenter 

17736 states that data that is limited to a single operating characteristic under utopian conditions 

is insufficient and inappropriate for establishing MACT limits that must be satisfied at all times.

 Commenter 17767 states that no attempt was made to quantify emissions from 

startups/shutdowns during development of the emission limits. Commenter 17925 states no stack 

test data exists for startups/shutdown.

 Commenters 17772, 17774, 18428 state EPA analyzed short-term testing (snapshot) of EGUs 

under normal operation conditions. Commenter 19114 states it is impossible to declare the 

MACT floor includes variability adjustments for SS when EPA possesses no test data to support 

the declaration. Commenter 17761 states the rules fail to account for operational variability and 

required shutdowns and do not appropriately represent emissions that can be consistently 

achieved. 

 Commenter 17925 assumes EPA used isokinetic stack testing during normal operation, without 

regard to actual emissions limit, or used arbitrary non-isokinetic assumptions to quantify SS 

emissions.

 Commenter 17925 does not understand how the EPA integrated startup/shutdown emissions into 

the 30-day standard.

 Commenter 17774 notes in particular that no malfunction data was incorporated into the MACT 

floor.

Commenter 17736 states that EPA should recognize these issues, especially when establishing standards 

without adequate consideration of data and other information.

Commenters (17383, 17724, 17876) question whether the EPA has accurate startup data for Hg 

emissions, state they are not aware of any Hg startup emission data, and note that Hg emissions spike 

during startup. Commenters (17383, 17724, 17876) request that the EPA provide a clear analysis of this 
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startup Hg emissions data with respect to the development of the variability calculations and the 

standard.

Response to Comment 20: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action.

ii. The EPA not demonstrated that limits are achievable.

Comment 21: Commenter 19114 states that by setting a limit to include startups/shutdowns but basing 

the limits solely on full load, steady-state test data, the EPA is violating the requirements of the CAA to 

set achievable standards. Commenter 17772 notes that the EPA’s approach understates the true average 

emissions of top 12 percent. Commenter 17878 states that the emission standard is lower than the rate 

“achieved in practice” by the best performing units. Commenter 17761 states that the EPA 

inappropriately established standards that do not reflect the “average emission limitation” achieved by 

the best performing 12 percent of existing sources. Commenters (17724, 17876) state the EPA must 

evaluate startup/shutdown emissions to demonstrate that the limits are achievable. Commenters (17402, 

18037, 18539) state that given the lack of data and that the limited data that are available show 

emissions are higher during SS, the EPA has not established an emission standard that can actually be 

achieved during SSM, as required by statute. Commenters (17851, 17878) state that MACT standards 

must be based on evidence that sources have achieved them. Commenter 17851 states that standards 

must be achievable under the most adverse circumstances which can reasonably be expected to recur.

Comment 22: Commenter 17732 states the EPA should explain what data was used to come to the 

conclusion that a single standard can be met at all times, including startup/shutdown periods. 

Commenter 17737 states that EPA provides no data or analysis to demonstrate that coal-fired EGUs will 

be able to meet the standard including SS periods. Commenter 17851 states the EPA must demonstrate 

why facilities can comply with the final standards. Commenter 17851 states that the EPA’s statement 

that sources can meet the standard during SSM is not based on any data, at least there is not data in the 

record. Commenter 17724 states the EPA must evaluate the ICR data to identify startup/shutdown 

emissions. Commenter 17722 requests that the EPA demonstrate how the ICR data is inclusive of 

startup/shutdown emissions for each regulated pollutant. Commenter 17772 states the EPA failed to 

quantify the level of any startup/shutdown adjustment, explain its methodology for taking SSM into 

account, and has not used real data for an adjustment, and thus the emission limits are arbitrary and 

capricious. Commenter 17815 states it is unclear how much SSM data was included in the analysis.

Comment 23: Commenter 18023 states that the impact of a single startup or shutdown event is 

unknown. Commenter 18428 states that representations by the EPA and other stakeholders that a 

number of units already meet the proposed limit are based on stack test data and not on continuous 

monitoring over 30-day periods, so these representations are incomplete at best. Commenter 18023 

states that the EPA has not shown through analysis that startup and shutdown events will not have a 

significant impact on the 30-day averages and the EPA has not presented evidence that they accounted 

for the impact of startups/shutdowns as it claims, given that the stack test data the emission limit is 

based on was collected for full-load steady state conditions. Commenter 17795 states that meeting a 

standard based on steady state operations at full load during SSM and load swings by use of a 30 day 

averaging period is not supported by data. Commenter 17758 states the EPA has not demonstrated that 

the 30-day average will enable compliance, and the EPA’s assumption is unsupported by data from 

actual units. Commenters (17728, 17729, 17775, 17756) state the EPA has no way of knowing if the 30-

day average is sufficient to address unpredictable startup emissions. If the EPA cannot demonstrate, then 
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commenters (17724, 17876, 19032) state that startup/shutdown periods should be excluded from 30-day

averages.

Response to Comments 21 - 23: For periods of startup and shutdown, the EPA is finalizing work 

practice standards instead of numeric emission limits. See the preamble for discussion. The EPA’s 

rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this 

final action.

iii. Burner inspection outage.

Comment 24: Commenter 17761 states that at a minimum, with the mandatory burner inspection 

requirements that impose an additional startup and shutdown on facilities, the EPA should take into 

account the emissions from the mandatory startup and shutdown precipitated by its own rule in 

establishing the “best performing” sources. Commenter 17930 states that rule requirements for annual 

shutdowns, for burner tune-ups, will increase the frequency of baseload units being shutdown, along 

with the suit of other EPA regulations. Commenter 17930 cites the allowance allocations in the CSAPR 

that assume units will operate seasonally, which will result in more SSM activity.

Response to Comment 24: In addition to the final rule treatment of startup and shutdown periods 

discussed in the responses under this section (see Responses to Comments 1-23, above), EPA also notes 

that the final rule adjusts the frequency of burner inspections to once at least every 36 months (or 48, in 

certain circumstances), so that the inspections can better coincide with planned unit outages. See further 

discussion under Comment Code 4D02. 

iv. Burner inspection requirement.

Comment 25: Several commenters (19536, 19537, 19538) state that during SSM events, organic HAP 

emissions are known to increase for short periods due to low boiler combustion temperatures, poor 

mixing, and low excess oxygen levels. Commenters state that the proposal is silent as to how an annual 

tuneup would assure organic HAP emissions remain controlled during SSM periods.

Response to Comment 25: Under the general provisions of Part 63, all sources must operate and 

maintain their sources in accordance with good air pollution control practices to minimize emissions. 

Those general provisions, together with the standards that apply (including the specific work practice 

standards in the final rule applicable to startup and shutdown periods), will ensure that organic HAP 

emissions are minimized from affected sources during SSM periods. 

v. Recommendations for EPA.

Comment 26: Commenter 17622 recommends re-testing of units under the same conditions to verify

emissions are repeatable and sustainable over operating periods that include startup/shutdown periods. 

Commenters (17732, 17772, 17774, 17877) state the EPA should collect and analyze data for emission 

standards during SS(M). Commenter 17737 states EPA should collect and analyze emissions data to 

evaluate the compliance risk associated with inclusion of startup periods in the MACT standard for 

normal operations. Commenters (17815, 17904) state that the EPA should analyze excess emission 

reports to determine the frequency of startups/shutdowns and include that analysis in the standards.
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Commenter 17795 states the EPA must account for the effect of startup/shutdown emission on a 30-day

average. Commenter 17729 states that setting the PM limit as the actual emission value measured during 

steady-state testing leaves no room for process variability and for startup/shutdown emissions.

Commenter 18021 believes the EPA needs to consider applying adjustments to the limits to allow for 

differences in operation conditions. Commenter 17930 states the EPA should increase the emissions 

limits for all pollutants to better account for SSM emissions. Commenter 17912 requests that the EPA 

replace the requirement with a number derived from the ICR database with a reasonable allowance 

added for operational flexibility needed to assure compliance under the worst foreseeable circumstances.

Response to Comment 26: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. This approach is more workable than the use of 

adjustments as suggested in some of these comments. See the preamble for discussion. The EPA’s 

rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this 

final action.

vi. Variability component.

Comment 27: Several commenters (17725, 17820, 18014, 18037, 18498, 18539) state that the EPA 

does not have sufficient data (either reference method or CEMS data) to address variability during 

SS(M) periods and load changes (17820). Commenters 17730 and 17761 state startup/shutdown 

emissions must be adequately accounted for in the variability component. Commenter 17886 states the 

EPA should revise its variability adjustment to account for long term unit emissions variability. 

Commenters 17724 and 17876 state that the variability component of the MACT floor calculation drives 

the final emission limit more so than the mean value of the data set. Commenters 17724 and 17876 

further state that the variability component could be drastically different with inclusion of 

startup/shutdown emissions data, resulting in a higher limit. Commenter 17722 states the EPA would 

develop a much different emission limit if startup/shutdown emissions were in the data sets.

Response to Comment 27: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action.

j. SSM results in increased emissions/distinct operating modes.

Comment 28: Commenters 17730 and 17740 state SS(M) periods are distinctly different modes of 

operations from normal operation. Commenters 17705 and 17757 state that startup/shutdown periods 

have different emission characteristics than emissions during normal operations. Commenters 17715 and

19114 state that startup/shutdown emissions are not similar to steady state full load emissions. 

Commenter 17878 states that SSM periods result in increased emissions rates. Several commenters 

(17715, 17757, 17856, 19114) state increased emissions during startups/shutdowns could skew the 

average emission rate. Commenter 17851 states that non-steady state emissions could alter the EPA’s 

calculations. Commenter 17705 states that other transient conditions such as significant load changes 

will result in emissions in excess of those measured during initial performance tests. Commenter 17851 

states that emissions during non-steady state conditions may vary significantly.

Several commenters (17808, 17870, 18025) note that, as in the Boiler MACT, malfunctions should not 

be considered a distinct operating mode. Commenter 17851 disagrees with the EPA that malfunctions 

are not distinct operating modes.
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Commenter 18023 states that startup is a distinct operating period and it should be considered 

independently. Commenter 18023 provides Hg CEMS data showing two distinct emission profiles for 

periods of startup (when SCR is offline due to low temperature) and for periods of steady-state with full 

control (when both SCR and FGD APCD systems are operating). Commenter 18023 further states that 

steady-state emissions data do not represent emissions during startup/shutdown periods.

Commenter 17775 states that long-term Hg and PM CEMS data show spikes in emissions that are likely

due to startup/shutdown events. Commenter 18428 has reviewed Hg CEMS data from 2 coal-fired units 

and states that the data spike above the proposed standard (1.2 lb/trillion Btu) is likely due to 

fluctuations.

Commenter 18449 states that startup results in very high stack Hg concentration for a short amount of 

time, most likely from Hg deposited on ducts and other surfaces, although Hg emissions are not 

necessarily high since the flow rate is very low. Commenter 18449 provides graphs with actual startup 

Hg emissions from Hg CEMS; the normal emissions are 3 to 4 ug/m3, with an ESP and SCR. 

Commenter 18449 states that the short transient nature of SSM events causes severe errors in estimating 

hourly mass emissions based on multiplying hourly averages of pollutant concentration and hourly

average of stack flow; these problems are worse when the mass is normalized to lb/GWhr using a 5 

percent of full power output, which will artificially inflate the emissions rate by a factor of 20 and added 

to the rolling average, even though the actual mass emissions may not be significant during SSM. 

Commenter 18449 states this is punitive.

Commenter 17772 states that their facility has 18 months of PM CEMS data with startups/shutdowns 

included that shows fully controlled units will not be able to comply with the emissions limit. The 

commenter provides graphs of 30-day boiler operating day average data for three units, and provided 

data showing the wide difference between PM CEMS data with and without startup/shutdown data. (See 

Figures 1 through 3 and Table 3 of letter, Docket Item No. The EPA-HQ-OAR-2009-0234-17772.) The 

commenter indicates that 0.018 lb/MMBtu is representative value for filterable PM, however, with 

startup/shutdown values included, the representative value is 0.29 lb/MMBtu (includes low flow rates, 

high concentrations, and CO2 diluent of 5 percent), which is 16 times higher.

Commenter 17795 provides average SO2 emissions data for 30 boiler operating days that include two 

startups, showing that SSM occurred for 10 percent of operating hours during the period and that 

including SSM emissions results in an increase of 13 percent in the 30-day average emission rate.

Response to Comment 28: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. In 

addition, one commenter maintains that the during SS and M periods there are fluctuations in the 

monitoring, but the commenter also refers to a provision in the proposed rule that allowed sources to 

assume a 5 percent of full capacity factor for periods of startup and shutdown. The 5 percent conversion 

is no longer included in the rule because we are establishing work practice standards for such periods. 

Because the proposed 5 percent factor does not apply to malfunction periods, the comment concerning 

artificial inflation of the emissions rate is not relevant to periods of malfunction. The final rule requires 

source owners who use continuous monitoring to measure emissions during malfunctions periods. We 

believe that it is important to collect data during all process operating periods including SSM periods, as 

the rule requires when conducting any continuous monitoring (see additional responses below relative to 

the accuracy and utility of such data). The agency also believes EGU owners or operators strive to 

minimize periods of malfunction and should a malfunction period occur, its duration will be brief, as 
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noted by the commenter. Any impact of potential excess emissions occurring during a period of 

malfunction should be offset to some degree through use of the rule’s 30 boiler operating day rolling 

average requirement. To the extent the CEMS records an exceedance during a malfunction, and the 

owner or operator believes the measurement was in error, the owner or operator can demonstrate that the 

source complied with the standard notwithstanding the CEMS measurement using any available 

information. See also responses below that address the issue of determining compliance during 

malfunction events.

k. Use of CEMS during startup/shutdown.

Comment 29: Several commenters express concerns regarding the use of CEMS for measurement 

during startup/shutdown. Commenters (17677, 17728, 17729, 17775) also indicate it is not feasible to 

measure compliance with CEMS during startup; commenters cited the following issues for 

startup/shutdown, including temperature issues (17728, 17729, 17815), low flow rate (17815, 17728), 

and varying moisture (17729). Commenter 18498 states that particulate size varies during 

startup/shutdown and cannot be measured accurately by PM CEMS. Commenter 18498 states that 

startup/shutdown periods present wide variations depending on the process and control equipment. 

Commenter 17728 states the EPA does not account for the absence of correlated PM CEMS during 

startup/shutdown periods. Commenters (17728, 17736, 17752, 17772) state the PM CEMS correlation 

curves do not include any data during SSM periods. Commenters (17728, 17752) state the PM CEMS 

cannot be correlated and the accuracy of PM CEMS data during those conditions is unknown, and 

commenter 17736 states the correlation can only be done during normal operating loads. Commenter 

18498 states that PM CEMS are calibrated for normal operating conditions. Commenter 18498 states 

that startups/shutdowns present significantly different conditions that are not part of PM CEMS 

calibration.

Commenters 17677 and 17775 state that CEMS are not correlated to startup/shutdown periods because 

the EPA reference test methods were not designed for transient or dynamic plant operations. Commenter 

17677 questions the enforceable value of these data, and states the EPA needs to consider the ability for 

CEMS to accurately monitor emissions in startup/shutdown periods. Commenter 17772 states the PM 

CEMS data from startups/shutdowns are not reliable and highly variable. Commenter 17886 states they 

do not know of valid test or CEMS measurement techniques for HAP during startups/shutdowns. 

Commenter 17736 states that most units do not start up on coal but use other fuels (e.g., fuel oil), and a 

PM CEMS that was correlated for coal does not measure emissions accurately. Several commenters 

(17725, 18014, 18498) state that particle size distribution or unburned levels during startup affect PM 

CEMS measurement accuracy, particularly those using light scattering or optically-based technologies; 

commenter 17728 states that the particle size distribution may differ from those in the correlation.

Several commenters (17725, 17820, 18014, 18498) state that including SSM is critical for units using 

PM CEMS to demonstrate continuous compliance, since part 63 no longer includes exemptions for 

SSM.

Commenter 17925 states that there are very few CEMS in operation to provide data to confirm that 

limits can be met during startup/shutdown.

Commenters 17774 and 17821 relay that there are operation problems for sorbent trap CEMS to 

demonstrate compliance with Hg limits during startup; Commenter 17774 cites the following for sorbent 

trap CEMs: demonstrate poor performance, flue gas conditions are unacceptable, and interferences cause 

breakthrough.
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Response to Comment 29: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits and thus commenters concerns related to reliance on CEMS 

during such periods is moot. See the preamble for discussion. The EPA’s rationale for its approach to 

malfunctions is discussed in the preambles to the proposed rule and this final action.

With respect to commenters’ concern that PM CEMS cannot be correlated and the accuracy of PM 

CEMS data during malfunction periods is unknown, see responses below that address the issue of 

determining compliance during malfunction events.

l. The EPA assumptions/justifications.

i. Support or oppose EPA’s assumptions.

Comment 30: Multiple commenters (17728, 17740, 17758, 17774, 17775, 17807, 17808, 17851, 17870, 

18023) disagree with the EPA’s rationale and assumptions for including startup/shutdown in the MACT 

standard. Commenter 17740 states that the EPA’s justification for not establishing different 

requirements for startup/shutdown (include (1) EGUs do not normally startup and shutdown frequently, 

and (2) EGUs typically use cleaner fuels during startup) are unsupported and do not reflect actual EGU 

operating practices). Several commenters (17728, 17729, 17756, 17775) state the EPA’s rationale does 

not account for the variety of ways EGUs startup and shutdown (types of fuel, duration varies), and is 

not based on actual emission observations during startup/shutdown (17728, 17775). Commenter 17807

states the EPA has not justified these assumptions based on actual startup/shutdown data. 

Multiple commenters cited concerns about EPA assumptions regarding SSM and made statements such 

as the following: startup/shutdown periods are predictable and routine (17691, 17821); startup/shutdown 

periods are not predictable and routine (17807, 17758); EGUs do startup and shutdown frequently 

(18447); base load units do have startups and shutdowns (17772); EGUs do not startup frequently 

(17851); solid fuel-fired EGUs startup infrequently (17815); the duration of startup/shutdown is 

reasonably predictable (17316, 17386); the duration of startup can vary significantly (17756); the 

emissions during startup are variable (17316, 17386), due to transient combustion conditions (17386), 

affected by length of time unit has been shutdown (17316, 17386), and affected by ambient conditions at 

lite-off (17386); the number of startups in a given period can vary (17756); frequency and duration of 

startup/shutdown varies by unit and fuel blend (17758, 17807); base load units generally operate for 

long periods without an outage (17737); and historically, planned outages for maintenance and repair 

were fairly predictable and routine (17720, 17758). 

Response to Comment 30: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action.

ii. Cleaner fuels.

Comment 31: Commenter 17740 states that units burn a wide array of fuels and the EPA cannot assume 

without additional justification that EGUs rely on cleaner fuels during startup. Commenters 17740 and

17774 also state that emissions may be higher than normal during startup periods, even when alternative 

(cleaner) fuels are used. Commenter 17728 states the EPA cannot assume that use of cleaner fuels 

accounts for startup/shutdown periods, and the EPA provides no data to support the assumption (flue gas 

conditions and particle size distribution may differ significantly during startup/shutdown than other 

periods). Commenter 17737 takes little comfort in the EPA’s assertion that emission exceedances will 
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not occur due to use of clean fuels during startup. Commenters 17737 and 17772 state that they use oil 

during startup with APCD bypass (FF, ESP) to avoid oil residue fouling, and Commenter 17737 states 

that bypass occurs until flue gas entering the FF is 160 oF. Commenter 17756 states that they use oil for 

some units and use NG for others during startup. Commenters 17702 and 18018 state that many EGUs 

use oil for startup when NG is not available. Commenter 17702 states the EPA should consider an 

exception during startup/shutdown when an EGU is forced to use oil or when NG is not available. 

Commenter 17758 states the EPA has not provided support that use of different fuel for 

startup/shutdown would minimize emissions. Commenters 17815 and 17904 agree that solid fuel-fired 

EGUs typically startup on cleaner fuels, however note that some fire and transition to solid fuel during 

startup. 

Commenters 17808 and 17870 state that most EGUs will switch fuels during startup, but for shutdown 

some will not switch fuels. Commenter 17702 states that manufacturer protocols for control equipment 

require additional delays for equipment startup when oil is used.

Response to Comment 31: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. 

iii. Combustion inefficient.

Comment 32: Commenter 17925 states that combustion is unstable (during startup), and design 

emission rates may not be achieved. Commenter 19114 states there are increases in products of 

incomplete combustion (PICs) (during startup). Commenter 17851 states that even when using cleaner 

fuel, the combustion process is inefficient during startup. Commenter 17851 notes that incomplete 

combustion would not impact fuel-derived HAP but would impact organic and PM emissions. 

Commenter 17904 states that boilers may not perform at the same efficiency during startup/shutdown.

Response to Comment 32: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion.

m. APCD not operated.

Comment 33: Numerous commenters (17316, 17386, 17402, 17623, 17675, 17715, 17740, 17757, 

17774, 17820, 17851, 17904, 17930, 18539, 19114) state that APCDs do not operate during startup or 

most of startup; commenters (17725, 17757, 17820, 17904, 18014, 18498) state some emission controls 

should not operate until the system comes to the proper temperature or other conditions; commenter 

17756 states that different control devices are brought online at different stages of startup.

Commenter 18018 states that manufacturer’s often require delays for APCD for startup when using oil 

and not NG. Commenter 18018 states that the EPA should consider an exception to the compliance 

provision when an EGU is forced to use oil or NG is not available.

Multiple commenters (17623, 17702, 17740, 17774, 17815, 17904, 17930, 17975, 18018, 19114) 

indicate facilities follow manufacturer recommendations and/or good engineering practices for APCDs. 

Commenters (17815, 17904) state that solid fuel-fired EGUs operate with manufacturer-established 

constraints on APCDs during startup. Commenter 17815 states that manufacturer limits on APCD 

constrain an EGU’s ability to comply with the standard during startup/shutdown. Commenter 17925 

states that APCDs are not designed for higher loadings during startup/shutdown. Commenter 17930 

states that manufacturer’s recommendations protect APCDs against failure, explosive conditions, and 
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ensure long-term functionality. Commenter 17740 states that EGUs have very few options for 

controlling, monitoring, or limiting emissions during periods of startup/shutdown due to equipment 

integrity concerns, technological limitations, and safety issues.

Multiple commenters indicate that APCDs are bypassed under certain operating conditions. Commenter 

19114 states that APCDs need to achieve stable operating temperatures or other conditions. In general, 

fabric filters must have a specific stack gas temperature to avoid damage or failure of the bags (17851, 

17740, 19121), and damage to the FF (17740, 19121). Commenter 19121 states that FF use during high 

loading of fuel oil cause bag blinding. Commenter 19121 states that use of FF during startup/shutdown 

may require replacement of all bags from each startup/shutdown event, and with five startups per year, 

this would be costly and may impact capture efficiencies. In general, ESPs must have a specific stack 

gas temperature (17740, 17930) to avoid short-term stability problems (17740), unsafe actions and longterm degradation due to fouling (17740), increased chances of wire damage (17740), or increased 

corrosion in chambers (17740). Commenter 17930 states that ESPs are on 85 percent of the coal-fired 

fleet. Commenter 17740 states that SDA require a minimum temperature, because the slurry feed rate is 

limited by the amount of moisture that the flue gas can evaporate. Commenter 17881 states that 

requiring the FGD system to operate during SSM, if technically feasible, is a waste of reagent, 

increasing ratepayer costs while providing no emission reduction or environmental benefit, damaging 

equipment and further resulting in unplanned shutdowns.

Commenter 18447 cites concerns for the safety ramifications of the rule. Commenter 18447 states that 

the EPA does not understand how to operate a boiler and the procedures that are necessary to operate 

safely during startup/shutdown. Commenter 18447 states that during shutdown or malfunction, the fuel 

to the boiler is shutdown and the ESP is powered down, to prevent unburned fuel from exiting the boiler 

and passing into the ESP where it would be ignited by the ESP if it remained powered up.

Commenter 17740 states that the warm-up time could theoretically be reduced by ramping up the fuel 

rate, but plants closely follow OEM warm-up period recommendations to avoid severe refractory

damage and excessive metallurgical stresses due to rapid changes in temperature and wide variations in 

temperature across boiler and duct parts. Commenter 17740 states inconsistent heating could cause 

immediate failures such as tears or ruptures in support steel or heat transfer surfaces, posing risk to 

personnel. Commenter 17740 notes that failure rates would increase if rapid heating and cooling cycles 

were conducted, which would further increase startups and shutdowns. 

Commenter 17772 states that if cooling pumps fail at shutdown, immediate bypass is necessary to avoid 

melting fiberglass tubes.

Commenter 17740 provides an example facility, a single unit plant that has upgraded with installation of 

new control equipment (SCR, FGD, and PJFF) that is considered BDT, modification of plant heat 

rejection system, and improvements to the boiler. Commenter 17740 states that the plant cannot operate 

the SCR and FGD during startup when the flue gas temperatures and boiler steam pressure are lower 

than required. The commenter indicates that the current permit limit requires lb/MMBtu for SO2 and 

NOX on a 30-day rolling average; the plant can meet the permit limits if there is only one startup within 

a given 30-day period, however, additional startups significantly jeopardize compliance for SO2 and 

NOX.

Response to Comment 33: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These work practices take into account operation of 
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APCDs. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is 

discussed in the preambles to the proposed rule and this final action.

n. APCD not efficient.

Comment 34: Numerous commenters (17402, 17623, 17705, 17715, 17725, 17736, 17757, 17758, 

17772, 17774, 17807, 17808, 17820, 17821, 17870, 17877, 17902, 18014, 18498, 18539, 19114) state 

some APCDs do not operate efficiently (or optimum performance) during SS(M) periods. Commenter 

17736 states that even the most advanced technologies have lower removal efficiencies during 

startup/shutdown periods. Commenter 17736 states that the EPA failed to recognize that control 

technologies cannot achieve the relied-upon result every hour of each day of the year. Commenter 17772 

states the EPA must recognize how APCDs function and the limitation of APCDs during SSM in order 

to develop reasonable and achievable standards. Commenter 17623 states it is not practicable to meet the 

same stringent standards as would be required when APCD is fully functioning. Several commenters 

(17758, 17772, 17774, 17807, 17821) state that emissions may be greater during startup/shutdown 

periods because APCDs do not operate efficiently until steady-state is achieved. Commenter 17856 

states SO2 emissions are higher from the scrubber and NOX and Hg emissions from SCR are higher 

during first few days of startup. Commenter 17725 states there may be periods when a source would not 

be able to comply with the standards because the control device does not operate at peak performance 

until certain operating conditions and flue gas temperature are achieved. Commenter 17821 states that 

FGD systems require 24 to 36 hours for startup to develop the proper scrubber liquor chemistry, and to 

achieve the SO2 emission reduction.

Commenter 17736 states that ESPs yield lower removal efficiencies during startup due to low 

temperatures; Several commenters (17736, 17772, 17821) state that SCR effectiveness cannot be 

realized until the unit reaches a specific temperature. Commenter 17821 notes that the SCR performance 

impacts Hg oxidation and stack Hg emissions and therefore impacts the ESP performance. Commenter 

17772 states that SCR contribution to Hg removal is high during normal operation, with the scrubber 

and ESP achieving 90 percent Hg removal, but is minimal during startup where the scrubber and ESP 

achieve approximately 65 percent Hg removal.

Commenter 17975 states that the EPA has failed to consider whether FF or other APCDs can 

substantially reduce emissions during startup/shutdown and maintenance. Commenter 17975 states that 

if other APCDs can reduce emissions, the PM limits must be based on superior technologies and not 

those APCDs that are not designed to operate effectively during startup/shutdown.

Response to Comment 34: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These work practice standards take into account operation 

of APCDs. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is 

discussed in the preambles to the proposed rule and this final action.

o. Rule clarifications.

i. Definition for SSM.

Comment 35: Several commenters (19536, 19537, 19538) state that the EPA does not define startup, 

shutdown, or malfunction.
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Response to Comment 35: The rule describes what constitutes startup periods and shutdown periods in 

Table 3 to Subpart UUUUU of Part 63. Table 9 indicates that the definition of malfunction contained in 

general provisions (40 CFR Part 63.2) applies.

ii. Period for emissions averaging.

Comment 36: Commenters 17808 and 17870 state that averaging emissions over 30 boiler operating 

days is only relevant for CEMS but is not relevant for units conducting monthly or quarterly 

performance testing because these EGUs are not averaging emissions during startup/shutdown periods.

Commenter 17772 suggests that an annual limitation measured could be established for SSM periods for 

uncontrolled emissions for some limited number of hours.

Response to Comment 36: The commenters are correct that the 30-day rolling average will only apply 

to sources demonstrating compliance through the use of CEMS or other continuous monitoring 

mechanisms. For periods of startup and shutdown, the EPA is finalizing work practice standards instead 

of numeric emission limits; therefore, the commenter’s suggestion that annual averaging be applied for 

startup and shutdown periods is moot. See the preamble for discussion. We do not believe that annual 

averaging times are appropriate for malfunction events. The EPA’s rationale for its approach to 

malfunctions is discussed in the preambles to the proposed rule and this final action.

iii. Definition of boiler operating day/subpart Da.

Comment 37: Several commenters (17756, 17775, 17820) state the “boiler operating day” definition is 

not flexible to account for periods of shutdown, and recommends the EPA specify a minimum number 

of operating hours necessary to calculate a 30-day rolling average. The commenters indicate that if the 

requisite number of hours is not obtained, then the EGU may combine data from that period with data 

from the next 30-day period until the requisite number of hours is obtained. The commenters indicate 

this is similar to subpart Da for calculation of a 24-hour average in section 60.48Da(g)(3), which 

requires a minimum number of valid hours to calculate an average. Commenters (17820, 17886) suggest 

the EPA define a “boiler operating day” as operating 75 percent of the day, or 18 hours or more. 

Commenter 17886 states that operating days should be defined as 18 hours or more operation and if less 

than 18 hours should be excluded from the 30-day average.

Several commenters (17316, 17386, 17772) indicate that 40 CFR part 60 subpart Da rule revisions 

exclude startup/shutdown periods from 30-day averaging. Commenters (17715, 19114) state that 

excluding startup/shutdown periods from emission limits would follow precedent in numerous 

rulemakings.

Response to Comment 37: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits so this comment is moot. These work practice standards 

take into account operation of APCDs. See the preamble for discussion. 

iv. Other.

Comment 38: Commenter 17675 states there should be allowances for alternative compliance limits or 

alternative monitoring for startup/shutdown periods, especially for acid gas and SO2, when APCD are 

being brought online (or kept online during shutdown). Commenter 17675 recommends that section 

63.9991(a)(1)(iii) be modified to allow a short, 8 to 12 hour, startup.
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Commenter 17761 suggests, in conjunction with a longer emissions averaging period, that the EPA 

impose a work practice relative to a time limitation on what constitutes a startup or shutdown (e.g., 20 

hours for startup, etc.), and to the extent that the startup exceeds the defined time, the facility would 

either have to abandon its startup efforts, justify a claim of malfunction, or utilize such emissions during 

that extended period in the emission averaging calculation to demonstrate compliance.

Response to Comment 38: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These work practice standards take into account operation 

of APCDs. See the preamble for discussion.

p. Weighting startup/shutdown.

Comment 39: Several commenters suggest that the EPA weight the startup/shutdown emissions based 

on heat input. Commenter 17775 suggests weighting startup and shutdown values by heat input would 

be a more effective way of normalizing the impact of such events, and is consistent with the rationale 

the EPA provided in the proposed revision to 40 CFR part 60, subpart Da. Commenter 15678 states that 

fuel specific CO2 concentration should be used for calculating emissions in lb/MMBtu during 

startup/shutdown periods.

Commenter 17886 states that the 30-day average should be a heat input average, so that emission rates 

for low fuel burn and heat input are appropriately weighted with higher fuel burn and heat input.

Commenter 17772 recommends weighting the hourly values by flow rate. Commenter 17772 indicates 

that low flow rates (flue gas) for startup should not carry the same weight as high flow rates for normal 

operation. Commenter 17772 states that if there are short-term high emissions during shutdown, the 

emission rate on subsequent days when the unit is not operating (and the emissions are zero, but are not 

recorded because they are not measured during a “boiler operating day”) will remain elevated, creating 

additional days of apparent non-compliance.

Commenter 17820 suggests weighting the startup/shutdown emissions by adding the mass emissions for 

each hour (lb/hr) for a total mass (lb) for the 30-day periods and dividing by the sum for each hour of the 

heat input (mmBtu/hr) for a total heat input (mmBtu) for the 30-day period, resulting in a lb/mmBTU 

30-day average that more accurately accounts for startup/shutdown with less impact for 

startup/shutdown events.

Response to Comment 39: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion.

2. Separate standards/work practice standards for SSM.

a. Support separate standards.

Comment 40: Several commenters (17730, 17886, 19120) state the EPA must establish emission 

standards for startup/shutdown periods. Commenter 17740 states that if the EPA does not establish a 12-

month rolling average, the EPA should establish work practice standards for startup/shutdown periods. 

Several commenters (17730, 17737, 17930) state the EPA must establish separate emission standards for 

startup/shutdown periods, or must extend the averaging time. Commenter 17677 states the EPA should 

consider removing startup/shutdown data from the continuous compliance demonstration data, or allow 
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manufacturer’s/site best work practices. Commenter 19122 recommends higher alternative PM limits or 

a work practice standard.

Numerous commenters (16849, 17383, 17402, 17627, 17638, 17677, 17689, 17712, 17715, 17716, 

17720, 17722, 17724, 17725, 17728, 17729, 17730, 17736, 17737, 17740, 17756, 17758, 17772, 17774, 

17775, 17795, 17808, 17813, 17815, 17820, 17821, 17870, 17876, 17877, 17878, 17885, 17886, 17902, 

17904, 17909, 17925, 17928, 17930, 18025, 18037, 18428, 18429, 18498, 18539, 19032, 19114, 19122, 

18023) recommend work practice standards during periods of SS(M). Many commenters (17402, 17627, 

17638, 17715, 17716, 17720, 17725, 17736, 17737, 17740, 17756, 17758, 17774, 17775, 17795, 17808, 

17815, 17816, 17820, 17856, 17870, 17878, 17886, 17902, 17904, 17925, 17928, 17930, 18014, 18025, 

18037, 18428, 18429, 18498, 18539, 18023) note that work practice standards are required in the Boiler 

MACT rule; Multiple commenters (17383, 17689, 17712, 17724, 17740, 17757, 17758, 17774, 17813, 

17876, 17885, 17909, 19032) state that previous (HAP) rulemakings required work practices for 

startup/shutdown events. Commenters 17627 and 17816 state that the EPA determined in Boiler MACT 

rule that MACT emissions limits do not apply to startup/shutdown. Commenter 17740 states the same 

reasons that the EPA established work practice standards for startup/shutdown periods in Boiler MACT 

apply here for EGUs, and the EPA offers unsupported assumptions as its only grounds for continuous 

compliance with emission standards. Commenter 17758 notes the EPA provides no explanation or 

justification why utility boilers are subject to more rigorous numeric standards. Commenters 17627 and

18037 note the EPA provides no compelling reason why MACT emission limits apply to EGU boilers 

during startup/shutdown but not to other boilers and industrial furnaces. Commenter 17776 states the 

EPA provides no reason for the different approach. Commenters (17878, 18428) state the EGU and 

Boiler source categories are similar. Commenter 17930 states that work practice standards are more 

appropriate for startup/shutdown.

Commenter 17623 states the EPA should propose a work practice standard during SSM periods 

because: emission standards are not practicable; data collected during SSM periods are from CEMS but 

do not include all pollutants regulated, particularly Hg from certain kinds of CEMS; and emission 

standards are not economically practicable because collecting SSM period data would involve 

significantly altering measurement techniques and may require manual monitoring.

Response to Comment 40: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action See 

also responses below that address the issue of determining compliance during malfunction events.

b. Sierra Club Decision.

Comment 41: Multiple commenters (16849, 17402, 17691, 17732, 17736, 17740, 17758, 17761, 17774, 

17775, 17807, 17808, 17815, 17851, 17904, 17930, 19536/19537/19538) cite the Sierra Club court 

decision that vacated SSM exemptions. Multiple commenters (17383, 17689, 17712, 17724, 17813, 

17876, 17885) agree that court decisions indicate that HAP regulation must account for 

startup/shutdown events.

Several commenters (17732, 17775, 17904, 17930) state that section 112 only requires that some section 

112 compliant standard apply at all times. Several commenters (17732, 17775, 17930) state that section 

112 does not require that one standard apply to all periods. Commenter 17772 states that the court case 

clarified that providing continuous emission reduction did not mean that a single standard for all periods 
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was required. Commenter 17930 does not support the Sierra Club decision, and states that it is clear that 

the decision does not require one uniform standard at all times.

Commenter 17758 points out that the discussion of CAA section 112(h) in the Sierra Club decision and 

the decision itself do not constrain the EPA’s ability to choose work practice standards in lieu of 

numeric standards. Commenter 17736 states that Sierra Club decision should not be treated as 

authoritative or supportive of the EPA’s action in this rulemaking, as Sierra Club only bars the EPA 

from providing units with a blanket exemption, and the court did not hold that SSM periods must be 

included in MACT standards.

Commenter 17761 states the SSM Exemption court case does not dictate the onerous and potentially 

unachievable result set forth in the rule. Commenter 17904 states that the EPA has gone well beyond the 

Sierra Club decision by not only providing no exclusions, but also failing to offer alternative provisions 

addressing excess emissions during startup/shutdown. Commenter 17904 states that the EPA does not 

explain why these periods cannot have alternative standards.

Commenter 18539 states that applying a different standard during SSM is consistent with section 

112. Commenter 18539 states that the court has held that emissions standards could be different for 

SSM and that work practice standards were permissible. Commenter 19121 states that CAA does not 

allow exemptions for SSM.

Commenter 17758 states that EPA cited to Sierra Club v. EPA (551 F.3d 1019) in both the boiler MACT

and the EGU MACT and came to disparate conclusions that continuously applicable numeric standards 

are required at all times. According to the commenter, the court did not find that numeric emission limits 

under section 112(d) were required during SS periods. The commenter states that work practice 

standards under section 112(h) would satisfy the requirements of Sierra Club and EPA can choose to use 

work practice standard in lieu of numerical standards.

Response to Comment 41: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. As 

explained in those preambles, the EPA has determined that CAA section 112 does not require that 

emissions that occur during periods of malfunction be factored into development of CAA section 112 

standards. As the EPA further explained, accounting for malfunctions would be difficult, if not 

impossible, given the myriad different types of malfunctions that can occur across all sources in the 

category and given the difficulties associated with predicting or accounting for the frequency, degree, 

and duration of various malfunctions that might occur. Setting work practice standards under section 

112 presents the same issues as setting numerical emission limits given the varied nature of 

malfunctions.

c. CAA section 112(h).

Comment 42: Multiple commenters (17716, 17730, 17736, 17740, 17758, 17774, 17775, 17815, 17904, 

18429, 18023) cite section 112(h) and state that section 112(h) allows work practice standards. Several 

commenters (17740, 17774, 17775, 17815, 17904, 18023) note that emissions cannot be measured 

during SSM, that it is not feasible to prescribe or enforce an emission standard, and refer to the 112(h) 

CAA definition of the phrase “not feasible to prescribe or enforce” which includes any situation in 

which the Administrator determines that the application of a measurement methodology to a particular 

class of sources is not practicable due to technological and economic limitations. Commenters (17716, 
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17720, 18023) state the EPA must provide a separate work practice standard for SSM because it is not 

technically feasible to complete stack testing (and monitoring, 17720) during these periods.

Multiple commenters (17402, 17716, 17725, 17736, 17740, 17758, 17820, 17870, 17904, 17925, 18014, 

18025, 18498, 18539, 18023) also point out that the EPA found in Boiler MACT that it is not 

technically feasible to complete stack testing or monitor during startup and shutdown. Multiple 

commenters (17402, 17716, 17725, 17740, 17904, 18037, 18539, 18023) state the same measurement 

problems (and technological difficulties, 17740) exist for EGUs. Commenters 17740 and 17758 note 

that Boiler MACT units and EGUs are substantially similar, and commenter 17740 states that the EPA 

has recognized previously that ICI boilers and EGUs are virtually identical. Commenter 17740 notes 

that the EPA attributes differences between ICI boilers and EGUs to size of units, boiler/furnace 

technology, and portion of electrical output for sale, but none of these differences allow EGUs to 

complete testing requirements during startup/shutdown periods. Commenter 17758 states that EGUs 

have the same issues as ICI boilers with respect to emission testing.

Commenter 18037 states it is not feasible to obtain sufficient data for startup/shutdown. Commenters 

17725 and 17904 state that no technical feasibility for stack testing and monitoring leaves the EPA and 

the regulated community without a practical way to accurately determine emissions during 

startup/shutdown. Commenter 18023 has evaluated stack testing times and relays that total PM testing 

would require 8 to 10 hours and metal HAP and acid gas testing would require minimum of 16 hours. 

Several commenters (17725, 17820, 18014, 18498) state it is uncertain whether representative 

measurements could be obtained during startup/shutdown due to dynamic flue gas conditions and 

technical limitations with measurement technology. Commenter 18023 states that startups are transient 

periods where heat input, fuels, and gas flows continually change, and stack testing is impossible due to 

load fluctuations. Commenter 17851 states that testing during transient conditions is 

difficult. Commenter 17851 states that running EPA Reference Method 5 during startup would require 6 

to 8 hours to complete a single test, but the conditions would have changed so significantly it would be 

impossible to understand what the data meant or extrapolate the data. Commenter 17851 notes the same 

is true for CEMS data during startup.

Response to Comment 42: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. As 

explained in those preambles, the EPA has determined that CAA section 112 does not require that 

emissions that occur during periods of malfunction be factored into development of CAA section 112 

standards. As the EPA further explained, accounting for malfunctions would be difficult, if not 

impossible, given the myriad different types of malfunctions that can occur across all sources in the 

category and given the difficulties associated with predicting or accounting for the frequency, degree, 

and duration of various malfunctions that might occur. Setting work practice standards under section 

112 presents the same issues as setting numerical emission limits given the varied nature of 

malfunctions. See also responses below that address the issue of determining compliance during 

malfunction events.

d. Performance testing and measurement issues.

Comment 43: Commenter 18034 opposes any requirements to require stack testing during 

startup/shutdown. Commenter 18034 states that requiring stack testing during potentially dangerous 

plant operations that could place testing personnel at risk is inappropriate.
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Commenter 17815 states that during startup/shutdown, the EGU exit gas temperature and flow rate are 

not at steady state, and it is impossible to collect condensable and filterable PM samples. Commenter 

17815 states it is not reasonable to establish filterable PM as a surrogate with no reasonable ability to 

measure. Commenter 17737 states there are significant challenges in collecting accurate emissions data 

during startup (commenter cites UARG comments).

Commenter 17912 states that the EPA incorrectly assumed that measuring and monitoring equipment 

will function properly under these conditions. Commenter 17912 states that the infeasibility of obtaining 

valid stack tests under SSM means there is no way to provide assurance that a unit could achieve the 

limits.

Commenter 18021 states that the EPA must account for SSM in the test protocols that influence 

compliance.

Commenter 17736 states control device operating characteristics during full load testing is not 

representative of the range of operating characteristics that a unit may experience on any given day.

Commenters 17725 and 17904 state that monitoring equipment cannot operate accurately during SSM 

periods due to transient flow and flue gas conditions. Commenter 17725 states that since monitoring 

data for SSM periods are not representative of normal operations and are of suspect quality, the EPA 

should adopt an approach where they would not be included in data averages used to determine 

compliance and missing data substitution procedures. Commenter 17725 recommends that the EPA 

provide clarity in the rule for how such periods would be treated.

Response to Comment 43: CEMS data during startup and shutdown will not be used for purposes of 

calculating 30-day averages under the final rule. For periods of startup and shutdown, the EPA is 

finalizing work practice standards instead of numeric emission limits and thus commenters concerns 

related to monitoring during such periods is moot. See the preamble for discussion. 

For malfunction periods, the EPA does not agree with the commenters that CEMS will not provide data 

during malfunction periods (unless the malfunction is related to the CEMS) and commenters provide no 

support for their assertion that data cannot be obtained. To the extent an EGU owner or operator has not 

installed CEMS or believes a CEMS reading during a malfunction event is in error (i.e., shows noncompliance) over the averaging period the EGU owner or operator may use other available means 

(including engineering judgment) or information to demonstrate that the source complied with the 

standard.

e. Suggestions for work practice requirements.

Comment 44: Multiple commenters (17677, 17714, 17725, 17808, 17870, 17902, 17925, 17928, 

18025) suggest that work practices should include or be based on manufacturer recommended practices. 

Several commenters (17725, 17870, 18025) recommend that, as in Boiler MACT, the EPA require units 

to follow manufacturer’s specifications for minimizing emissions during startup/shutdown (as in 40 CFR 

part 63.7530(h)). Commenter 18025 also suggests that rather than referring to “manufacturer’s 

recommended procedures”, the EPA could refer to standard industry procedures to account for instances 

where more than one manufacturer has supplied different components. Commenter 17772 suggests the 

work practice standard take into account the boiler configuration, boiler type, and safe operation of the 

unit. Several commenters (17725, 17774, 19032) state the work practice standard should account for 
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boiler type and control equipment. Commenter 17816 states that work practices should be specific to a 

unit’s boiler type, operational characteristics, and APCDs.

Commenter 17774 states that sources should have to address malfunctions as soon as safely practicable. 

Commenter 17774 states facilities have large incentives to address malfunctions that may lead to excess 

emissions since facilities have emission limits under a number of EPA programs.

Commenter 17174 states the EPA should explain the reasoning for not requiring SSM plans. Commenter 

18037 recommends a SSM plan be included in the Title V permit as an appropriate work practice 

standard. Commenter 17691 suggests the EPA should require startup/shutdown plans, for consistency

with the recent Boiler MACT standard, since startup/shutdown events are predictable and routine.

Response to Comment 44: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. The 

EPA is setting standards that apply at all times, including periods of startup and shutdown and periods of 

malfunction. With such standards in place, sources have ample incentive to plan for and achieve 

compliance during startup and shutdown and during malfunctions, so there is no longer any reason to 

require sources to develop SSM plans

f. Operating parameters for APCD.

Comment 45: Several commenters (17820, 17821, 17868) state that work practices should be 

established in lieu of operating parameters for APCDs. Commenters 17821 and 17868 state that the EPA 

has no basis to expect that operating parameter limits established during performance tests will be 

achievable during SSM. Commenter 17821 states that the EPA established enforceable operating 

parameters in Boiler MACT but made it clear that those limits do not apply during SSM. Commenter 

17820 states that operating limits for operating parameters for APCD should not apply during 

startup/shutdown. Commenters 17820 and 17868 state that the EPA requires sources to establish control 

device operating parameter levels that are dependent upon load during periods of “maximum normal 

operating load,” or other frequently used loads, and then maintain those levels during other periods, 

including startup and shutdown.

Several commenters (17820, 17821, 17868) state that the EPA assumptions regarding startup/shutdown 

are not applicable to APCD operating parameter limits, which are based on 12-hr averages established 

during the performance test (maximum normal operating load) and not based on startup/shutdown.

Commenter 17820 states that startups on large units take longer than 12 hours, so there is no allowance 

for periods of startup/shutdown in the parameter operating limit.

Response to Comment 45: The final rule does not provide for operating parameter limits for air 

pollution control devices. Please see the final preamble and responses to comments under Comment 

Code 5A05. For periods of startup and shutdown, the EPA is finalizing work practice standards instead 

of numeric emission limits. See the preamble for discussion. The EPA’s rationale for its approach to 

malfunctions is discussed in the preambles to the proposed rule and this final action. 

3. Other averaging periods.

a. General.
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Comment 46: Commenter 17774 recommends a longer compliance period to provide flexibility and 

accommodate SSM events. Commenter 16849 suggests a longer averaging period, as an alternative to 

not including SSM hours in the 30-day average. Commenters (17737, 17740, 17795, 17904, 17930, 

19122) recommend the EPA establish a 12-month rolling average or annual average. Commenter 17772 

recommends moving to a 90-day or longer boiler operating day average.

Commenter 17730 states the EPA must establish separate emission standards for startup/shutdown 

periods, or must extend the averaging time.

Commenter 17737 states that if the EPA does not establish a work practice standard, then the EPA 

should use a 12-month rolling average (17737, 19032), or modify the 30-day rolling average by

establishing a minimum number of hours to qualify as a boiler operating day and averaging all hours 

within the 30 boiler operating days (17737).

Commenter 17930 states that if a work practice is not implemented, the EPA should extend the 

averaging period to annual averaging and increase the emissions limit for all pollutants to better account 

for SSM emissions.

Commenter 17740 states that because the EPA is including emissions from non-steady state operations, 

including SSM and load following operations, the averaging period should be lengthened to a 12-month 

rolling average, calculated monthly. Commenter 17740 states that especially for single units that cannot 

be part of a multi-unit plant’s averaging plan, the averaging period is highly important in dealing with 

these non-steady state events. Commenter 17740 notes that a 12-month rolling average for all HAP 

would achieve environmental protection yet provide needed operational flexibility and accommodate 

real-world operating conditions. Commenter 17795 states that a 12-month averaging period would 

ensure operational flexibility, allowing economic consideration to be part of dispatching and operating 

decisions.

Commenter 17795 states that there is no logical reason for providing more flexibility for facilities 

averaging multiple units than for facilities with a single unit or common stack.

Commenter 17761 states the EPA should extend the averaging period to account for routine and 

required maintenance, such as the required shutdown and startup required to inspect burners under this 

rule. Commenter 17761 states that the burner inspection outage time alone, along with required 

adjustments or repairs, could cause a facility to exceed the 30 boiler operating day average emission 

limit, particularly since there is both a shutdown and startup. Commenter 17761 states that to comply, 

facilities will have to take outage both to install controls and to perform assessments required by the 

rule, so that facilities may be forced into a situation that upon startup they are out of compliance.

Commenter 17774 states the EPA should lengthen the averaging period to provide needed flexibility to 

accommodate the range of operating events, including SSM events. Commenter 17761 notes that longer 

averaging periods for all emissions limits (such as an annual or semi-annual average) to fully account for 

the emission variability during these startup and shutdown periods are consistent with the holding in 

Sierra Club as emissions limits would continue to apply to facilities at all times.

Response to Comment 46: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble for discussion. The EPA’s rationale for 

its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. As 

explained in those preambles, the EPA has determined that CAA section 112 does not require that 
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emissions that occur during periods of malfunction be factored into development of CAA section 112 

standards and thus we are not revising the averaging time in the final rule to account for malfunction 

emissions. We believe that the 30 day averaging period provides the appropriate level of flexibility for 

the regulated industry and that longer averaging periods would inappropriately weaken the standards and 

limit our ability to evaluate source compliance on an ongoing basis (see RTI memorandum). In addition, 

the commenters’ expressed concern about including startup and shutdown period in the averaging is no 

longer relevant in light of the inclusion of work practice standards for such periods in the final rule.

b. Kushner letter.

Comment 47: Commenter 17761 states that there is precedent in the Kushner Letter that the agency 

would provide compliance flexibility to sources that implemented appropriate responses (i.e., good faith 

efforts) to SSM events and would provide longer averaging periods (annual or semi-annual) (EPA 

Office of Civil Enforcement Interpretative Letter from Director Adam Kushner, July 22, 2009). 

Commenter 17904 cites the Kushner Letter and requests that the EPA be consistent with the guidance in 

the letter, by averaging over a long period of time, e.g., yearly.

Response to Comment 47: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. For malfunctions, the EPA is finalizing the proposed 

affirmative defense language for exceedances of the numerical emission limits that are caused by 

malfunctions. See the preamble for discussion. 

The Kushner letter did not state that EPA would necessarily provide longer averaging periods in 

promulgating new standards. In assessing the immediate impact of the Sierra Club v. EPA decision, the 

Kushner Letter merely noted that many sources may not have difficulty complying with existing 

standards during periods of SSM even if they lost the SSM exemption because of averaging periods built 

into those rules. 

4. Diluent capping and electrical production.

Comment 48: Commenter 17648 agrees with the options for calculating input-based emissions based 

upon a default diluent value or fuel specific CO2 concentration, or calculating output-based emissions 

using an electrical production rate of 5 percent of rated capacity during startup/shutdown periods.

Commenter 17767 supports use of minimum default values for the diluent and power generation 

numbers for startup/shutdown for parameters monitored by CEMS and by Low Emitting EGU 

methodology.

Commenter 17923 recommends the rule allow for alternative unit specific lb/MWh emission 

calculations, given that the 5 percent of rate capacity value could potentially cause overestimates 

resulting in artificial compliance issues.

Commenter 17821 states the EPA should define the default CO2 value for various fuel types, just as it 

has for O2. Commenter 17821 urges the EPA to define a default CO2 value of 5 percent for coal-fired 

boilers for startup/shutdown, and the EPA should not leave it up to the regulated community as no two 

companies would choose the same value and lead to discrepancies. Commenter 17715 states that diluent 

capping during startup/shutdown periods is appropriate. Commenter 17715 recommends including a 

table in the rule listing the appropriate CO2 diluent values, notes that the O2 diluent value is not 
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appropriate, and recommends use of the diluent cap values already defined in part 72 of 5 percent for 

CO2 and 14 percent for O2 for coal-fired EGUs, which would harmonize the two rules and provide 

adequate margin in the data. Commenter 17821 also supports a value of 5 percent CO2, consistent with 

part 75. Commenter 17715 states the equivalent values for reporting lb/MWe are too low and should be 

changed to 10 percent.

Commenter 17904 states that startup/shutdown emissions cannot be confirmed by standard methods. 

Commenter 17904 states that the EPA recognizes measuring and monitoring during startup/shutdown is 

problematic. Commenter 17904 states that the EPA ignores the fact that there are no appropriate 

methods for accurately determining a representative value for pollutant concentrations. Commenter 

17904 notes that the inclusion of diluent values in a 30-day compliance period would appear to disregard 

both measurement inaccuracies and variability of pollutant concentrations.

Several commenters (19536, 19537, 19538) state that no compliance monitoring is required during 

SSM. The commenters state that the monitoring provisions do not require any testing during periods of 

startup, shutdown, and malfunction and thus provide no means to determine if the standards are met 

during these periods. The commenters state that the default diluent value or the corresponding fuel 

specific CO2 concentration for use in calculating emissions in units of lb/MMBtu or lb/TBtu during 

startup/shutdown periods does not assure continuous compliance during these periods. Commenters state

that because no testing is required during SSM periods, even assuming the diluent requirement would 

address SSM, it would never have to be used as no SSM testing is required.

Comment 49: Commenter 17801 suggests wording changes for the electrical output to be applied 

during startup/shutdown to reflect when electric production actually exceeds 5 percent of the rated 

capacity, so that the default use does not result in an underestimate of power generated and overestimate 

of output-based emissions: For calculating emissions in units of lb/MWh or lb/GWh only during startup 

or shutdown periods, use a nominal electrical production rate of equal to 5 percent of rated capacity until 

the measured electrical production rate exceeds 5 percent of rated capacity.

Several commenters (17740, 17758, 17776) state that the EPA does not address these concerns (that 

there are equipment integrity concerns, technological limitations, economical issues, and safety issues]) 

but accounts for variable conditions by using a default value and specifying electrical production rate; 

by proposing these default values and production rates, the EPA acknowledges that it is not feasible to 

test and monitor emissions from EGUs during startup/shutdown. Commenter 17821 states that use of 

default values (10%) only addresses the limitation of the equations when using CEMS, it does not 

address that the emissions themselves are different during startup/shutdown. Multiple commenters 

(17758, 17776, 17912, 19536, 19537, 19538) state that the EPA does not explain how the default values 

were selected or why they are appropriate and accurate proxies for emissions during SS(M). Commenter 

17925 does not understand how the EPA determined these parameters.

Response to Comments 48 - 49: For periods of startup and shutdown, the EPA is finalizing work 

practice standards instead of numeric emission limits. See the preamble for discussion. The EPA’s 

rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this 

final action. We agree with the commenters that the rule does not require formal performance testing 

during SSM periods. However, as noted above, we believe that it is important to collect data during all 

periods including SSM periods, as the rule requires when conducting any continuous monitoring. 

Sources who install CEMS or other continuous monitoring devices are required to operate the 

monitoring equipment and collect data at all times the process unit is operating and at the intervals 

specified in the rule, except for periods of monitoring system malfunctions, repairs associated with 
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monitoring system malfunctions, required monitoring system quality assurance or quality control 

activities and any scheduled maintenance as defined in the unit’s site-specific monitoring plan. Sources 

who conduct continuous monitoring will have HAP and other emissions data during SSM periods. 

Sources who opt to conduct periodic testing will not have data collected during malfunction periods. A 

source who experiences a malfunction event may use any available information to demonstrate that the 

source complied with the standard notwithstanding the malfunction.

5. Reliability issues.

Comment 50: Commenters 16849 and 18023 state that including SSM periods in the rule will cause 

reliability issues. Commenter 18023 states the ability to startup and shutdown units in a flexible manner 

and bypass controls for short periods are critical to operating a reliable electric system. Commenter 

18023 states the rule does not provide regulatory relief during modes of operation such as SSM that are 

likely to result in higher emission rates, this will prohibit APCD bypass, and units will have to shut 

down if not able to meet MACT rule standard at all times. Commenter 18023 indicates that this will 

cause reliability challenges and will force additional shutdowns and restarts. Commenter 18023 notes 

there are additional reliability challenges for facilities that have multiple units served by a single APCD. 

Maintenance outages are scheduled for planned outages at one or more units; however Commenter 

18023 states that transmission requirements may demand a certain amount of generation from that plant 

that could oblige the remaining units to operate while the control is offline. Commenter 18023 states the 

prohibition of emissions bypass under even these special circumstances could result in transmission 

consequences for areas served.

Commenter 17902 states the need for EGUs to provide uninterrupted reliable power is contrary to 

maintaining operations with frequent malfunction.

Response to Comment 50: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These work practice standards take into account operation 

of APCDs. See the preamble for discussion. Given the inclusion of the work practice for startup and 

shutdown periods, we believe those comments are now resolved as they relate to startup and shutdown 

periods. 

Concerning malfunction, we question the scope of this problem notwithstanding commenters assertions. 

Commenters have not provided information on the scope of this alleged problem or the likelihood that 

sources would have the large number of malfunction events that commenters describe. As stated in 

response to other reliability related comments, we believe we have identified mechanisms to address 

reliability issues associated with implementation of this final rule. 

We address APCD maintenance, bypass stacks, our approach to malfunctions, and reliability issues 

elsewhere in the final rule record.

6. Malfunctions.

a. Support or oppose malfunction approach.

Comment 51: Several commenters (17772, 17807, 17902, 18428) support the malfunction exclusion. 

Commenter 17648 states that the EPA decision not to include malfunctions is reasonable, aligns with 

purpose of section 112, and malfunctions do not reflect normal variability in operating conditions. 

Commenter 17648 states the EPA already accounted for variability for typical operating conditions and 
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it should not make further accommodations for malfunctions. Commenter 17772 also states they would 

support some alternative standard that is based on real data that recognized emissions are higher during 

malfunctions.

Commenter 17774 notes that the EPA’s decision not to differentiate malfunction periods is not based on 

any data. Commenter 17774 notes the EPA’s reference to the precedent that standards that factor in the 

variability of emissions under all operating conditions are reasonable. Commenter 17774 went on to 

state that in this case, it would be both reasonable and appropriate for the EPA to based the MACT 

standard on data that includes malfunctions. Commenter 17774 states that if the EPA chooses not to 

include such malfunction data, it cannot expect sources to comply with general emission limits during 

malfunction periods.

Commenter 17730 states that if malfunctions are included in the compliance calculation, the emission 

standards should be raised to account for the variability or the averaging times should be lengthened to 

account for including malfunction emissions.

Commenter 17767 disagrees with the EPA’s statement that malfunction events are unlikely to lead to 

noncompliance.Commenter 17730 states malfunction events will cause sources to violate the standard. 

Commenter 17775 states that because the EPA does not factor malfunctions (even malfunctions of “best 

performing” sources) into its proposed standards, it is unlikely the standards will be achievable if a 

significant malfunction occurs. Commenter 17775 agrees with the EPA that equipment can and will fail 

unexpectedly, and that some allowance must be made for periods of malfunction. Commenters 17821

and 17877 state that even the best performing units or technology will occasionally fail (and 

malfunction). Commenter 17851 states that even the best operated and maintained facilities will have 

malfunctions. Commenter 17623 states that malfunctions leave the source with uncertainty about 

whether they will be penalized and vulnerable to citizen suits. Commenters (17623, 17821) appreciate 

that the EPA states that not all malfunctions will result in violation; Commenter 17821 states that 

sources are subject to the discretion of the EPA, state, and plaintiffs in citizen suits, and Commenter 

17623 states that regulated sources are still subject to significant EPA and state discretion concerning 

such occurrences and hold the burden of proving an affirmative defense.

Commenters 17623 and 17774 state the EPA should not be able to set a MACT floor that does not 

account for malfunctions because it deems the data infeasible, while at the same time require compliance 

with the strict standard during malfunction periods. Commenters note that just because the EPA is not 

required to account for every conceivable malfunction does not mean it can set standards excluding data 

of any malfunction event.

Commenter 17775 states the application of numerical limits to such malfunctions without a defense to 

penalties clearly would violate the Due Process Clause and the Eighth Amendment prohibition on Cruel 

and Unusual Punishment. Although Commenter 17775 appreciates the EPA’s willingness to exercise 

enforcement discretion and to provide a defense to civil penalties, the EPA’s refusal to take 

malfunctions into account when setting standards is not reasonable.

Several commenters (17808, 17870, 18025) recommend the EPA or states maintain current enforcement 

discretion to address situations when a source fails to comply with a section 112(d) standard as the result 

of a malfunction. On the other hand, Commenter 17402 opposes the EPA’s proposal to use its discretion 

to determine an appropriate response to malfunction events and it opposes EPA’s affirmative defense 

proposal. The commenter has established a state-approved plan that it follows during malfunctions and 

breakdowns. The commenter believes this approach is preferable to EPA’s proposal, in which there is a 
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presumption of non-compliance. The plan incorporated in commenter’s Title V operating permit 

application ensures that future malfunction events will be minimized and that best practices will be 

followed, whereas EPA’s proposed approach is focused on after-the-fact penalty.

Response to Comment 51: The EPA’s rationale for its approach to malfunctions is discussed in the 

preambles to the proposed rule and this final action. As explained in more detail in the preamble, EPA’s 

approach to malfunctions is consistent with CAA section 112 and is a reasonable interpretation of the 

statute. While the EPA recognizes that malfunction events may lead to noncompliance, the EPA 

disagrees with commenter’s statements concerning enforcement discretion. The EPA will consider the 

totality of circumstances of each case in determining whether and to what extent and enforcement 

response is appropriate. The commenter’s suggestion that its state-approved plan is prefereable to the 

EPA’s approach does not explain how an approach based on such a plan meets the requirements of 

section 112.

b. Work practice specific to malfunctions/Sierra Club Decision.

Comment 52: Commenters 17775 and 18023 suggest the EPA work with utilities to develop reasonable 

work practice standards under section 112(h) that take malfunctions into consideration. Commenter 

17623 states the best approach is to require a work practice standard that ensures malfunction problems 

are addressed as soon as safely practicable.

Commenter 17775 states section 112 does not limit the EPA’s standard setting obligation to “distinct 

operating modes.” The commenter notes that as the D.C. Circuit ruled in Sierra Club v. EPA, CAA § 

112 requires that some “section 112-compliant standard” apply at all times (not just during distinct 

operating modes). 551 F.3d 1019, 1027 (D.C. Cir. 2008). The commenter states that if the EPA has 

determined that it is not technologically or economically “feasible” to gather emissions data necessary to 

establish numerical emissions standards that “take malfunctions into account,” the EPA should 

promulgate operational and work practice standards as section 112(h) specifies. To the extent the EPA is 

attempting to distinguish between the “impracticality” of taking malfunctions into account, and the 

“infeasibility” of prescribing and enforcing standards for such events, the commenter states that the 

EPA’s position is difficult to square with the CAA.

Commenter 17775 states that specifying work practice standards for malfunctions is more consistent 

with the CAA, and the D.C. Circuit’s interpretation of it in Sierra Club, than the EPA’s proposed 

affirmative defense. Although the court found that the existing “general duty to minimize emissions”

was not sufficient to qualify as a section 112(d) standard, and that the EPA had “not purported to act 

under section 112(h),” the commenter states that it also made clear that the CAA does not require that 

the same standard apply to all periods. Id. at 1021 (recognizing that “continuous” under CAA § 302(k) 

does not mean “unchanging”), 1028. In short, the commenter states that nothing prohibits the EPA from 

establishing section 112(h) standards for periods that include a malfunction, even if section 112(d) 

standards apply at other times. In fact, the commenter states that establishing section 112(h) standards 

for malfunctions would be more consistent with the Sierra Club ruling than applying clearly 

unachievable standards and allowing a defense to penalties, since an unachievable section 112 standard 

is not “section 112-compliant.” The commenter notes that it also would be more consistent with 

Congressional intent. By allowing work practice and other requirements under section 112(h), the 

commenter states that Congress clearly intended that sources be provided the opportunity to be fully in 

compliance with some standard at all times. The commenter states that nothing in section 112 suggests 

that Congress intended to require a source owner or operator to certify “violation” of a section 112 

standard as a result of an event the source could not reasonably control. The commenter states that the 
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EPA should adhere to that intent and specify reasonable work practice or operational requirements for 

periods of malfunctions.

Response to Comment 52: The EPA’s rationale for its approach to malfunctions is discussed in the 

preambles to the proposed rule and this final action. The EPA’s rationale does not turn on whether 

malfunctions should be viewed as a distinct operating mode. Further, the EPA's rationale for its 

approach to malfunctions is not based on the criteria that must be met to justify a finding that it is not 

feasible to prescribe or enforce an emission standard under section under section 112(h). Section 112 (h) 

(2) provides that such a finding must be based on a determination that “a hazardous air pollutant or 

pollutants cannot be emitted through a conveyance designed and constructed to emit or capture such 

pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any

Federal, State or local law” or “the application of measurement methodology to a particular class of 

sources is not practicable due to technological and economic limitations.” The EPA justification for its 

approach to malfunctions is unrelated to the findings required under section 112(h)(2). Thus,

commenters’ claim that the EPA’s attempt to distinguish between the two “is difficult to square with the 

CAA” is without merit. As explained in the preamble to the proposed rule and this final rule, the EPA 

has determined that CAA section 112 does not require that emissions that occur during periods of 

malfunction be factored into development of CAA section 112 standards. The EPA has further explained 

its view that accounting for malfunctions would be difficult, if not impossible given the myriad different 

types of malfunctions that can occur across all sources in the category. This rationale is not based on the

factors set forth in section 112(h)(2). 

c. Reporting.

Comment 53: Commenter 17775 states that the EPA’s reporting requirements also raise some practical 

issues. Although some malfunctions will occur even at the best performing plants, the commenter states 

not all malfunctions will necessarily result in emissions above a numerical standard. With the longer 

averaging times the EPA has proposed, the commenter states that it is possible that elevated emissions 

from some malfunctions will be sufficiently compensated for during normal operation such that they do 

not result in exceedance of a 30-day rolling average. The commenter indicates that determining before 

the end of a 30-day period whether a malfunction will result in an exceedance of a 30-day rolling 

average may not always be easy. Commenter 17775 states that requiring EGUs to keep logs of 

malfunctions is not unreasonable, however, requiring notice to the EPA of events before the EGU even 

knows whether an exceedance will occur, requiring logs in response to exceedances (rather than 

malfunctions), or requiring that the exceedance occur at the same time as the malfunction, are not 

reasonable. Commenter 17775 suggests that the EPA rework its proposal to recognize that some 

malfunctions that ultimately result in exceedance of an emission limit (particularly those with longer 

averaging times) may occur long before the exceedance is recorded. The commenter notes that the EPA 

should simply require the maintenance of the appropriate records surrounding any event identified by

the EGU as a malfunction and leave the reporting until after all of the data relevant to the compliance 

determination for the affected period are collected.

Commenter 17772 indicates that 40 CFR part 60 subpart Da rule and others exclude malfunction periods 

from 30-day averaging.

Response to Comment 53: The EPA’s rationale for its approach to malfunctions is discussed in the 

preambles to the proposed rule and this final action. See preamble and rule for discussion on related 

reporting requirements.
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The commenters appear to be referring to reporting associated with the assertion of an affirmative 

defense, described in section 63.10001. The EPA agrees that the notice requirement associated with the 

affirmative defense may not be practical when a 30-day averaging period applies. The EPA is revising 

the notification requirement so that it reads “ The owner or operator of the affected source experiencing 

an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone 

or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial 

occurrence of the malfunction or, if it is not possible to determine within two business days whether the 

malfunction caused or contributed to an exceedance, no later than two business days after the owner or 

operator knew or should have known that the malfunction caused or contributed to an exceedance, but, 

in no event later than two business days after the end of the averaging period, if it wishes to avail itself 

of an affirmative defense to civil penalties for that malfunction.”

d. Malfunction definitions.

Comment 54: Commenter 17775 notes that section 63.10005(a) makes a number of references to 

“excess emissions” however, there is no general definition of “excess emissions” in section 63.2. 

Commenter 17775 states that according to section 63.10(c)(7) and (8), “excess emissions” are supposed 

to be defined in the applicable subpart, but proposed subpart UUUUU contains no such definition. 

Commenter 17775 suggests the EPA issue a proposal to define “excess emissions” in the context of any

final rule that uses the term.

Commenter 17736 notes that the definition of “malfunction” is sufficient for the Utility MACT rule.

Response to Comment 54: We disagree with the commenter. In defining the standard, we are in effect 

also defining emissions that are in excess of the standard. We have in this final rule established 

numerical emission standards that must be met on a 30-day rolling average. Emissions in excess of those 

levels over the established averaging period are considered excess emissions.

7. Affirmative defense.

a. Support or oppose AD approach.

Comment 55: Multiple commenters (17623, 17715, 17740, 17807, 17904, 17909, 17912, 18025, 18428, 

19114) support affirmative defense (AD) for malfunctions; commenter 17722 generally supports the AD 

for excess emissions. Multiple commenters (17689, 17724, 17712, 17876, 17877, 17885, 19032) support 

affirmative defense concept but believe the EPA should articulate specific reasonable provisions in the 

rule.

Commenter 17975 states that requiring agencies to evaluate and rebut AD on a case-by-case basis is 

impractical and ineffective. Commenters (17689, 17712, 17877, 17885) state the EPA should not decide 

the appropriateness of individual situation retroactivity on a case-by-case basis based on vague changing 

guidelines. Commenter 17909 states the EPA should provide detailed guidance on how the provisions 

will be applied and rely on case-by-case review. Commenter 17912 notes that the EPA properly 

proposes flexibility for malfunctions. Commenter 17912 supports the EPA finding that it is reasonable 

not to account for malfunctions in emission standards.

Commenter 17902 states that short of excluding malfunctions, they support AD, however, the EPA 

should make it less burdensome. Commenter 17902 recommends the EPA remove items 7 through 9, 

because the information is redundant with items 1 through 6, are unnecessary, are not reasonably 
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documented or quantified, are not expected to provide meaningful insights on how to avoid future 

malfunctions, and make the rule less impractical.

Commenter 17851 supports maintaining a regulatory provision for malfunctions, such as an AD. 

Commenter 17851 notes concerns that the AD implies the facility is guilty until proven innocent. 

Commenter 17851 states concerns that in calling it an AD even before it has been established to be a 

deviation, improperly shifts the burden to the facility. Commenter 17851 suggests the EPA establish a 

rebuttable presumption, rather than AD, where it is presumed the facility did everything in their power 

to minimize emissions, unless the EPA proves certain facts that are enumerated in rules. Commenter 

17851 states the burden of proof would be on the EPA.

Commenter 18500 states that the steps associated with AD are highly prescriptive and infer that the 

failure to meet any step is a willful violation. Commenter 18500 states the standard should be moderated 

to match the risk to the violation, and to recognize that malfunctions are unanticipated failures.

Commenter 17730 states that AD still requires the source to document the event and defend itself to the 

EPA or in a court of law for violation of standard that was unreasonably established. Commenter 17402 

recommends a SSM work practice plan in the Title V permit to minimize future malfunctions and ensure 

best practices are followed, similar to the malfunction and breakdown plan they developed for their title 

V application. Commenter 17902 states that EGUs are already required to minimize emissions during 

SSM under title V operating permit conditions. Commenter 18447 states that the [AD] response to a 

malfunction is heavy-handed and threatening. Commenter 18447 states that facilities are guilty until 

they go to great lengths to prove innocence. Commenter 18447 states that the EPA would do well to 

realize that even well-trained and well-intentioned employees can and do make mistakes.

Commenters 17402 and 17772 oppose the EPA’s AD proposal for malfunctions. Commenter 17772 

states that AD for malfunctions is inappropriate, overly complex, and unduly burdens both industry and 

the EPA. Commenter 17772 states that the EPA has improperly shifted the burden of proof to the 

facility, but the ultimate burden of proof to justify a civil penalty remains with the EPA, and the EPA 

should have to present clear evidence sufficient to persuade a judge or independent fact finder that the

claimed malfunction should be disregarded for reasons such as poor maintenance, careless operation, or 

other preventable conditions. Commenter 17772 states the multi-part process for establishing the 

existence of a malfunction is overly complex and burdensome. Commenter 17772 suggests that any AD 

to be used should be limited to the definition in section 60.41Da. Commenter 17772 notes that the rule 

establishes 12 separate requirements and requires the EGU operator to carry a burden of proof for each 

one to comply; this is arbitrary and capricious. Commenter 17772 states that the 12 requirements are 

vaguely worded and will themselves become a primary focus of litigation; after a malfunction occurs, it 

is almost always possible for someone to allege there was some practice that could have been employed 

to prevent the malfunction.

Commenter 17772 also states their concerns that root cause analysis in section 63.10001(a)(9) will be 

used against the EGU operator, since a potential argument may be made that earlier implementation of 

the recommended correction would have prevented the malfunction. Commenter 17772 states that 

proposed rule section 63.10001(a)(5), for example, states that the accused must prove that “all possible 

steps were taken” to minimize the impact of the excess emissions. The commenter asks whether that 

means that if the EPA or some private litigate can imaginatively identify some step not tried, then the 

affirmative defense is rejected? The commenter goes on to note that if so, no affirmative defense would 

ever be successful -- some untried alternative or additional action could always be found by inventive 

counsel or expert witness. Similarly, commenter 17772 notes that proposed rule section 
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63.10001(a)(i)(2) states that the excess emissions “Could not have been prevented through ... better 

operation and maintenance practices.” The commenter indicates this could be an impossible standard to 

meet if “better” is used to mean better than the practices actually employed by the accused. Commenter 

17772 states that this vague and unworkable standard should, at a minimum, be modified to allow the 

accused to meet whatever burden of presentment or proof is applied by a showing that the operation and 

maintenance practices were consistent with good utility practice.

Commenter 17851 states the requirements in section 63.10001 are impossible to meet due to ambiguous 

terms such as “careful,” “proper,” or “better”, and these terms must be defined in order to determine 

whether the criteria were met. Commenter 17851 states the EPA should drop references to “any” activity

and “all” in this paragraph.

Commenter 17912 states that the AD is restrictive and vague. Commenter 17912 urges the EPA to set 

conditions for AD that a facility can actually achieve rather than setting a virtually insurmountable bar.

Commenter 17736 objects to the EPA’s attempt to restrict the definition of “malfunction” such that the 

concept is eliminated albeit the EPA’s proposed “affirmative defense.” Commenter 17736 notes that 

determining whether no malfunction occurred if it “could have been prevented through careful planning, 

proper design, or better operation and maintenance,” the EPA should explain what “proper design” and 

“better operation” is.

Commenter 17775 cites concerns regarding AD. Commenter 17775 states that section 63.10005(a)(1)(i) 

refers to an “unavoidable” failure, and although the difference between “reasonably preventable” and 

“unavoidable” may seem small, the EPA’s rule seems to require a stronger showing than the definition 

anticipates in that it leaves room to argue whether a failure could have been prevented even if the acts 

necessary to do so were “unreasonable.” Commenter 17775 indicates that other provisions in (a)(1), 

paragraph (ii) (“[c]ould not have been prevented”), (iii) (“could [not] have been foreseen and avoided, or 

planned for”), and (a)(5) (“all possible steps”) - also seem to remove the requirement of 

“reasonableness.” In contrast, the commenter notes that other provisions include references to 

practicability. At a minimum, Commenter 17775 states the EPA must revise its criteria consistent with 

the section 63.2 definition to include the concept of “reasonableness.”

Several commenters (17383, 17712, 17876) state AD for malfunctions should be reasonable and the 

requirements well articulated. With respect to AD for malfunctions, Commenter 18023 requests that the 

EPA reconsider the criteria defining malfunctions to include the concept of “reasonableness” and to 

defer reporting until an exceedance has been recorded.

Commenter 17722 states that for language in section 63.10001(a)(5) “All possible steps were taken...” it 

should be clarified that those steps must be relevant to the excess emissions. The commenter also stated 

the term “possible” is subjective and could be replaced by “all steps needed, based on best professional 

judgment.”

Commenter 17722 states that for language in section 63.10001(a)(9), it should be clarified that written 

root cause analysis should include all forms of documentation, including electronic records.

Commenter 17975 states that neither NSPS nor MACT standards appropriately deal with malfunction. 

Commenter 17975 states that the EPA must determine whether certain emission control technologies are 

less likely to malfunction and cause standards to be exceeded. Commenter 17975 states that if these 
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technologies are available, the EPA should not provide an AD for malfunctions from emissions controls 

that are accident prone.

Several commenters (19536, 19537, 19538) state that the EPA’S AD for malfunctions is unlawful.

Commenters state that the CAA makes clear how the courts are to assess civil penalties, whether a case 

is brought by the EPA or a citizen. 42 U.S.C. § 7413(e). The commenters note that Congress intended 

citizens to be able to enforce emission standards under the CAA using the full range of civil 

enforcement mechanisms available to the government, and, in the HAP context, subject only to the 

limitation that government not be “diligently prosecuting” its own civil enforcement action, CAA § 

304(b)(1)(B), 42 U.S.C. § 7604(b)(1)(B). The commenters state that the EPA’s rule proposal, by shifting 

this careful balance and contravening these mandates, violates the CAA.

Commenters state that the AD that the EPA proposes to allow in case of malfunctions goes directly

against congressional intent in two ways. First, the commenters note that Congress expressed a clear 

intent as to how judges should determine the size of civil penalties whenever they are sought and thus 

Congress flatly barred the EPA from limiting when civil penalties can be assessed. See Chevron, U.S.A., 

Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837, 842-43 (1984). In this proposal, the commenters

note that the EPA acts outside of its delegated authority to limit civil penalties available in citizen suits 

or its own enforcement actions. Second, the commenters state that the proposal will impermissibly chill 

citizen participation, and the ability to win an effective, deterrent remedy, in CAA enforcement actions.

Commenters state that the AD is fatally flawed because the EPA cannot decide when civil penalties will 

not be allowed. The commenters state that the CAA itself spells out the only limits that Congress 

intended to impose on citizens’ ability to seek and recover penalties in enforcement suits under CAA § 

304, 42 U.S.C. § 7604. See 42 U.S.C. § 7413(e). By attempting to impose additional agency-created 

limits, the commenters state that the EPA exceeds its authority. The commenters note that Congressional 

intent on civil penalties is clear-they are a remedy available to citizen plaintiffs, and the CAA gives 

judges a list of factors to consider in assessing them. As such, the commenters state the EPA cannot 

interpret the statute to contravene that intent, and by attempting to rewrite this provision, via regulation, 

the EPA has done just that.

Commenters state that the CAA grants the EPA minimal discretion that only applies to administrative 

penalties, allowing the EPA to “compromise, modify, or remit, with or without conditions, any

administrative penalty which may be imposed under [subsection 113(d)].” 42 U.S.C. § 7413(d)(2)(B). 

However, the commenters state there is no similar grant of authority to the EPA to compromise, modify

or limit civil penalties that a court may impose under section 113(e) or section 304. The commenters

state that section 304(a), 42 U.S.C. § 7604(a), grants courts the sole authority “to apply appropriate civil 

penalties” in citizen suits. The commenters note that the explicit reference to the EPA’s ability to modify

penalties in one subsection and its absence in the other subsection of the same provision can only be 

understood as an intentional decision by Congress that the EPA cannot contravene by rule.

Commenters state that citizen participation in CAA enforcement also will be hampered, in violation of 

citizens’ rights to protect themselves from pollution and in direct conflict with congressional intent. The 

commenters state that the affirmative defense would likely be used on a routine basis by polluters 

seeking to avoid penalties, just as the malfunction exemption was. As a result, the commenters note that 

citizens who seek civil penalties against polluters in order to protect themselves and achieve the CAA’s 

goals may be forced to engage in fact intensive disputes over the cause of emission violations and 

adequacy of responsive measures - an outcome Congress intended to prevent with the simple 

straightforward enforcement and penalty provisions in the CAA. As a result, the commenters note that 
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enforcement of the CAA could suffer, for civil penalties provide a powerful deterrent to violators as 

Congress intended.

Commenters state that the AD also runs counter to two clearly expressed intentions of Congress: (1) the 

burden it places on citizens makes it less likely that they will enforce the CAA, see, e.g., Pennsylvania v. 

Del. Valley Citizens’ Council for Clean Air, 478 U.S. 546, 560 (1986); and (2) several of the factors at 

issue in the AD undercut Congress’s intent that citizen suit enforcement should avoid re-delving into 

“technological or other considerations,” NRDC v. Train, 510 F.2d 692, 700 (D.C. Cir. 1974). The 

commenters state that both result from the technical burden the EPA imposes on citizens with the AD, 

and both render the defense impermissible.

In addition to these problems, commenters state there is simply no need for an AD to penalties to be 

written into the regulations and cause the harm that will result. The commenters note that the EPA has 

discretion to decide what cases to prosecute, to consider settlements, and to request civil penalties in a 

case-by-case manner, as long as it acts consistent with the CAA to protect clean air as its top priority, 

see 42 U.S.C. § 7401. The commenters state that promulgating this affirmative defense is equivalent to 

giving polluters “get out of jail free” cards for serious emission exceedances and MACT violations. The 

commenters note that polluters are likely to claim that any violation of the standard is due to a 

malfunction in order to evade the requirements. The commenters state that allowing polluters to evade 

financial penalties - which are the real teeth of the standards - through this type of measure is likely to 

lead to polluters simply ignoring or factoring potential standard violations into their cost of doing 

business, rather than actually trying to prevent malfunctions and violations of the standards as a way to 

avoid financial losses from the application of penalties.

Commenters state that assuming arguendo that the EPA had authority to promulgate any type of 

affirmative defense to penalties for malfunctions, the EPA should also promulgate the following 

provisions:

1. A specific amount of compensatory damages should apply to each reported malfunction. These funds 

should be dedicated to enforcement, inspections, and monitoring in the local community around the 

specific facility, to create greater assurance that malfunctions will not happen again.

2. The EPA should modify the regulations so that the AD cannot be used by a specific facility or 

company more than once within a set period of time, such as 10 years. The AD should become 

automatically unavailable to a facility that has previously had a malfunction within the last 10 years, to 

ensure that this defense does not swallow the value of the standards.

3. The EPA should promulgate specific public reporting and notification requirements for malfunctions, 

or any emission exceedance that occurs of which an operator is aware. Specifically, the EPA should 

require that when a facility provides the EPA with a notification of a malfunction or emission standard 

exceedance under the regulations, this notice will be made publicly available on the EPA’s website 

within 14 days. In addition, the EPA should promulgate the requirement that when such notification is 

made, the facility must also provide for community notification of the malfunction or emission standard 

exceedance within 2 business days, through an appropriate public forum that is designed to reach 

residents who live near the facility, including but not limited to a notice on the facility’s own website (if 

it has one), a written notice to the local municipality and local school district, a press release to the local 

newspaper, radio, and TV news station that contains information community members may need to 

protect themselves and their families from the additional air pollution.
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Response to Comment 55: For malfunctions, the EPA is finalizing the proposed affirmative defense 

language for exceedances of the numerical emission limits that are caused by malfunctions. As EPA 

explained in the preamble to the proposed rule, EPA recognizes that even equipment that is properly

designed and maintained can fail and that such failure can cause an exceedance of the relevant emission 

standard. The EPA included an affirmative defense in the final rule in an attempt to balance a tension, 

inherent in many types of air regulation, to ensure adequate compliance while simultaneously

recognizing that despite the most diligent of efforts, emission limits may be exceeded under 

circumstances beyond the control of the source. The EPA must establish emission standards that “limit 

the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. § 

7602(k)(defining “emission limitation and emission standard”). See generally Sierra Club v. EPA, 551 

F.3d 1019, 1021 (D.C. Cir. 2008) (emissions limitations under CAA section 112 must both continuously

apply and meet section 112’s minimum stringency requirements, even during periods of startup, 

shutdown and malfunction). Thus, EPA is required to ensure that section 112 emissions limitations are 

continuous. The affirmative defense for malfunction events meets this requirement by ensuring that even 

where there is a malfunction, the emission limitation is still enforceable through injunctive relief. While 

“continuous” limitations, on the one hand, are required, there is also caselaw indicating that in many 

situations it is appropriate for EPA to account for the practical realities of technology. For example, in 

Essex Chemical v. Ruckelshaus, 486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit acknowledged that 

in setting standards under CAA section 111 “variant provisions” such as provisions allowing for upsets 

during startup, shutdown and equipment malfunction “appear necessary to preserve the reasonableness 

of the standards as a whole and that the record does not support the ‘never to be exceeded’ standard 

currently in force.” See also, Portland Cement Association v. Ruckelshaus, 486 F.2d 375 (D.C.Cir. 

1973). Though intervening caselaw such as Sierra Club v. EPA and the CAA 1977 amendments 

undermine the relevance of these cases today, they support EPA’s view that a system that incorporates 

some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil 

penalties for excess emissions that are proven to be beyond the control of the source. By incorporating 

an affirmative defense, EPA has formalized its approach to upset events. In a Clean Water Act setting, 

the Ninth Circuit required this type of formalized approach when regulating “upsets beyond the control 

of the permit holder.” Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, 

Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an informal 

approach is adequate). The affirmative defense provisions give the EPA the flexibility to both ensure 

that its emission limitations are “continuous” as required by 42 U.S.C. § 7602(k), and account for 

unplanned upsets and thus support the reasonableness of the standard as a whole.

Further, EPA’s view is that the affirmative defense is consistent with CAA section 113(e) or 304. 

Section 304 gives district courts jurisdiction “to apply appropriate civil penalties.” Section 113(e)(1) 

identifies the factors that the Administrator or a court shall take into consideration in determining the 

amount of a penalty to be assessed, once it has been determined that a penalty is appropriate. The 

affirmative defense regulatory provision is not relevant to the amount of any penalty to be assessed 

under section 113(e). If a court determines that the affirmative defense elements have been established, 

then a penalty is not appropriate and penalty assessment pursuant to the section 113(e)(1) factors does 

not occur. 

In exercising its authority under section 112 to establish emission standards (at a level that meets the 

stringency requirements of section 112), EPA necessarily defines conduct that constitutes a violation. 

The EPA’s view is that the affirmative defense is part of the emission standard and defines two 

categories of violation. If there is a violation of the emission standard and the source demonstrates that 

all the elements of the affirmative defense are met, only injunctive relief is available. All other violations 

of the emission standard are subject to injunctive relief and penalties. The CAA does not require that all 
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violations be treated equally. Further, a citizen suit claim under section 304 allows citizens to commence 

a civil action against any person alleged to be in violation of “an emission standard or limitation under 

this chapter.” The CAA, however, allows EPA to establish such “enforceable emission limitations.” 

Thus, the citizen suit provision clearly contemplates enforcement of the standards that are defined by

EPA. As a result, where EPA defines its emissions limitations and enforcement measures to allow a 

source the opportunity to prove its entitlement to a lesser degree of violation (not subject to penalties) in 

narrow, specified circumstances, as EPA did here, penalties are not “appropriate” under section 304. 

The EPA’s view is that an affirmative defense to civil penalties for exceedances of applicable emission 

standards during periods of malfunction appropriately balances competing concerns. On the one hand, 

citizen enforcers are concerned about additional complications in their enforcement actions. On the other 

hand, industrial sources are concerned about being penalized for violations caused by malfunctions that 

could not have prevented and were otherwise appropriately handled (as reflected in the affirmative 

defense criteria). The EPA has utilized its Section 301(a)(1) authority to issue regulations necessary to 

carry out the Act in a manner that appropriately balances these competing concerns.

The EPA disagrees that the affirmative defense provision will hamper citizen enforcement. First, 

injunctive relief is still available and the threat of penalties would not deter violations in cases where all 

of the conditions of the affirmative defense have been satisfied because the affirmative defense criteria 

ensure that all reasonable steps were taken to prevent a malfunction that causes excess emissions. 

Further, litigating whether a source has met the affirmative defense will not burden citizen group any 

more or less than would litigating the appropriate penalty amount in the penalty assessment stage of a 

citizen suit enforcement action, because the 113(e) penalty assessment criteria and the affirmative 

defense criteria are similar and in fact overlap. For example, the requirement that the Administrator or 

the court consider “good faith efforts to comply” is bound to generate the type of fact-intensive disputes 

that the commenter complains of. In addition, several of the affirmative defense criteria are exactly the 

type of criteria the Administrator or Court might consider in determining whether a source made “good 

faith efforts to comply.” For example, to take advantage of the affirmative defense, the source must 

prove by a preponderance of the evidence that, among other things, the excess emissions “were caused 

by an unavoidable failure of air pollution control and monitoring equipment, process equipment, or a 

process to operate in a normal or usual manner” and “could not have been prevented through careful 

planning, proper design or better operation and maintenance practices” and “did not stem from any 

activity or event that could have been foreseen and avoided, or planned for.”

Thus, the EPA does not expect the affirmative defense provision to significantly alter the burden of 

bringing a citizen enforcement action. For those cases that do proceed to trial, even in the absence of this 

affirmative defense, sources generally raise equitable arguments to argue for a low penalty and citizens 

often rebut such arguments. Therefore, as a practical matter, the EPA does not expect the affirmative 

defense provision to materially affect the practice of CAA enforcement.

Additionally, the affirmative defense is reasonable. The EPA’s judgment is that the affirmative defense 

criteria capture the appropriate considerations in determining whether penalties are appropriate when a 

violation occurs as the result of a malfunction. As noted above, the affirmative defense criteria overlap 

to some extent with the penalty assessment criteria set forth in section 113(e), but are not identical. For 

example, size of business is one of the factors listed in section 113(e), but is not reflected in EPA’s 

affirmative defense. This reflects the EPA’s view that when a violation is caused by a malfunction, the 

size of the business is not relevant to whether penalties should be excused. If the violation was 

unavoidable and could not have been prevented, the EPA’s view is that it would be unfair to impose a 

penalty no matter the size of the business. 
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The EPA is not adopting commenters’ suggestion with respect to compensatory damages or limits on the 

frequency of use of the affirmative defense. It is not clear that EPA has authority to require the 

automatic imposition of compensatory damages and even if such authority exists, the EPA does not 

think automatic imposition of damages is appropriate. Ensuring that malfunctions do not recur can be 

handled through imposition of appropriate injunctive relief. In addition, the EPA’s view is that it would 

not be appropriate to limit a source’s ability to take advantage of the affirmative defense to one time 

over a specified period of time such as ten years given that the affirmative defense is only available 

when the source could not have prevented the excess emissions. With respect to commenters’ suggested 

reporting requirements, the reporting requirements in the rules promulgated today already require 

malfunction reporting and the affirmative defense provisions require that parties choosing to assert the 

affirmative defense meet additional malfunction reporting requirements. Any such reports submitted to 

the EPA are publicly available pursuant to CAA section 114.

Further, the EPA believes that courts are well equipped and often do evaluate and apply the type of 

criteria set forth is the affirmative defense. Many of the conditions were modeled after the conditions of 

the affirmative defense in EPA’s SIP SSM policy, which several states have adopted into their SIPs. 

(See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, 

Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, 

Maintenance, and Malfunctions (Feb. 15, 1983)). We do not have any indication that parties to 

enforcement proceedings have had any significant difficulties applying the terms of these SIP 

affirmative defenses. In addition, EPA’s view is that use of consistent terms in establishing affirmative 

defense regulations and policies across various CAA programs will promote consistent implementation 

of those rules and policies. The affirmative defense does not require a facility to prove its innocence 

rather than requiring an enforcement authority to prove a violation of the CAA or change the burden of 

proof with respect to establishing a violation. The affirmative defense applies to penalties and thus is 

only utilized where a violation has been established. The burden of proof remains with the plaintiff in an 

enforcement action. See, e.g., 40 C.F.R. 22.24. If a violation has been established and a source wishes to 

assert the affirmative defense with respect to penalties, the source does bear the burden of establishing 

that the elements of the affirmative defense have been met. This burden-shifting is appropriate because 

the source is in a better position to determine the facts required to establish the defense. See, e.g., 

Arizona Pub. Serv. Co. v. EPA, 562 F.3d 1116, 1120, 1129-30 (10th Cir. 2009) (rejecting industry

challenge to EPA’s use of an affirmative defense to address excess emissions during malfunction 

events.). With respect to the comment that the affirmative defense should be stated instead in terms that, 

once a source has claimed that its excess emissions were related to a malfunction, it will not be 

considered to be in violation of the standards unless the enforcement authority demonstrates that the 

source is not entitled to claim the malfunction, EPA’s does not agree that the affirmative defense should 

operate as the commenter suggests. The commenter improperly seeks to shift the burden of proof from

the source to EPA. It is the source, not EPA, that has the information relevant to assess whether a 

particular event qualifies as a malfunction and meets the affirmative defense. Furthermore, commenter’s 

suggested approach appears to be similar to the scheme that the court vacated in the Sierra Club case, in 

that there would be no violation unless the enforcing party (EPA or a citizen), established that the event 

in question was not a malfunction. The EPA also disagrees with the comments suggesting that the 

affirmative defense provisions should be specified as work practice standards. As is explained elsewhere 

is the response to comment document, EPA is not taking malfunctions into account in setting section 

112 standards. 

b. AD for startup/shutdown.
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Comment 56: Commenters 17904 and 19120 request AD for excess emissions during startup/shutdown 

periods, similar to the AD provided for malfunctions. Commenter 17904 cites the NSPS (approved FIP 

for a station) where opacity standards apply at all times except during SSM (40 CFR 60.11), and AD 

applies to SSM. Commenter 17904 notes that unlike an exclusion, an AD does not excuse a source from 

continuous compliance. Commenter 17904 states that nothing in the Sierra Club decision precludes the 

EPA from including an AD for excess emissions during startup/shutdown.

Response to Comment 56:. The EPA is promulgating the affirmative defense for malfunctions only, 

not for periods of startup and shutdown. As explained in the preamble, the EPA believes that 

malfunction events should be treated differently than periods of startup and shutdown, which are 

predictable and routine aspects of a source’s operations. In contrast, the EPA has determined that CAA 

section 112 does not require that emissions that occur during malfunctions be factored into development 

of CAA section 112 standards. Because startup and shutdown periods are part of a source’s normal 

operations, the same approach to compliance with, and enforcement of, applicable emissions standards 

during those periods should apply as otherwise applies during a source’s operations. Further, as 

explained above, periods of startup and shutdown – but not malfunctions -- are taken into account when 

establishing section 112 emissions standards. For these reasons, the EPA does not believe it is 

appropriate to apply the affirmative defense provision to startup and shutdown periods.

c. Reporting timeline.

Comment 57: Commenter 17912 states section 63.10001 requires notification as soon as possible but 

no later than 2 business days, but the rule text does not allow for circumstances where the facility does 

not have knowledge of the malfunction until later. Commenter 179212 states that a source must provide 

a preponderance of the evidence that it has met all of the elements set forth in 63.10001 but in many 

cases the best a facility can practically do is prepare a best estimate.

Commenter 17772 states that the 2-day statute of limitations on AD is an arbitrarily short deadline and 

should be struck in its entirety. Commenter 17772 states that the accused should retain its right to defend 

itself against a notice of violation (NOV) and relevant evidence of a malfunction should not be ignored 

due to a procedural rule. Commenter 17772 cites an example where emissions are measured by a sorbent 

trap and the malfunction may not be found until the trap is removed and analyzed.

Commenter 17772 states that for short-term malfunctions, it may not be known until the end of the 30-

day period that there has been a violation, and a better approach would be to permit the claim to be made 

as soon as there is knowledge of the malfunction but no later than 45-days following the event.

Response to Comment 57: The EPA is revising the notification requirement so that it reads “ The owner 

or operator of the affected source experiencing an exceedance of its emission limit(s) during a 

malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as 

possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not 

possible to determine within two business days whether the malfunction caused or contributed to an 

exceedance, no later than two business days after the owner or operator knew or should have known that 

the malfunction caused or contributed to an exceedance, but, in no event later than two business days 

after the end of the averaging period, if it wishes to avail itself of an affirmative defense to civil 

penalties for that malfunction.”

d. Reporting method.
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Comment 58: Commenter 17722 states that language in section 63.10001(b) should include “or 

delegated authority, as applicable” in addition to “notify the EPA Administrator...” and should replace 

“by phone or facsimile...” with “in an appropriate manner such as phone, fax, email, or other electronic 

means, as determined by the EPA Administrator or delegated authority.”

Commenter 18034 states that electronic reporting, such as complies with CROMERR standards, should 

be allowed for the initial notifications, rather than telephone notifications, which should not be allowed, 

because telephone notifications are difficult to verify and enforce. Commenter 18034 states that 

electronic notification provides quick and durable reporting that may be relied on for investigative and 

enforcement purposes.

Commenter 18034 suggests that the EPA allow state rules for AD that are EPA-approved as part of a 

SIP, to be used in lieu of the federal procedures, to eliminate duplicative or conflicting requirements for 

both state agencies and regulated entities. Commenter 18034 states that TAC includes reporting of 

upsets (malfunctions), startups, and shutdowns, that are substantially the same as the EPA’s rule. 

Commenter 18034 requests that as part of the alternative EPA-approved SIP procedures, consideration 

may be given to Texas criteria regarding the percentage of total annual operating hours for emission 

events in lieu of frequency.

Response to Comment 58: The definitions in part 63.2 Part 63 defines “Administrator” to mean the 

Administrator or authorized representative (e.g. delegated state). The EPA accepts documents in 

electronic format, as long as the format is compatible with the requirements of the standards. For the 

affirmative defense provisions, the owner or operator of a facility experiencing an exceedance of its 

emission limit(s) during a malfunction must notify the Administrator by telephone or facsimile (FAX) 

transmission of the exceedance. However, the written reports required to demonstrate that the 

affirmative defense provisions have been met and requests for an extension of the deadline for these 

reports may be submitted electronically. 

Pursuant to EPA regulations at 40 CFR 63.93, states may seek approval of state requirements to 

substitute for requirements included in final section 112 standards if the state requirements are 

equivalent to the promulgated section 112 standards. States that have SIP approved affirmative defense 

provisions may seek to have those programs apply in lieu of the affirmative defense provisions 

applicable to malfunction periods in the final rule. 

e. Not require Root Cause Analysis for every malfunction.

Comment 59: Commenter 17923 states that documentation required to assert an AD will impose 

administrative burden with no environmental benefit. Commenter 17923 states that a facility should not 

be required to conduct a root cause analysis (RCA) for every malfunction for AD. Commenter 17923 

states that the ambiguity of the recordkeeping requirements limits confidence in a facility’s ability to 

demonstrate compliance.

Commenter 17851 notes that the rule language assumes that all malfunctions are equally significant and 

need an identical degree of investigation. Commenter 17851 notes that a RCA implies a formal process, 

and believes a formal RCA should be used only when other reasonable methods fail to show what 

caused the malfunction or when the serious nature of an event might make such an analysis necessary. 

Commenter 17851 believes a RCA for every malfunction is unnecessary and requires excess efforts with 

no environmental gain. Commenter 17851 states that other tools may be more appropriate (e.g., failure 

mode and effect, fault tree, etc.) or more powerful tools may be introduced in the future, and the facility
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should decide which tool to use. Commenter 17851 suggests the EPA use an alternative term that does 

not carry a specific meaning.

Commenter 19040 states that RCA is just one of many types of inductive analyses, and other inductive 

techniques should be considered appropriate are the “parts count” approach, FEMA, FMECA, PHA, 

FHA, DFM, or RDB. Commenter 19040 also suggests that deductive methods of analysis, such as fault 

tree analysis, would be appropriate. Commenter 19040 suggests that the EPA not limit the analysis 

technique, the EPA should allow the entity to use the technique that will give the most appropriate 

results or conclusions. Commenter 19040 states it is in the interest of the EPA to obtain the most 

meaningful results or conclusions on malfunction causes, not to have facilities develop proficiency in 

conducting RCA and not identify the malfunction cause.

Response to Comment 59: The EPA believes that a minor administrative burden will result in sources 

analyzing their violative emissions to reduce or avoid those emissions in the future, which is an 

environmental benefit. A root cause analysis is only required if a source seeks to assert an affirmative 

defense. However, such an analysis is beneficial in resolving or preventing violations and excess 

emissions whether the source seeks to assert the affirmative defense or not. A root cause analysis is one 

example of what constitutes good air pollution control practices to minimize emissions.

A root cause analysis is not required for every malfunction - - only those malfunctions for which the 

source chooses to assert an affirmative defense. We agree with the commenter that not every

malfunction is so significant that it would require asserting an affirmative defense. The EPA believes 

that sources seeking to minimize emissions will endeavor to find out what went wrong anytime there is a 

minor or major malfunction. The facility should decide what level of investigation is needed in each 

instance. We agree with the commenter that sources should use appropriate techniques of analysis to 

achieve the desired results and conclusions in the event of a malfunction. The EPA joins the commenter 

in seeking meaningful results which successfully identify, and address the cause of the malfunction. 

However, if the malfunction rises to the level of one that the source seeks to avail themselves of the 

affirmative defense, then a root cause analysis is required.

In the context of part 63 section 112, the term “root cause analysis” was used generically to imply an 

analysis of sufficient depth and complexity to indicate whether a malfunction did indeed cause a failure 

to meet a standard, provide sufficient information on the nature and causes of a malfunction to 

determine whether the source had a malfunction that met the definition of a malfunction, and whether 

civil penalties are an appropriate sanction for the violation, if one occurred. The term “root cause 

analysis” is not defined in subpart A (the General Provisions) or in the subpart being promulgated, 

Subpart UUUUU. The EPA did not intend to prescribe a specific methodology, given that “root cause 

analysis” is not a defined term in the applicable subparts of Part 63. 

8. SSM limits should be more stringent; emissions are high during SS events.

Comment 60: Commenter 17975 states the EPA has not factored SSM emissions into the standards, and 

the EPA has not evaluated what monitoring can be done or what can be done to limit SSM emissions.

Based on EGUs in Texas that have recently submitted permit applications for PM during SSM, 

Commenter 17975 notes that emission rates for SSM events range from 0.375 to 5.5 lb/MMBtu, which 

is 12 to 180 times the 0.03 lb/MMBtu limit set for non-g metals. Commenter 17975 states that facilities 

have requested SSM durations of 48 hours at a time and for up to 600 hours per year, and Title V 

monitoring reports for 2009 and 2010 for these same facilities show actual duration of SSM events 

frequently exceed 100 hr/yr, and more than 200 hr/yr at one facility.
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Commenter 17755 states that a majority of PM and opacity excess emissions occur during SSM when 

the ESP is not operating.

Commenter 17975states that total PM emissions during SSM events can be 20 times higher than during 

normal operations and cited Texas EGUs with PM limits of 216 lb/hr that show 4,788 lb/hr for 

startup/shutdown, so that now their annual PM emissions that are currently 946 ton/yr per boiler could 

emit up to 1,436.4 ton/yr per boiler if the SSM application is granted. Commenter 17975 highlights 

another facility with current emissions limit of 1,033 ton/yr that could emit up to 2,284.4 ton/yr if the 

SSM application is granted. Commenter 17975 notes the SSM emission limits requested in the Texas 

applications are high and may jeopardize compliance with the EPA’s non-Hg metal standard. The 

commenter presents an example where they assume SSM periods at 24 hours duration, incorporates 

these higher emission levels into the 30-day rolling average, and shows that the emissions range from 

0.034 to 0.053 lb/MMBtu, which is far above the standard of 0.03 lb/MMBtu. Commenter 17975 states 

that 24 hours of SSM periods would also increase total non-Hg metals to 43 and 47 lb/TBtu for the 30-

day rolling average, which is above the standard of 40 lb/TBtu. The commenter also notes that the 

opacity exceedances from SSM events exceed 24 hours, so the emissions would be even higher.

Commenter 17975 states that opacity data, which is a primary indicator of PM emissions, at EGUs in 

other states indicate high PM emissions during SSM events. The commenter cites an Oklahoma facility

with 167.1 hr of opacity exceedances per year, and four other facilities with over 40 hours of opacity

exceedances per year due to startup/shutdown. The commenter notes that these estimates are 

conservative since they do not include opacity spikes due to maintenance events during normal boiler 

operation. Commenter 17975 further notes that these exceedances can be extreme, and cited facilities 

with 80 percent opacity for 25 hours.

Commenter 17755 states that their inspectors have documented significant particulate emissions from 

COMS data during SSM and offline periods when the boiler may or may not be combusting, with 

greater than 400 hours per quarter for some units.

Commenter 17975 states available PM emissions and opacity data suggest that plants would have to 

average 10 percent opacity to achieve 0.03 lb/MMBtu PM, however opacity during startup and 

shutdown can be much higher, at 60 percent opacity or higher for several hours. Commenter 17975 

notes that EPRI data shows PM levels of 0.06 lb/MMBtu with opacity of 15 percent; PM of 0.23 

lb/MMBtu with opacity of 25 percent. Commenter 17975 indicates there is not much data relating PM 

emissions to extremely high opacity events, but cited data from a Georgia facility that measured 1 

lb/MMBtu with opacity at 60 percent, which is 30 times higher than EPA’s standard.

Commenter 17975 has reviewed SSM applications in Texas and opacity data from 2009 and 2010 from 

the same plants and states that SSM emissions may be even higher than the facilities have estimated. 

The commenter indicates that emission calculations assume 30 to 80 percent of fine PM are removed 

even when the ESP is not operating, because a fraction of fly ash sinks to the bottom of the APCD, 

however it is likely that heavier particles would drop out but smaller PM is more likely to be emitted. 

The commenter notes that the SSM application for one facility shows maximum emissions estimates 

during startup based on heat rate no greater than 693.84 MMBtu/hr, however Title V monitoring reports 

for the facility show opacity exceedances at startup of 80 percent or more at much higher heat rates than 

those shown as maximums in the application, for example, an opacity exceedance of 93 percent at over 

2,500 MMBtu/hr heat input. The commenter states that these much higher heat rates for startup suggest 

the emissions can sometimes be much higher than estimated in SSM applications.
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Commenter 17975 states that many ESPs are not turned on during startup/shutdown because they

require minimum temperature for safe operation and they cannot function effectively until certain inlet 

gas temperature and flow rates are reached. The commenter indicates that ESPs are not turned on while 

coal is burned for extended period of time during startup and in the final hours of shutdown.

Commenter 17975 states it is common for ESPs not to be energized until proper operation conditions 

occur, and it is clear that permits do not contain limits to minimize startup and shutdown periods of ESP 

non-operation. The commenter states PM emissions and opacity are high during these time periods. The 

commenter states that high opacity during SSM time periods indicates high PM emissions, and while no 

uniform correlation has been developed between opacity and PM emissions, one can reasonably

conclude that periods of high opacity during SSM are periods when PM and non-Hg metal emissions are 

high. Commenter 17975 provides examples of opacity and PM data for coal-fired units (see Table X in 

EPA-HQ-OAR-2009-0234-17975).

Commenter 17975 states that during startup/shutdown, baghouses can operate at lower temperatures, 

may not need to be bypassed at all, and could be bypassed for a much shorter period during startup.

Commenter 17722 states that baghouses do need to be bypassed during startup with fuel oil, as fuel oil 

negatively impacts the bags.

Commenter 17957 states the EPA must evaluate maximum control technologies that are most efficient 

in reducing SSM emissions and use the evaluation to set appropriate limits. The commenter indicates 

that high PM and non-Hg metal emissions are the result of decisions by some EGUs to continue to rely

on ESPs that are not designed to function during startup/shutdown, or because EGUs have chosen not to 

explore other alternatives for reducing SSM emissions. Commenter 17975 notes baghouses are more 

effective during normal operating conditions, giving units a greater margin to accommodate upsets and 

still stay in compliance with 30-day averaging period. Because more than 30 percent of EGUs are 

controlled with baghouses, Commenter 17975 states that if MACT standards are based on the most 

effective fabric filters as the law requires, SSM emissions would be greatly reduced.

Commenter 17975 states that while the EPA acknowledges that MACT standards must apply at all 

times, that does not mean weakening a proposed standard to accommodate SSM, by lengthening the 

averaging time for compliance, or treating these episodes as immovable objects, when technologies that 

can reduce emission are proven and commercially available.

Commenter 17975 states there are best management practices to reduce emissions during SSM periods, 

including: new and existing units should be equipped with baghouse (instead of ESPs) to reduce 

emission of PM, including fine PM and thus metal HAP; natural gas should be used as startup fuel, 

given that it is available, reduces startup emissions, is not technically challenging, and has modest cost; 

and the duration of SSM events should be kept to a minimum by defining process conditions that denote 

the start and end of the event in enforceable permit conditions.

Commenter 17975 notes that monitoring of non-Hg metals is not required during SSM. The commenter 

notes that the monitoring methods identified in the proposal fall far short of what is need to calculated 

emissions when boilers are brought down for maintenance and restarted after that work is complete. The 

commenter indicates that stack testing is conducted during “normal” operation and testing is not 

required to assure compliance during SSM, when emissions are likely to be highest. Commenter 17975 

states that absent the evaluation of SSM events and methods to reduce their frequency and severity, as 

30-day rolling average designed to accommodate SSM events is an arbitrary standard.
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Commenter 17975 notes that deslagging of units as part of maintenance contributes to increased opacity

even though the unit is not operating. The commenter indicates baghouses can remove deslagging PM 

far more effectively than ESPs, which would not be energized when the unit is off and when deslagging 

occurs.

Commenter 17975 provides examples of drop-out factors used for ESPs to estimate PM emissions 

during startup and shutdown, where even though the ESP is non-operational or non-energized, the 

collection efficiency is not zero.

Response to Comment 60: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These work practice standards take into account operation 

of APCDs. See the preamble and rule for discussion and requirements. The EPA’s rationale for its 

approach to malfunctions is discussed in the preamble. 

We note that sources that install CEMS or other continuous monitoring devices are required to operate 

them at all times. Section 63.10020 clearly states that if you are conducting continuous monitoring, 

“You must operate the monitoring system and collect data at all required intervals at all times that the 

affected EGU is operating...” We believe that it is important to collect data during all process operating 

periods including SSM periods, as the rule requires when conducting any continuous monitoring (see 

additional responses above relative to the accuracy and utility of such data). The Agency also believes 

EGU owners or operators strive to minimize periods of malfunction and should a malfunction period 

occur, its duration will be brief, as noted by the commenter. Any impact of potential excess emissions 

occurring during a period of malfunction would be offset through use of the rule’s 30 boiler operating 

day rolling average requirement. To the extent the CEMS records an exceedance during a malfunction, 

and the owner or operator believes the measurement was in error, the owner or operator can demonstrate 

that the source complied with the standard notwithstanding the CEMS measurement using any available 

information.

Commenter’s inference that PM emissions during startup may be up to 20 times higher than during is 

based on permit information and emissions estimations rather than emissions data. Further, commenter 

does not provide HAP data for such periods. We believe that our approach will provide the data 

necessary to evaluate these emissions during the 8-year review.

9. Use of multi-metals CEMS and fuel testing for startup fuels.

Comment 61: Commenter 17283 states that use of a multi-metal CEMS allows monitoring of all urban 

HAP metals, including Hg and all phases. Commenter 17283 indicates that multi-metal CEMS have 

lower initial and on-going costs than the EPA’s option of monitoring with two CEMS, and multi-metal 

CEMS use allows monitoring of emissions directly, so it is not necessary to conduct performance testing 

for individual metals.

Commenter 17675 supports the exemption from fuel testing for startup fuels.

Response to Comment 61: For the use of multi-metals CEMS, please see the response to all comments 

under Comment Code 5A07b. The exemption for startup fuels is no longer applicable as the proposed 

fuel testing requirements are not part of the final rule.

10. Initial startup.
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Comment 62: Commenter 17801 states that neither MACT or NSPS limits should apply during the 

initial startup of a facility, should not apply until after the EGU has achieved its Commercial Operation 

Date (CCD), or at the earliest, per 40 CFR 60 General Provisions, 60.8 for a performance test 

demonstration compliance period that allows up to 180 days after initial commissioning operation. 

Commenter 17801 states that the EPA could establish different limits based on initial startup and 

commissioning conditions and activities.

Response to Comment 62: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits, and compliance with the work practice at initial startup 

should not be an issue for sources. Further, commenters have not explained under what authority EPA 

would allow a source to not comply with the final rule on the compliance date of the final rule; 

therefore, we are not providing the provision suggested by the commenters.

11. Initial data.

Comment 63: Commenter 17402 states that the EPA cannot establish that the proposed numeric 

emission limits represent a reasonable estimate of emissions achieved by the best performers during 

startup and shutdown as required by the CAA and the courts in Cement Kiln Recycling Coalition. 

Commenter states that, as a result, the EPA must establish work practice standards for these periods.

Comment 64: Commenter 17776 states that the proposed rule would inappropriately require EGU’s to 

comply with numeric MACT standards during startups and shutdowns even though the agency did not 

consider data for startup and shutdown in developing the standards. The proposal is therefore arbitrary

and capricious because the agency relies on inaccurate or unfounded assumptions about such events. 

Commenter 17776-11 states that the EPA assumes incorrectly and without adequate basis that startup 

and shutdown are predictable and routine, that a 30-day averaging period will accommodate startups and 

shutdowns, and that emissions during these periods can be accurately calculated. Commenter 17776-11 

states that many outages are unavoidable and unplanned with the effect that the 30-day averaging time is 

not adequate given the frequency of outages.

Comment 65: Regarding startups and shutdowns, commenter 17914 cites the following as problems 

with the EPA’s MACT floor analysis:

 No startup/shutdown data were considered.

 Incorrectly characterized solid fuel-fired EGUs as infrequently starting up and shutting down and 

using cleaner fuels during startup.

 Incorrectly characterize startups and shutdowns as predictable and routine.

 Limited PM monitor data indicates an order of magnitude higher emissions during startup and 

shutdown than during normal operation.

Commenter 17914 recommends that the agency collect a minimum of 30 days of continuous emissions 

data, including periods of startup and shutdown, from the top performers and use the data to set the 

standard.

Comment 66: Commenter 18034 states that emissions during startup and shutdown were not evaluated 

for the proposed emission limits and that the EPA should establish work practices for these periods. 

Commenter 18034 states that the boiler MACT rule requires work practices in lieu of numerical limits 

for periods of startup and shutdown.
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Response to Comments 63 - 66: The EPA acknowledges that it does not have data upon which to base 

numerical emission limits during periods of startup and shutdown. Therefore, the EPA is, in the final 

rule, establishing work practice standards for periods of startup and shutdown. In addition, the EPA is 

committing to reevaluating this approach during the 8-year review when sufficient CEMS data will be 

available from the EGU population.

Comment 67: In commenting that the EPA is not adequately addressing emissions during startup, 

shutdown and maintenance, commenter 17975-15 states that opacity exceeded 80 percent during at least 

44 hours at Gibson boiler 2 in 2009 after boilers were turned off for maintenance. Commenter 17975-30 

provides data showing PM emissions of 0.03 to 0.050 lb/MMBtu at opacities of 10 to 11 percent, which 

implies that opacities greater than these correspond to PM emissions greater than the proposed 0.03 

lb/MMBtu.

Response to Comment 67: Commenter has not provided data to indicate the impact of these periods of 

high opacity on HAP emissions. Further, commenter has not provided, and the EPA does not have, data 

on HAP emissions during periods of startup and shutdown. In addition, it is not clear what commenter is 

suggesting the EPA do with this information or how we could incorporate it into the MACT standard 

setting process. In the final rule, the EPA has specified work practice standards for periods of startup 

and shutdown. See the preamble for discussion. 

12. Other.

Comment 68: Commenter 17402 opposes the application of the numeric emission limits established for 

steady state operations to sources during periods of startup and shutdown. Commenter states that as a 

result of the technical infeasibility of measuring emissions and the impracticability of enforcing numeric 

emissions limits during those times, the statutory requirements for the EPA’s authority to impose a work 

practice standard are met. The EPA should, therefore, abandon its approach to enforcing identical 

numeric emissions limits during startup and shutdown and, instead, adopt a work practice standard 

consistent with its own precedent in the Industrial Boiler MACT rule.

The commenter states that even with the proposed 30 boiler operating day averages, emissions from 

these non-representative periods could significantly affect the averages, especially for peaking units or 

other units that com on- and off-line frequently. Commenter agrees with the EPA that startup and 

shutdown periods are of short duration in relation to the long-term operation of control equipment, but it 

is important to note that to maintain the efficiency of control equipment, they must be run in a certain 

way during periods of startup and shutdown. The EPA ignores what is well known–emissions control 

devices typically perform less than optimally during periods of startup and shutdown. In fact, some air 

pollution control equipment cannot be operated at all when the boiler is starting up. Commenter provides 

examples of how control device operation and efficiency are affected during startup and shutdown and 

by the procedures followed to bring pollution control equipment online. In the commenter’s experience, 

sources controlled using ESP will necessarily have higher Hg emissions during the first 24 hours after 

startup especially for plants using ACI to control Hg from subbituminous coal, which cannot be readily

controlled with other technologies. Commenter states that the numeric emissions limitations established 

for periods of steady state operations should not be applied to periods of startup and shutdown when 

controls are not performing at optimal levels (or are not performing at all until certain temperatures are 

reached).
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Several commenters (17681, 17714, 17758) also support work practice standards for startup and 

shutdown events. Commenters note that work practice standards are consistent with the CAA and has 

been done in other MACT rules, such as the industrial boiler MACT rule.

Response to Comment 68: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. See the preamble and rule for discussion and requirements. 

The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule 

and this final action.

Comment 69: According to commenter 17402, the EPA argument for not setting emission limits for 

malfunctions - that it would be difficult to apply the concept of best performing to a malfunctioning unit 

and that it would be impracticable to take malfunctions into account in setting CAA section 112(d) 

standards for EGUs - actually argues in favor of the EPA setting a work practice standard as an 

emissions standard for malfunction events rather than the numerical emission limits. Commenter 

opposes the EPA’s proposal to use its discretion to determine an appropriate response in the event of a 

malfunction and it opposes the EPA’s affirmative defense proposal. Commenter states that under their 

current title V operating permit applications, they have established a state-approved plan, which 

minimizes malfunction events and requires best practices be followed, that it follows during 

malfunctions and breakdowns, which is preferable to the EPA’s proposal in which there is a 

presumption of non-compliance and is focused on after-the-fact penalty. Furthermore, the EPA’s 

approach would add yet another burden on the states at a time when states are working with increasingly 

limited resources and are already overburdened with regulatory responsibilities. Since it would not be 

technically feasible to accurately measure emissions and impracticable to enforce numeric emissions 

limits during malfunction and breakdown (for either stack testing or CEM monitoring, which would not 

have the ranges required to have accurate data), the statutory requirements for the EPA’s authority to 

impose a work practice standard are met and the EPA should abandon its approach to enforcing identical 

numeric emissions limits during malfunction and breakdown and, instead, adopt a work practice 

standard.

Response to Comment 69: The EPA’s rationale for its approach to malfunctions is discussed in the 

preamble. As explained in those preambles, the EPA has determined that CAA section 112 does not 

require that emissions that occur during periods of malfunction be factored into development of CAA 

section 112 standards. As the EPA further explained, accounting for malfunctions would be difficult, if 

not impossible, given the myriad different types of malfunctions that can occur across all sources in the 

category and given the difficulties associated with predicting or accounting for the frequency, degree, 

and duration of various malfunctions that might occur. The EPA’s rationale for its approach to 

malfunctions is not based on the criteria that must be met to justify a work practice standard under CAA 

section 112(h). Further, setting work practice standards under section 112 presents the same issues as 

setting numerical emission limits given the varied nature of malfunctions. In any event, commenter has 

not provided support for its assertion that it would not be technically feasible to accurately measure 

emissions and impracticable to enforce numeric emissions limits during malfunction and breakdown. 

Sources in this category can and do operate multiple measurement systems that measure different 

parameters at different points in the generating process and on affected sources and control equipment. 

While direct measurement of some factors may or may not take place during certain malfunctions, the 

EPA is not persuaded that sources could be left with no means whatsoever to determine whether they 

stayed in compliance during a malfunction. Sources may use other available means (including 

engineering judgment) or information to demonstrate that the source complied with the standard.
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With respect to commenters claim that the affirmative defense will burden the state, many of the 

conditions of the affirmative defense were modeled after the conditions of the affirmative defense in 

EPA’s SIP SSM policy, which several states have adopted into their SIPs. (See, e.g., State 

Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and 

Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and 

Malfunctions (Feb. 15, 1983)). We do not have any indication that states have had any significant 

difficulties applying or implementing the terms of these SIP affirmative defenses. 

Comment 70: Commenter 18539 recommends that a startup, shutdown and malfunction plan that is 

incorporated into a unit’s title V permit is an appropriate work practice standard for startup, shutdown 

and malfunction. Commenter 17402 recommends that the EPA adopt a requirement that a unit must 

submit an SSM plan for approval and incorporation by reference into its title V operating permit as the 

work practice standard for periods of startup, shutdown and malfunction. According to the commenter, 

such as approach would ensure that units minimize SSM periods and that appropriate operating practices 

are followed during these periods and, thus, would result in minimizing emissions.

If the EPA does not adopt a work practice standard for periods of startup and shutdown, the commenter 

requests, in the alternative, that the emission averaging period be increased to a rolling 12-month 

average time period as opposed to the proposed 30-day rolling average. In this way, the increased 

emissions from periods of SSM would be spread out over a longer averaging period, and the EPA could 

potentially show that the limits were achievable even during SSM events.

Commenter 17776 likewise believes that a more stringent approach for startup and shutdown emissions 

is not necessary for some types of boilers and encourages the EPA to require compliance with work 

practice standards for EGUs as in the Boiler MACT. Failing that, the commenter suggests that the EPA 

set special MACT standards for startup and shutdown periods at EGUs based on a reasoned analysis of 

data concerning such emissions.

Commenters 17790 and 17851 find the EPA’s logic about applying the proposed standards during 

startup and shutdown to be flawed because it does not account for the variety of ways in which the 

EGUs startup and shutdown and because it is not based on actual emissions during those occurrences. 

Commenters point out that PM CEMS are not correlated during periods of startup and shutdown because 

the EPA requires full-load operation for CEMs certification testing and the EPA manual test methods 

are not designed for transient plant operations. Therefore, Commenters request a separate work practice 

standard for use during periods of EGU start-up and shutdown. Commenter 17914 agrees with this 

suggestion.

Commenter 18037 recommends that the EPA adopt a work practice standard in lieu of numeric 

emissions limitations during periods of startup, shutdown, malfunction and breakdown. The operational 

efficiency of control equipment is critical to emissions reduction and these controls must be run in a 

certain way during periods of startup and shutdown. The EPA’s decision ignores that it is well known 

that emissions control devices typically perform less than optimally during periods of startup and 

shutdown. In fact, some air pollution control equipment cannot be operated at all when the boiler is 

starting up.

Response to Comment 70: For periods of startup and shutdown, the EPA is finalizing work practice 

standards instead of numeric emission limits. These standards take in to account operation of APCDs. 

See the preamble and rule for discussion and requirements. The EPA’s rationale for its approach to 

malfunctions is discussed in the preambles to the proposed rule and this final action and elsewhere in 
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this response to comments document. The requirements do not include a startup, shutdown, and 

malfunction plan. See Table 3 to Subpart UUUUU of part 63. Commenter’s suggestion that its stateapproved plan is prefereable to EPA’s approach does not explain how an approach based on such a plan 

meets the requirements of section 112.
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5C07 - Compliance: Other

Commenters: 16849, 16850, 17385, 17402, 17620, 17638, 17648, 17689, 17702, 17714, 17716, 17718, 

17719, 17729, 17730, 17736, 17737, 17740, 17752, 17754, 17756, 17758, 17761, 17765, 17767, 17768, 

17772, 17775, 17790, 17791, 17795, 17798, 17800, 17805, 17808, 17813, 17818, 17820, 17821, 17840, 

17851, 17867, 17868, 17871, 17880, 17881, 17886, 17902, 17909, 17914, 17928, 17930, 18019, 18025, 

18034, 18424, 18429, 18477, 18498, 18539, 18541, 18963, 19033, 19114, 19214, 19536, 19537, 19538, 

18023

1. Support low emitters alternative compliance.

Comment 1: Commenter 17402 supports establishment of a low emitters alternative compliance, with 

modifications. Commenter 17402 states that facilities that satisfy the low emitters standards are 

necessarily demonstrating emissions 50 percent to 90 percent below the proposed limits, and these 

extremely low emissions should be encouraged with greater compliance flexibility. Commenter 17402 

proposes that fuel testing only be required every 6 months. Commenter 17402 also suggests that testing 

be based on the reductions capability of the plant demonstrated during the test, not the particular level of 

emissions during the test.

Commenter 17754 states that if an affected EGU has been determined to be a LEE (for Hg), it is clear 

that such unit’s Hg emissions are very low, and as such, these LEE units should not be subject to unduly

burdensome requirements for demonstrating continuous compliance.

Commenter 17176 states the fuel sampling requirements for LEE units are ambiguous, provide no 

compliance value, do not require the establishment of a fuel input operating limit, do not address singlefuel units, changes in fuel type, or units that burn or co-fire multiple fuels. Consistent with the non-LEE 

requirements, Commenter 17176 states that LEE units that burn multiple fuel types or blends should 

establish a fuel-input operating limit during the initial compliance demonstration, and the EPA should 

remove the monthly fuel sampling requirement and allow multiple-fuel LEE units to conduct fuel 

sampling only when the fuel type changes. Commenter 17176 states single-fuel LEE units should not 

have to comply with any fuel sampling requirements.

Commenter 17754 states the EPA should revise the proposed rule regarding the use of the 90th 

percentile upper confidence level for determining the operating limit for mercury (LEEs for Hg). 

Commenter 17754 states the rule should be clarified that, while the initial performance test is conducted 

over a 2830 day period to demonstrate LEE status, the subsequent performance tests (performed every 5 

years) shall consist of three 120-minute runs, unlike the longer duration of the initial performance test.

Commenter 17754 notes the rule should be modified because it is unclear whether a source 

owner/operator who demonstrates initial satisfaction with the LEE criteria, but then subsequently fails to 

demonstrate continuous compliance with the relevant standards, has the ability to retest the unit to 

reestablish its LEE status. Commenter 17754 states a source owner should be afforded the opportunity to 

demonstrate that an affected EGU qualifies as a LEE, notwithstanding a prior performance test result 

exhibiting emission rates in excess of the threshold. Commenter 17754 indicates the compliance 

demonstration methods under the rule provide a highly conservative estimate of Hg emission rates for 

purposes of ensuring LEE status, and this conservatism should not prevent such source owner from 

demonstrating LEE applicability by more refined analyses.
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Response to Comment 1: The final preamble describes the final rule provisions for LEE. Because the 

proposed fuel analysis provisions are not part of the final rule, the approach to maintaining LEE status 

has changed. For mercury, an existing unit may qualify based on an initial Method 30B test, and then 

will have to retest annually. If the LEE status is lost based on the results of an annual retest, the rule 

requires you to install an Hg CEMS or sorbent trap monitoring system, with quarterly Method 30B 

testing until the monitoring system is certified. You can regain LEE status for that unit if every required 

performance test for a 3-year period shows that emissions from the unit did not exceed the LEE limit. 

For non-Hg emissions, you can qualify for LEE status if all performance tests conducted over a 3-year 

period meet the LEE qualification limit. In that event, you must retest every 36 months to demonstrate 

that you still qualify for LEE status. If any subsequent emissions test for that pollutant exhibits 

emissions greater than 50 percent of the emissions limit, you must revert to the original emissions 

testing frequency until you re-establish a 3-year period of very low emissions no greater than 50 percent 

of the standard.

2. Support the EGU NESHAP Rule.

Comment 2: Commenter 17648 states the EGU toxics rule will provide needed regulatory certainty and 

will spur investment in new generation controls. Commenter 17648 notes that today we increasingly rely

on aged infrastructure that operates without pollution controls simply because the federal government 

has failed to establish legally enforceable emissions standards for toxic pollutants. Commenter 17648 

states that the lack of a national standard for toxic emissions continues to be a barrier to investment in 

new, cleaner generation capacity as well as the modernization of existing sources. Commenter 17648 

states companies are reluctant to build replacement, cleaner generation or to modernize existing plants 

when it is not assured that their competitors will be required to comply with modern emission standards, 

and it has been found that the installation of pollution controls will raise the marginal costs of 

production for those early adopters and place them at a competitive disadvantage relative to those that 

do not install pollution controls. Commenter 17648 states the regulatory certainty provided by

the toxics rule is long overdue.

Commenter 17930 supports the EPA’s decision that it was not appropriate to set numerical emissions 

limits for organic HAP and that a work practice standard would be more appropriate. As stated by the 

EPA, the majority of measured organic HAP emissions from EGUs are below the detection levels of the 

EPA test methods. They cannot be reliably measured and cannot be subject to emissions limits.

Commenter 18541 states that technologies are available to achieve such reductions, and virtually

eliminate some of these emissions, not only though on-site emissions reductions, but also by switching 

to cleaner sources of electricity generation and energy efficiency, and using improved grid system 

management within the relevant electricity balancing area.

Commenter 17718 supports the EPA’s proposed approach to streamline the continuous compliance 

requirements for monitoring, reporting, and recordkeeping. The commenter states that the EPA is correct 

in recognizing that the compliance requirements are already applicable to EGUs and eliminating 

redundancy wherever possible. The commenter urges the EPA to remain open to additional 

accommodations that are identified in the course of implementing the program. 

Commenter 19214 states that to demonstrate compliance with both the Boiler NESHAP and the EGU

MACT, the more stringent emission limit should be demonstrated. The commenter states that it is the 

responsibility of the source to show compliance with all applicable limits. The commenter supports the 

EPA’s proposal that compliance with the more stringent emission limit be demonstrated.
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Response to Comment 2: The EPA acknowledges the support provided in these comments, and 

believes the final rule remains consistent with these general areas of support.

3. Performance testing.

Comment 3: Commenter 17808 states the testing requirements are very burdensome and believes the 

agency could achieve an equivalent level of compliance assurance with a lower compliance burden with 

adjustments.

Comment 4: Commenter 18023 urges the EPA to allow annual filterable PM stack testing as an 

alternative compliance option. Commenter 18023 notes that complying with the monthly or bi-monthly

PM or non-Hg metallic HAP alternatives is not practical for the following reasons: (1) both planned and 

forced outages will make it difficult to obtain proper unit operating levels, which will stretch the short 

term capacity of the testing community nationwide; (2) it is cost prohibitive, as PM testing will cost 

approximately $3000 to $5000 per source per month, Hg testing via RM-30B will cost approximately

$10,000 per source per month, and non-Hg metal testing via RM-29 will cost approximately $8,000 to 

$10,000 per source per month; (3) analytical results take a minimum of 2 weeks to be analyzed and 

reported by laboratories, so a unit could potentially be out of compliance for 2 weeks before analytical 

results could be provided; (4) analyzing this data is a difficult scientific proposition – lab technique and 

experience are important to avoid biasing the data; and (5) changing compliance and permit limits 

monthly based on new test results would place unreasonable operational restrictions on generating units 

in an effort to comply with a potentially moving target.

Response to Comments 3 - 4: In the final rule, the optional periodic testing has been reduced to once a 

quarter. Sources have the option to use CEMS or PM CPMS in lieu of compliance testing.

Comment 5: Commenter 17775 states EGUs should have flexibility to specify when performance tests 

for CEMS and sorbent trap monitoring systems start. Commenter 17775 notes that 

for CEMS or sorbent trap monitoring system, the “performance test” consists of the “first 30 operating 

days of data collected with the certified monitoring system.” (section 63.10005(a)); section 63.10005(g) 

through (j) allows 180 days after the applicable compliance date to “demonstrate initial compliance;”and 

“performance tests” also must be conducted under specific operating conditions (section 

63.10007(c)). Commenter 17775 objects to the proposed arbitrary designation of the “performance test”

periods. Commenter 17775 states the start of performance tests should not be arbitrarily tied to 

completion of monitor certification, but instead, EGUs should be allowed to complete certification tests 

on monitoring systems and to use those certified systems to determine whether the shakedown of 

emission controls have been successful prior to conducing the “performance test” to establish 

compliance with emission limits. Commenter 17775 notes that EGUs also must be able to time the start 

of the “performance test” to ensure that it meets the fuel and operating conditions the EPA has specified. 

In fact, proposed section 63.10030(d), which requires submission of a “Notification of Intent” to 

conduct a “performance test” at least 30 days before it is scheduled to begin, suggests that sources have 

the ability to specify a date in advance that may be unconnected to the testing of the monitoring system.

Commenter 17775 states that allowing sources flexibility to specify at what point during the 180-day

period the “performance test” starts not only makes sense, it is in some cases necessary. At a 

minimum, Commenter 17775 indicates the EPA needs to allow flexibility for sources to specify the start 

of the “performance test” for CEMS that have been previously certified (e.g., SO2 CEMS that were 

previously certified under the Acid Rain Program). Commenter 17775 points out that otherwise their 

performance test technically could have begun prior to the compliance deadline (or even prior to this 
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rule being promulgated). The commenter states that in addition, for PM CEMS, which do not conduct 

anything called “certification testing” (the term “certification” does not appear anywhere in PS 11), 

there is no clear point at which to declare that the performance test has begun. Unlike SO2 CEMS, 

PM CEMS must be correlated by conducting tests with a reference method and developing a 

“correlation curve” that meets PS 11 performance criteria. According to the commenter, once the curve 

is developed, the PM CEMS must be programmed so that its output is adjusted consistent with that 

curve. The commenter states that none of these actions are consistent with the concept of a system 

instantly becoming a “certified” upon completion of a test. The commenter states that although sources 

do conduct a 7 day drift test under PS 11, that test is almost always conducted prior to any correlation 

testing in order to avoid having to repeat correlation testing if the 7-day test is not passed, and as a 

result, the drift test cannot be used to define when the PM CEMS is ”certified.”

Response to Comment 5: While the EPA does not share the concerns that the commenters have about 

relating monitoring system certification with performance testing, final rule has been revised so that 30 

day test is not tied to the certification of the CEMS or sorbent trap monitoring system. In addition, as 

mentioned elsewhere, the requirements for the mandatory use of PS-11 have been removed from the 

final rule.

Comment 6: Commenter 17775 notes that the EPA must recognize that there are limitations on the 

conditions under which the EPA can require EGUs to test. To comply with CAA section 112, 

Commenter 17775 states the EPA assessed the capabilities of controls under the conditions specified in 

the 2010 ICR testing and established compliance testing and compliance assurance requirements 

consistent with that assessment. Commenter 17775 indicates the EPA has proposed continuous 

monitoring, initial stack testing, or periodic fuel analysis that it presumably believes are consistent with 

that assessment; as long as an EGU is complying with one of the options for demonstrating “continuous 

compliance,” there is no basis to allow the Administrator to specify some other test be conducted under 

some other set of conditions.

Commenter 17775 agrees that EGUs should be allowed to use prior tests, however, the EPA should 

allow use of any tests conducted under the same conditions, even if those conditions have not remained 

unchanged during the entire period since the test (e.g., if there was a period between the prior test and 

the current compliance demonstration when a different fuel was combusted).

Commenter 17880 supports the EPA to require affected coal or oil-fired plants to conduct performance 

tests that demonstrate compliance with applicable emissions limits.

Commenter 17928 states that the frequency of performance tests required for organics compliance 

should be reduced.

Commenter 18025 asks that the EPA give consideration to units already subject to state-level testing 

requirements where these requirements provide at least the same assurance as the Utility Toxics Rule. 

The commenter notes that their Bridgeport coal unit complies with a Hg emission standard half that 

proposed by the EPA for similar units. The commenter states that Connecticut DEP remains confident 

that quarterly stack testing provides a sufficient guarantee of compliance. The commenter states that 

likewise, the commenter’s Hudson and Mercer coal units consistently comply with New Jersey’s Hg 

requirement through stack testing, and recent test data have shown very low levels of Hg relative to New 

Jersey’s Hg limit of 3.00 mg/MWh (net). The commenter requests that in similar situations state 

requirements be accepted as alternate testing plans for the Utility Toxics Rule.
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Commenter 17930 states that the EPA has proposed to require an annual performance test, which 

includes a “tune-up,” but the EPA allows an extended period of up to 18 months “for those EGUs with 

unusual planned outage schedules,” though there is no standard planned outage schedule across the 

industry. The commenter states that many coal and lignite fired units are scheduling 24-month outages; 

some have even longer scheduled outages. According to the commenter, in the next few years, it is 

expected that the schedule will be extended even more as maintenance practices improve and as 

consumer electricity demands, and demands for base load capacity, increase. Therefore, Commenter 

requests that the final rule provide the option for performance tests and tune-ups to be conducted on the 

existing schedule of each power plant. The commenter states that in the event that the EPA feels there 

must be a maximum time limit, it cannot be shorter than 36 months without significantly interfering with 

plant operations.

Response to Comment 6: In response to comments, EPA has reduced the duplicative testing of fuels, 

HAP surrogates and HAP. Optional periodic testing frequency has also been reduced. The EPA 

disagrees with the adoption of various state Hg rules within the final MACT rule. Sources may apply on 

a site specific basis for alternative monitoring per 63.8. Neither the proposed rule nor the final rule 

required organic HAP compliance testing, so there is no frequency to be changed. The tune-up work 

practice and testing has been altered to allow for more flexibility for facilities with less frequent outage 

schedules.

Comment 7: Commenter 17775 states that the purpose of section 63.10005(d)(7) “(demonstrate initial 

compliance through CPMS)” is unclear. Commenter 17775 is not aware of any option in the rule to 

demonstrate compliance using CPMS that measure pollutant concentration. Commenter 17775 states the 

EPA should issue a proposal that explains the purpose of this provision so that they can provide

meaningful comment on it.

Response to Comment 7: The commenter is correct that there was no option for initial compliance 

option for use of CPMS in the proposed rule and this was an erratum.

4. Frequent testing for liquid oil-fired units.

Comment 8: Commenter 17758 states that frequent performance stack testing (monthly or every other 

month) for oil-fired EGUs is impractical, unnecessary, restrictive, and expensive, and notes these units 

would have to brought on-line just for the sake of performing the stack tests. Commenter 17758 states 

that liquid oil-fired EGUs should perform stack testing no more frequently than annually.

Commenter 17775 states that for section 63.10006(l) and (m) for liquid oil-fired EGUs without HCl 

and HF CEMS”, the EPA must make it clear that the HCl and HF testing requirements do not apply 

to EGUs using fuel analysis in lieu of performance testing, and that fuel analysis is an alternative to 

performance testing.

Commenter 17928 requests that the hours for mandatory unit testing should not be included in the 

calculation of oil use. These tests required by the ISO or for compliance with the proposed rule should 

be exempt from any “limited use” calculation.

Commenter 17716 states that many liquid oil-fired sources operate infrequently and only during peak 

demand periods, and frequent performance testing (monthly or every other month depending on whether 

add-on controls are installed) is burden. Commenter 17716 further notes that no correlation was found 

between the PM control at oil-fired units and non-Hg metallic HAP emissions, that the emissions 
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of HCl, HF, and non-Hg metals are most closely tied to fuel characteristics, and that changes in fuel 

characteristics over time could be tracked to determine if a change in emissions is 

likely. Commenter 17716 states the fuel sampling, analysis, and calculation of expected emission rates 

are already incorporated in section 63.10021 and should be applied for liquid oil-fired sources.

Response to Comment 8: Under the final rule, liquid oil-fired units have three basic options for 

monitoring compliance, with a third alternate a possibility in some situations. First, these units may

conduct quarterly performance tests to demonstrate ongoing compliance. If they choose this option, they 

must also conduct site-specific monitoring to ensure compliance between tests (see the final preamble 

for further discussion). Second, sources may use CMS for various pollutants. This includes the use of a 

PM CPMS to demonstrate compliance with an operating limit established during an initial performance 

test that demonstrates compliance with a filterable PM, total HAP metals, or individual HAP metals 

emission limits. A source can also elect to use a PM CEMS as a direct compliance method with the 

filterable PM standard (see the preamble for further discussion of this option). It also includes the use of 

an HCl/HF CEMS for acid gas compliance demonstrations. The third alternative is for fuel moisture 

monitoring. This compliance option allows you to monitor fuel moisture (either through direct sampling 

of fuel you receive or through fuel supplier certification). Provided that the fuel moisture is no greater 

than 1.0 percent, the rule states that you are in compliance with the HCl and HF emission limits. If 

results indicate moisture above 1.0 percent, you must institute one of the other options for monitoring 

compliance with the HCl and HF limits. With respect to the comment concerning the need for HCl/HF 

CEMS performance specifications, please see the responses to comments under Comment Code 5A09.

5. Operating limits.

Comment 9: Commenter 18023 suggests BLDS for fabric filters are not necessary, and if BLDS are 

required in the final rule they should only be used for purposes of triggering maintenance activities. 

Commenter 18023 explains the following for BLDS: (1) this operating limit is purely arbitrary, the EPA 

provides no information nor makes any claim that the operating limit quantifiably connected to the HAP 

emission limit; (2) the preamble language provides a different requirement where the output of the 

BLDS is measured during performance testing and then becomes a BLDS operating limit, this is an 

improper use of the BLDS as it attempts to use the system to quantify emission rates; (3) the EPA 

guidance document on Fabric Filter Bag Leak Detection Guidance states, “this guidance is not intended 

to evaluate changes in the long term performance of the baghouse system, nor does it apply to 

applications in which monitoring system attempts to quantify emission rates” (EPA-454/R-98-015 

September 1997); (4) the BLDS is more appropriately used to trigger maintenance activity rather than 

being used to determine compliance; and (5) bag failures are not acute occurrences and could be 

adequately identified in the bi-monthly performance test required by the MACT.

Comment 10: Commenter 18023 suggests setting fixed secondary power input limits for ESPs is 

unnecessary, and if the EPA goes forward setting ESP operating limits, the only necessary requirement 

should be to ensure that ESP power supplies remain in service. Commenter 18023 explains the 

following: (1) ESPs are generally designed to meet a specified performance level with one or 

more TR sets out of service, this provides operational margin for malfunction and/or maintenance of 

each TR set, a boiler operator would have to perform its compliance test with secondary power 

artificially reduced in order to maintain this margin, and this seems to contradict the EPA’s desire to 

acquire meaningful emission data; (2) process conditions beyond the control of the boiler operator such 

as flue gas temperature, fly ash resistivity, and grain loading can affect the power levels of the ESP 

without necessarily detrimentally impacting emissions, some margin should be added to the operating 

limit to account for this variability (i.e., within 20 percent of the lowest 1-hour average secondary
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power); (3) because performance does not correlate perfectly with ESP secondary power, a reduction in 

power is more appropriately used to trigger maintenance activity (i.e., returning a TR set to operation) 

rather than being used to determine compliance; and (4) it is unclear why the proposed operating limits 

only apply for EGUs that operate additional wet control systems, the EPA should clarify what 

requirements they are proposing for EGUs that operate only an ESP.

Response to Comments 9 - 10: The EPA has responded to similar comments under Comment Codes 

5A05 and 5A05a. Please see those responses. Under the final rule, there are no operating limits for 

control device parameters or any BLDS requirements. 

6. Support flexible compliance options.

Comment 11: Commenter 16850 states that electric utilities should be given the flexibility to choose the 

most efficient, least-cost compliance options to meet public health and environmental goals.

Commenter 17648 notes the EPA has provided a variety of compliance options, particularly notes that 

the EPA provided a flexible array of compliance options for both initial and continuing compliance 

demonstrations, and encouraged the installation and use of CEMS but has not mandated CEMS, thus 

giving sources reasonable opportunity to design different compliance programs that best align with the 

source’s short- and long-term plans.

Commenters 17730 and 17820 appreciate that there are several compliance options in the EGU MACT 

rule, and states that electric utility industry will need flexibility to achieve compliance with the 

requirements.

Comment 12: Commenter 17736 requests that the EPA revise the emissions limitations to reflect the 

inherent operational variability of coal-fired EGUs and provide sources with greater flexibility to 

demonstrate compliance. According to the commenter, the EPA must give practical consideration as to 

how coal-fired EGUs operate. The commenter states that the combustion technologies for coal-based 

units drive the selection of emissions controls, such as wet versus dry flue gas desulfurization.

Comment 13: Commenter 17772 states that the proposed rules purportedly leave in place the existing 

emission standards for SO2, NOX, and PM as applied under Part 60, subpart Da to existing EGUs. The 

commenter states that the compliance provisions as proposed in the HAP regulations, Part 63, to include 

all emissions even during periods of SSM makes no adjustments to the currently-effective emissions 

levels but makes those levels more difficult to achieve for an existing EGU that is reconstructed or 

merely modified, by eliminating the existing SSM exclusions. Commenter recommends that the EPA 

reconsider incorporating these SSM exclusions.

Comment 14: Commenter 17791 requests that the EPA recognize the needs of states and regions to 

deploy a diverse portfolio of cost-effective supply-side and demand-side resources based on the unique 

circumstances of each State and region.

Commenter 18539 states that the EPA takes steps to provide critical flexibility by providing for the use 

of surrogates to demonstrate compliance, proposing work practice standards where appropriate and 

allowing for emissions averaging. The commenter states that the EPA diminishes the utility of these 

flexibility mechanisms-consequently driving up costs and complexity-by placing burdensome and 

unnecessary restrictions and requirements on them, without demonstration of substantial environmental 

or health benefits and that the EPA’s proposed compliance testing and monitoring programs are 
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complicated, confusing and costly, without any demonstration as to why the requirements are necessary

or how they would ensure compliance over the long term even among the existing top 12% MACT pace 

setters.

Commenter 19114 asks for greater flexibility so sources can reliably demonstrate compliance, such as 

through reexamination of the sources of uncertainty and recalculation of the limits, longer averaging 

times, additional options for averaging with other units, as well as development of work practice 

standards for known periods when controls do not operate, such as start-ups and shutdowns, or design of 

emission rates that can actually be achieved across the whole range of operations a unit would 

experience. The commenter states that the EPA should consider the full range of operating conditions 

that might be expected over the life of a unit in establishing the final rule. The commenter is concerned 

that there is a risk of non-compliance due to unknown and uncontrollable variables, especially for 

elements present in trace quantities for which no detailed operational history exists, is significantly

increased. According to the commenter, state agencies have designed permits with limits or work 

practice standards that are applicable to specific coal types and/or operating scenarios. The commenter 

states that in many cases, permits have been designed that exempt specific operating conditions, such as 

startup, shutdown, and malfunction operations, from the emission limits designed for normal operations. 

According to the commenter, particularly in the case of EGUs where control equipment is subject to 

known operational limits (like safe operating temperatures in the flue gas before electrostatic 

precipitators can be energized or ammonia injection for a selective catalytic converter can commence) 

the case for the development of work practice standards is strong. The commenter asserts that the EPA’s 

proposed limits do not provide sufficient flexibility to allow compliance demonstrations to be made 

during reasonably foreseeable operating scenarios and must be reevaluated.

Comment 15: Commenter 16849 supports the need for at least a 180-day period to perform all 

compliance testing including needed adjustments and repairs to Hg CEMS.

Commenter 17928 states that compliance requirements that are based on calendar months or calendar 

quarters, rather than on operating quarters or years, could lead to unnecessary operation solely to 

demonstrate compliance, which is undesirable from both an environmental and a financial perspective.

Response to Comments 11 - 15: We address comments related to the compliance time and 

startup/shutdown/malfunction in the preamble to the final rule and elsewhere in this RTC. With regard 

to the flexibility comments, we believe that we have provided the flexibility reasonably allowed under 

the statute and court precedent. As noted elsewhere in this document, we have made adjustments to the 

monitoring provisions of the final rule that we believe will reduce the burden and complexity while 

complying with the statute.

The rule increases the emissions monitoring, reporting, recordkeeping, and testing options available to 

EGU owners or operators by adding additional choices, each of which has an averaging time that assures 

compliance with emissions limits. The rule no longer contains emissions limits but work practice 

standards, including operation of emissions control devices as appropriate, during periods of startup or 

shutdown and does not impede development and deployment of diverse energy portfolios. Compliance 

options have been simplified, but still assure compliance with emissions limits. While the Agency finds 

no impediment concerning averaging periods based on calendar months or EGU operation, the rule 

affords liquid oil-fired EGUs whose annual capacity factor is less than five percent the ability to meet a 

work practice standard, rather than conduct emissions testing, thus preventing the commenter’s concern 

about unnecessary operation solely to demonstrate compliance.
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7. Clarifications needed for compliance demonstration.

Comment 16: Commenter 17752 states that the compliance demonstrations require clarification and 

revision. Commenter 17752 notes that although the EPA provides a number of compliance 

demonstration options, the applicability of many requirements is unclear. Commenters (17752, 17775) 

state the EPA must revise the proposal to clarify what requirements apply to each compliance option and 

include supporting rationale for each requirement. Commenter 17752 notes the preamble has 

inconsistent statements and lacks rational as to when operating limits and fuel input limits apply and 

when they do not apply (citing IV. Summary of this proposed NESHAP Section I. What are the testing 

requirements? Section J. What are the continuous compliance requirements? Section K. How did we 

select the compliance requirements? and V. Rationale for this proposed NESHAP). Commenter 17752 

cannot think of any rationale as to why a source with a continuous monitor would also need to comply

with an operating limit, and the commenter believes that the EPA intends for the operating limits and 

fuel input limits (including the operating load limit and continuous parameter monitoring systems) to 

only apply to EGUs who do not use continuous monitors to demonstrate compliance. Commenter 17752 

states that if this is not the case, the EPA needs to include rationale for requiring the operating limits and 

provide an opportunity for public comment on the rationale.

Commenter 17775 states these proposed provisions in section 63.10011(b) suggest that some EGUs, i.e., 

those that demonstrate compliance using “performance testing,” will need to establish operating limits 

and maximum fuel pollutant input levels, and those that do not use “performance testing,” will not have 

to establish those. However, Commenter 17775 notes that this supposed distinction between EGUs that 

demonstrate compliance using “performance testing,” and those that do not, does not exist elsewhere in 

the rule (or in the Part 63 general provisions); for example, proposed section 63.10000(c)(1) and (2) 

require “performance testing” for all EGUs, and proposed section 63.10005(a) and (b) require all 

affected EGUs to “demonstrate initial compliance . . . through performance testing . . . .”

Furthermore, Commenter 17775 notes that Table 5 identifies emissions testing, CEMS, sorbent trap 

monitoring, and LEE testing as “performance stack testing.” Commenter 17775 states proposed section 

63.10005(a) defines “performance testing” to include the first 30-operating days of CEMS data. 

Commenter 17775 points out that although proposed section 63.10005(c) allows liquid oil-fired EGUs to 

“demonstrate initial compliance . . . by conducting fuel analysis,” it is not clear whether the EPA intends 

that to constitute another form of “performance testing,” or an exception to it, and if it is an exception to 

it, the other provisions do not reflect that. Accordingly, Commenter 17775 indicates the proposed rule 

on its face appears to require all EGUs to establish site-specific operating limits for all controls used to 

meet emissions limits under the rule, and maximum fuel pollutant limits for chlorine, Hg, and non-Hg 

metals “according to” the cited provisions and paragraphs regardless of the compliance “option” they

choose.

Commenter 17775 states that the EPA must specify that the operating limits (including the operating 

load limit) and fuel input limits apply only to EGUs using stack tests to comply, or explain why those 

requirements are necessary for other units.

Commenter 17881 states that the EPA must revise the fuel types section in the proposed rule to clarify 

what requirements apply to each compliance option. According to the commenter, the EPA must provide 

a clear rationale for each proposed requirement.

Commenter 17775 assumes that the purpose of the control device operating limits is to help assure 

compliance between performance tests at EGUs that are not otherwise monitoring compliance with the 

relevant standard continuously (e.g., at EGUs not using CEMS or sorbent trap monitoring systems), and 
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that the purpose of the fuel input limits are to ensure that EGUs that are not otherwise monitoring 

compliance with the relevant standard continuously (e.g., EGUs not using CEMS or sorbent trap 

monitoring systems) repeat the relevant performance test if their fuel characteristics change, such that 

compliance with the applicable limit at the current level of control is no longer assured. Commenter 

17775 can think of no rationale for requiring sources that establish compliance with CEMS or sorbent 

trap systems to establish and demonstrate compliance with these other requirements. Commenter 17775 

notes that this assumption appears to be supported, somewhat, by the EPA’s few preamble statements. 

Commenter 17775 states the EPA must revise the rule and Tables significantly in order to make clear 

that only those EGUs that demonstrate compliance with a specific HAP or surrogate “through 

performance testing other than CEMS or sorbent trap monitoring systems,” must comply with these 

requirements, or if the EPA does not so revise the rule, the EPA must issue a new proposal and provide a 

purpose for what appear to be redundant and unnecessary requirements.

Commenters 17775 and 17790 state that the proposed monitoring and compliance provisions are 

difficult to interpret and inadequately explained. According to the commenters, many of the EPA’s 

proposed provisions simply require compliance “as applicable,” but the EPA nowhere clearly states 

when the requirements apply. In other cases, the proposed applicability seems clear, but the reason is 

not. Commenter 17775 cites an example, that the EPA clearly states in the preamble and in the proposed 

rule that EGUs that choose to comply with a surrogate limit must test for the corresponding HAP as 

well, and that EGUs that choose to comply with a HAP limit must test for the corresponding surrogate. 

The commenter states that the EPA never explains why such testing is relevant, what the EGU is to do 

with the results, or how the proposed requirement can be reconciled with other provisions clearly 

allowing EGUs a choice between a HAP or a surrogate limit.

Commenter 17871 states that the compliance requirements are duplicative and burdensome and would 

not provide any additional protection to public health or the environment.

Commenter 17928 states that the EPA’s proposed testing and compliance demonstration requirements 

are unnecessarily complex, confusing and burdensome.

Commenter 17795 requests that the EPA provide compliance demonstration flow charts for each of the 

categories of affected units. According to the commenter, when regulators conduct required permit 

inspections without meaningful flow charts and a clear understanding of multiple paths for compliance, 

there will be a tremendous amount of uncertainty for both the regulated community and the regulators. 

The commenter states that providing flow charts would make it easier to incorporate this type of 

information into existing Title V permits.

Response to Comment 16: The EPA has made changes in the final rule based on these comments to 

clarify and simplify the various monitoring and testing requirements. Please see the discussion in the 

final preamble. The EPA believes these clarifications eliminate unnecessary duplication and provide 

sources with clear options for demonstrating compliance.

Comment 17: Commenter 17820 recommends that the EPA provide clarification that units operating 

DSI technology will qualify for the option to use SO2 as a surrogate for HCl. Commenter further states 

that the compliance demonstration, recordkeeping and reporting requirements need clarification and 

further explanation. The commenter states that the applicability of many requirements, like fuel input 

limits and control device operating parameters are unclear, and in other cases, the applicability seems 

clear, but the purpose is not or is questionable. According to the commenter, this can be addressed by

providing additional clarity and explanation in the preamble to the rule or more specificity in the 
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regulatory text concerning requirements for performance testing, continuous parameter monitoring 

systems, fuel sampling and analysis, control device operating parameters, monitoring and reporting.

Several commenters (17868, 18424, 18963) question the EPA’s assumption that a large number of 

EGUs will use DSI to control acid gases. The commenter states that while DSI is a lower-cost option to 

reduce acid gas emissions, there is nothing in the history of its usage that suggests it is capable of 

achieving MACT acid gas emission limits in large EGUs burning medium to high sulfur coal. DSI is not 

in widespread use as a basic SO2 control system, and commenter 18963 notes that there have been no 

commercially demonstrated applications of DSI for the control of HCl from coal refuse-fired CFB units. 

Commenter 17868 questions the EPA’s assumption that the 3-year compliance schedule is achievable 

based on the use of DSI systems rather than FGD. Commenter 18424 also questions the EPA’s 

projection that a large number of EGUs will use DSI to control acid gases, and the use of these controls 

will increase the use of high-sulfur coals. According to the commenter, the EPA’s own consultant, 

Sargent and Lundy, has recommended not employing DSI on units burning coal with greater than 2.0 

Ib/MMBtu sulfur content. The commenter states that more than 80 percent of coal mined in Indiana 

exceeds 2.0 lb S02/MMBtu, and it seems unlikely that utilities burning Indiana coal will utilize the 

lower cost DSI technology and will either install/upgrade scrubbers or retire coal-fired units where 

scrubbers are uneconomical. The commenter states that few utilities will install DSI when other 

regulatory requirements, such as the SO2 emission reductions under CSAPR, are taken into account.

Response to Comment 17: A unit must use FGD in order to qualify for use of the SO2 surrogate, for the 

same reasons as stated in the proposed rule. If a source uses DSI and FGD, then that unit would qualify. 

The Agency estimates an additional 329 EGUs will choose some form of acid gas control by 2015; 

should an owner or operator find DSI unsuitable, he or she could choose from other approaches, 

including FGD or FBC with reagent injection. With respect to the remaining general concerns about the 

clarity of the monitoring and testing provisions, please see response to Comment 16, directly above.

Comments related to our assumptions with regard to DSI are responded to in the preamble to the final 

rule.

Comment 18: Commenter 17821 states that the EPA needs to revise the description and definitions of 

the IGCC APCD to account for upstream fuel cleanup and/or pollution prevention measures. The 

commenter states that for example, the technology used in IGCC units directly removes contaminants 

(such as particulate, Hg, non-Hg metal HAP, sulfur, chloride) directly from the fuel stream of IGCC 

units. According to the commenter, in this respect, IGCC is more akin to a natural gas-fired combined 

cycle unit, since it burns a syngas, which is cleaner than the coal combusted in a pulverized coal unit. 

According to the commenter, the EPA should reflect that IGCCs use upstream gasification/fuel clean-up 

(for example, AGR, SRU, PM scrubber) in the same way that coal-fired EGUs are credited for postcombustion or other air pollution control equipment such as SCR, ESP, and FGD. The commenter states 

that it makes no sense for IGCC to have additional testing burdens if reduced testing programs are 

allowed for coal-fired units with APCD. According to the commenter, the EPA recognizes that an IGCC 

unit is a distinct type of electric generating unit by proposing a separate subcategory for IGCC units, and 

the EPA needs to further acknowledge the process differences between IGCC units and PC units by

providing clarification that for purposes of this MACT the affected facility is the combustion turbines 

and any emission limitations apply to the heat recovery steam generator HRSG stack. Commenter 

recommends that the EPA needs to provide further clarification that all upstream fuel clean-up in the 

IGCC process qualifies as control equipment, thereby not putting any additional testing burdens on 

IGCC units when reduced testing is allowed for coal-fired units with add-on pollution control

equipment.
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Commenter 19114 states that for IGCC units, the EPA should clarify the use of heat input and 

generation output terminology to account for (1) differences between coal-based (gasifier feedstock -

based) and syngas-based heat input; and (2) differences between syngas-based and natural gas-based 

output during co-firing operations.

Response to Comment 18: The final rule does not establish different testing frequencies based on the 

presence of add-on controls, so the concerns raised by Commenter 17821 are no longer relevant. As the 

final rule contains definitions for coal-fired electric utility steam generating unit, integrated gasification 

combined cycle electric utility steam generating unit, and natural gas-fired electric utility steam 

generating unit in §63.10042, there is no need for additional clarification. According to the definitions. 

an IGCC that co-fires syngas derived from either coal or solid oil fuel with natural gas and get more than 

10 percent of the average annual heat input during any of 3 consecutive calendar years or more than 15.0 

percent of the annual heat input during any calendar year from syngas, it is an IGCC electric utility

steam generating unit.

The commenters concerns about EPA not accounting for pre-combustions practices that remove HAP 

from the syngas are unfounded. Both the input and output based standards applicable to EGUs are 

production based limits. The EPA does not determine how a source will meet the standard only that the 

HAP emissions (or surrogate emissions) coming out of the stack must not exceed the standard. If a 

syngas production process removes sufficient HAP before combustion, the HAP concentration coming 

out of the stack should be compliant with the standards, perhaps even without the installation of add-on

controls.

Comment 19: Commenter 17867 states that the EPA should revise and/or clarify some aspects of the 

rule.

a. Adjustments to the provisions concerning testing, initial and continuous compliance with the 

standards including:

i. The frequency of non-Hg metals and HCl testing should be extended if consecutive testing 

shows emissions meet the standard.

ii. If a source elects to use PM as a surrogate, the emission limit should be established during the 

performance test to ensure it correlates with either total or individual non-Hg 

metal HAP emissions.

iii. Filterable PM, as used by the EPA in the final Industrial Boiler MACT, is the appropriate 

standard to use as the non-Hg metals surrogate.

iv. The EPA should adopt work practice standards during periods of startup and shutdown for 

sources subject to the rule as used by the EPA in the final Industrial Boiler MACT.

v. The EPA should not require parametric monitoring for sources electing to show compliance 

by utilizing continuous emissions monitoring systems.

b. The EPA should allow states to request equivalency determinations based on state rules that cover 

the same pollutants, but with different control requirements and timing
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Response to Comment 19: For the issue raised in item (a)(i), please see the discussion of the LEE 

provisions in the final preamble. For items (a)(ii) and (iii), the final rule establishes a filterable PM 

emission limit as a surrogate to the non-Hg HAP metals standards. This limit applies to all sources as an 

option, and is not established on a case-by-case basis. For the issue in item (a)(iv), the final rule requires 

the source to meet a work practice limit rather than a numerical emissions limit during startup and 

shutdown periods. See preamble for discussion. For the issue in item (a)(v), the final rule does not 

require parametric monitoring where a CEMS is used to demonstrate compliance. For item b, these 

standards apply as federally enforceable standards. A Part 70 operating permit may provide for certain 

streamlining of applicable requirements, consistent with the applicable guidance and requirements that 

govern the Part 70 program.

Comment 20: Commenter 17881 states that the requirements of section 63.10031 should not apply to 

start-up/shutdown and flame stabilization fuels.

Comment 21: Commenter 17928 requests the EPA to provide clarification on the compliance 

requirements for units that may change from being “natural gas-fired” to “oil-fired”. According to the 

commenter, the proposed rule is unclear with regard to how much time the EPA would allow a newlydesignated oil unit to schedule and conduct initial performance tests to demonstrate compliance with the 

applicable standards.

Response to Comments 20 - 21: While the rule no longer requires compliance with emissions limits 

during periods of startup or shutdown, the rule maintains reporting requirements associated with the 

work practice requirements during those periods.

8. Cannot meet compliance deadline.

Comment 22: Commenter 18023 indicates that the requirement in section 63.10005(g) to demonstrate 

initial compliance for existing sources no later than 180 days after the compliance date is problematic 

for sources that may be in an outage or temporarily not operating on the compliance date. Commenter 

18023 states the EPA should clarify that compliance demonstrations must be complete within 180 days 

after the compliance date or, if the unit is not operating on the compliance date, then 180 days after the 

unit begins operation. Commenter 18023 further states that given the concerns that the proposed rule 

provides inadequate time to install controls, it is likely a number of utility units will be shut down on the 

compliance date.

Commenter 17714 states that the 3-year compliance deadline could be problematic because utilities 

must also consider the potential impact of the GHG NSR permitting requirements that could be triggered 

for large emission control projects, especially wet flue gas desulfurization projects. The commenter 

states that the “Tailoring Rule” provisions can be triggered by some projects because of the required 

timing of emission control projects necessary to meet the emission limits of the proposed rule, thus 

initiating the GHG BACT analyses requirements during the permitting process. The commenter states 

that GHG BACT is a largely unchartered area for both the regulated community and the state regulatory

agencies and will likely create additional permitting delays. According to the commenter, these delays 

will be exacerbated by challenges to the permits by those seeking to minimize GHG emissions. 

Commenter recommends the EPA include an exclusion from the requirements to obtain construction 

permits, including greenhouse gases under the Tailoring Rule, for emissions controls needed for an 

existing unit to meet the emission limits of the Utility HAP MACT Rule.
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Commenter 17736 states that a 3-year compliance requirement is not feasible. Commenter disagrees that 

the data proposed in the regulation is complete and it relied on faulty assumptions and unproven 

technologies. According to the commenter, compliance and implementation requirements under the 

proposed Utility MACT Rule are unreasonable and overly burdensome for the regulated community.

Response to Comment 22: The rule maintains the requirement for existing EGUs to demonstrate initial 

compliance within 180 days after the compliance date of the rule. Source owners or operators have the 

ability to schedule equipment installation, if needed, as well as EGU operation so that the requisite 

emissions demonstration can be completed on time. Should an owner or operator find that despite his or 

her best effort to meet the compliance date additional time is required to install controls, he or she can 

request up to a 1-year extension from the Administrator.

Some commenters thought that EPA permitting could cause delays in implementing this rule. The EPA 

recognizes that, following the vacatur of the new source review (NSR) pollution control project 

exemption in New York v. EPA, 413 F.3d 3, 40–41 (D.C. Cir. 2005), pollution control projects, 

including pollution control projects constructed to comply with this rule, have the potential to trigger 

NSR permitting. Based on an analysis done in 2005 that looked at SCR and FGD for CAIR compliance, 

but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR 

requirements would not significantly impact the construction of pollution controls that are installed to 

comply with this rule. In addition, it is very unlikely that pollution control projects would cause GHG 

increases that would exceed the 75,000 tons per year threshold either as a result of either chemically 

manufacturing GHGs or as a result of parasitic load. The EPA concludes therefore that there will be no 

significant impacts on timing from NSR for any pollution control projects resulting from this rule. 

Should NSR be triggered it would at most be for just a few of the projected control installations. In the 

limited circumstances where pollution control installations under the Mercury and Air Toxics Standards 

may trigger NSR, we also note that an expedited permitting process can occur with sufficient time to 

obtain permits and achieve emission reductions. For this reason, we strongly encourage permitting 

authorities to expedite permitting for any such projects, which are likely to be very limited in number.

Some companies may construct replacement generation as a compliance strategy. State pre-construction 

permitting requirements depend upon each individual state. Some states do not require pre-construction 

permits while some others require public utility commission (PUC) approval. For states obtaining PUC 

pre-approval for cost recovery, authorization typically averages seven months and is obtained usually

within one year.18 Furthermore, while PUC approval is necessary to recover investment costs through 

rate payers, it is not a prerequisite for obtaining credit or performing conceptual studies. 

Comment 23: Commenters 17689 and 17790 state that the DSI technology can achieve the levels of 

reduction necessary on EGUs using high chlorine eastern bituminous coals to meet the proposed MACT 

HCl limits. According to the commenters, the alternative control option of FGD cannot be timely 

installed to meet the proposed compliance deadline as the EPA admits.

Commenters 17689 and 17886 state that the EPA’s determination that over 56 GW of needed DSI 

technology can be installed in time to meet the compliance deadline raised issues related to whether the 

installation of dry scrubbers could be accomplished in time and whether the additional demands for the 

dry sorbent would be available in time.

 

18 “Public Utility Commission Report” March 31, 2011 by M.J. Bradley & Assoc LLC; web site: 

http://www.epa.gov/ttn/atw/utility/puc_study_march2011.pdf
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Commenter 17790 disagrees with the EPA’s assumption that DSI with fabric filters will provide 

compliance-level reductions to meet the very stringent acid gas limits at all units. Without data that 

demonstrates otherwise, Commenter 17790 expects compliance with this proposed rule will require 

FGD on over 60 percent of coal-fired EGUs.

Commenter 17765 states that the DSI technology has not been widely used or tested to date and there is 

little or no satisfactory evidence which demonstrates that an actual unit can comply with all of the 

proposed NESHAP using DSI without a scrubber.

Commenters 17765 and 17820 believe that without further testing to confirm that DSI technology will 

work without a scrubber, it is highly unlikely any utility’s compliance strategy will rely only 

on DSI technology. The lack of experience with the DSI technology also highlights the problem with 

setting emissions standards pollutant-by-pollutant, as there is also insufficient data to confirm whether a 

unit using DSI with or without a scrubber can meet all three standards on a continuous basis without 

creating antagonistic impacts to the overall effectiveness of other control technologies.

Commenter 17820 states that to satisfy the HCl emission limit of 0.002 lb/MMBtu as proposed in the 

rule, DSI may be a viable option at a reasonable cost for coal with chlorine < 300 ppm. The commenter 

states that for coal with chlorine between 300 to 1000 ppm, DSI could still be used but variable 

operating costs will increase substantially, while for coal with chlorine greater than 1500 ppm, removal 

requirements will be difficult and variable operating costs could approach $8-$10/MWh or higher. 

According to the commenter, some companies that burn certain eastern bituminous coals may not be 

able to achieve compliance with the acid gas standards using DSI, because the higher chlorine content 

found in these coals necessitates a more aggressive control technology to remove higher levels of HCl. 

According to the commenter, to comply, these companies may have to install wet FGD, which presents 

major challenges to the 3-year compliance deadline that the EPA optimistically asserts companies will 

be able to meet.

Commenter 17820 states that the EPA assumes that an adequate supply of dry sorbents is readily 

available in the RIA, yet sorbent production would need to increase by 10 to 20 times in order to meet 

the EPA’s projected DSI demand. The commenter states that it is uncertain whether suppliers will be 

willing to increase production without concrete assurances of future demand through mechanisms like 

take-or-pay contracts; uncertainties about the future power market and potential problems from DSI use 

will make companies’ decisions about employing DSI complex and lengthy, and some may be reluctant 

to take on large take-or-pay obligations. The commenter states that even assuming suppliers are willing 

to commit hundreds of millions for plant expansions that may be needed to increase supply, it will still 

take more than 18 months to ramp up dry sorbent production. The commenter states that there are also 

substantial questions about the Trona supply chain. According to the commenter, the sole regional 

supply of Trona from the Green River, Wyoming area takes two to four weeks to deliver, Trona is 

shipped by rail in sealed pressure discharge (“PD”) railcars that typically hold a little less than 100 tons 

of product, and Trona properties and feed issues limit the size of a plant’s storage silo to 200 to 300 tons. 

The commenter asserts that given the space constraints at many facilities, a large quantity of Trona will 

need to be stored in rail yards on the PD railcars, and it is unclear whether there are enough PD railcars 

to accommodate such an expanded use of DSI. The commenter states that if rail service is unavailable to 

a given power plant, then trucking the material to the site may cause additional logistic problems 

because of the large number of truck trips needed at substantially increased cost. The commenter also 

states that material suppliers recommend that Trona not be stored for more than one month because 

longer storage times may diminish the material’s effectiveness and negatively affect the product’s flow 

ability. According to the commenter, this storage restriction will have repercussions throughout the 
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supply chain. The commenter states that the RIA is overly optimistic about the use of DSI and, in turn, 

understates the cost of complying with the proposed MACT limits (because more units will need to 

install either a more expensive wet or dry scrubber). According to the commenter, consequently, the 

time estimated to comply with the proposed rule is also understated.

Commenter 17821 states that a number of technical issues must be adequately answered before utilities 

can proceed with widespread adoption of DSI technology. According to the commenter, the use of DSI

has substantial crippling impacts on other pollution control systems currently in use at utilities.

a. According to the commenter, increased mass loading combined with increased ash resistivity can 

increase PM emissions. The commenter states that calcium-based sorbents have higher inherent 

resistivity, making it very difficult to collect in an ESP and resulting in deteriorated performance. The 

commenter also states that sodium-based sorbents shave acceptable ash resistivity for applications 

in ESPs, but under certain conditions sodium bisulfate is formed. According to the commenter, sodium 

bisulfate has a sticky phase at temperatures above 330 oF-350 oF, and this sticky phase has caused 

significant operational problems in a number of units, causing plug gage of systems and components in 

the gas stream. According to the commenter, under certain conditions, sodium-based sorbents can serve 

as a catalyst to convert NO to NO2. This can cause an orange brown color in the stack plume

b. The commenter states that regarding fabric filters and DSI, there is not a sufficient number of 

medium-to-high sulfur coal burning units that are equipped with fabric filters to determine whether they

can operate reliably without experiencing degraded bag life from acid attack or H2SO4 dew point 

corrosion, plug gage and/or blinding. DSI for fabric filter protection is not an industry standard. 

According to the commenter, there are operational and reliability risks in installing fabric filters on 

large EGUs burning medium to high sulfur coals. The commenter states that the negative effect 

of SO3 from high sulfur coals on ACI for Hg control is well documented in DOE studies. According to 

the commenter, installing a fabric filter on a large EGU burning medium to high sulfur coals is not a 

simple “off the shelf” solution for Hg control;a fabric filter with DSI may hinder a unit’s ability to meet 

the proposed MACT limits for Hg and PM. The commenter states that in one test where both DSI and 

ACI were injected upstream of a polishing fabric filter, the addition of DSI caused the unit to need three 

times the normal amount of ACI to achieve the same level of Hg control. The commenter also states that 

in addition, for a large majority of DSI cases, retrofitting a fabric filter would be required, an installation 

that will take at least 30-35 months in general to complete; this is after the facility has the necessary 

approvals such as an air permit, specifications completed, and a contractor secured before it can actually

commence construction. According to the commenter, these steps could easily add several additional 

months; total project length including these other factors could easily be 42 months. The commenter 

states that in its proposed rule, the EPA has underestimated or not considered these additional burdens of 

installing fabric filters, activated carbon, and sorbent injection.

c. According to the commenter, companies may need to install other technologies such as wet FGD, 

which has an expected implementation time of 52 months after necessary permits and other approvals 

are secured. The commenter states that this point is critical given that the EPA finalized CSAPR in July, 

2011, with a compliance date of January 1, 2012, a quick turnaround that will force some companies to 

commit to FGD installation to meet SO2 requirements. According to the commenter, even if a company

were to decide on August 1, 2011 to install an FGD, which is four months before the Utility MACT is 

scheduled to be finalized, there is still not enough time to permit and install an FGD three years after a 

final MACT rule.
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d. Commenters 17821 and 17840 state that with injection rates of Trona at approximately 600 lb/hr, 

engineering studies have shown HCl removals at less than 20% with virtually no HF removal across a 

fabric filter. According to the commenters, the EPA needs to qualify the assumptions on how 

much DSI is required for acid gas removal to meet the emission limits required in this rule. The 

commenters state that there are not enough engineering data that both demonstrate compliance level 

removal rates and document accompanying balance of plant effects; for example, larger alkali injection 

rates can cause pH upsets in downstream systems and environmental controls. According to the 

commenters, the injection of Trona in an EGU generates NO2 which degrades activated carbon.

Commenter 17881 states that additional time is needed to thoroughly evaluate the feasibility of DSI, as 

such, considerable additional investigation on the widespread application of this technology is 

warranted. According to the commenter, the use of DSI will likely require a fabric filter to 

avoid NSR and PSD permits. The commenter states that while DSI may be installed in less than three 

years, engineering, permitting and constructing a fabric filter will, in fact, take longer, and that this 

concept is further complicated by any need to replace existing ash handling systems in order to 

accommodate the higher volume of wastes (i.e., fly ash and spent/unspent reagent) associated with DSI.

Several commenters (17756, 17758, 17790) are concerned that the EPA overestimated the number of 

DSI devices that will be used. Commenters 17758 and 17790 note that units burning eastern bituminous 

coals may not meet the acid gas standard using DSI; therefore they may use FGD instead.

Commenter 18037 states that the presumption that sorbent injection or dry scrubbing will be installed 

over wet scrubbing systems implies that the EPA is looking solely at this proposed rule and not the suite 

of rules the electric generating industry will be facing. According to the commenter, when considering 

all the rules, wet scrubbers may be the control of choice over dry systems and the installation time for 

wet scrubbers is significantly longer.

Response to Comment 23: As mentioned in the response to comment 17, the agency finds that a 

number of additional EGUs will choose some form of acid gas control by 2015; should an owner or 

operator find a particular approach such as DSI unsuitable, he or she could choose from other 

approaches, including flue gas desulfurization or fluidized bed combustion with reagent injection. 

Source owners or operators have the ability to schedule equipment installation, if needed, as well as 

EGU operation so that the requisite emissions demonstration can be completed on time. Should an

owner or operator find that despite his or her best effort to meet the compliance date additional time is 

necessary for the installation of controls, he or she can request up to a 1-year extension from the 

Administrator.

9. Request to modify compliance requirements.

Comment 24: Commenter 17800 requests the EPA to exempt EGUs from the annual tuning 

requirement in section 63.10021(a)(16)(iii) and (iv) if such units use a continuous tuning algorithm to 

optimize the air-to-fuel ratio, and minimize NOX and CO production. The commenter states that in 

section 63.10021(a)(16)(iii) and (iv) the EPA is requiring the annual inspection of systems controlling 

the air-to-fuel ratio and optimizations of CO and NOX consistent with manufacturer’s 

specifications. According to the commenter, while the EPA references air-to-fuel ratio, typically boiler 

operators use excess O2 to determine proper combustion; the general indicator of incomplete combustion 

is high CO levels or unburned carbon in the fly ash, and operators use O2 set points to insure combustion 

has been optimized. Currently Commenter uses a neural network computer system to optimize the boiler 

combustion and minimize NOX and CO production; this system continually tunes the boiler combustion 
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process based on boiler operating parameters. According to the commenter, an annual optimization is 

unnecessary, as this is being done continuously.

Response to Comment 24: The EPA has decided not to include alternate work practice standards, such 

as a CO requirement, but has adjusted the language in the final rule to recognize the value of automated 

boiler optimization tools such as neural-net systems. The EPA has reviewed the comments on the 

proposed frequency of tune-ups, and made adjustments in the final rule. See further detail in the 

response below on the timing of tune-ups required under the final rule.

Comment 25: Commenters 17800 and 17881 state that in section 63.10021(a)(16)(ii) the EPA is 

requiring flame pattern inspections and that to make this happen, the EGUs need to install observation 

ports. Commenters request the EPA to exempt them from this requirement as inspecting the flame would 

not provide useful information relative to optimizing CO and would be extremely expensive, as tubing 

in the boiler would have to be reconfigured to accommodate the port. According to the commenters, in 

some wall-fired coal boilers, there are observation ports which can be used to determine if flames are 

impinging on the furnace walls. The commenters state that while a qualitative evaluation can be made 

regarding the general appearance of the flames (bright, dark, etc.), observation of the flames is rarely, if 

ever, used to access the impact on NOx or CO; for instance, flame observation on cyclone and coal-fired 

tangential boilers would not generally be useful. According to the commenters, the cyclone itself is the 

burner and the flame is opaque;, in general, the furnace of a tangential boiler is essentially the burner as 

well, and in the case of a coal-fired tangential boiler, the furnace is filled with a spiraling flame that 

covers most of the furnace. The commenters state that the EPA has apparently recognized this by

requiring that the flame pattern must be inspected “as applicable.” Nevertheless, Commenters request 

exemption for those boilers that do not currently have observation ports or it can be shown that 

observation of the flames in these boilers provides no useful information relative to minimizing CO.

Response to Comment 25: The EPA has modified the rule to state that if specific aspects of the 

inspection process are not applicable to a given boiler type, then those elements of the basic procedure 

would be adjusted according to best combustion engineering practice for that burner type.

Comment 26: Commenter 17818 states that for compliance, it appears that the alternate limit in this 

case (of alternate Hg limits) would require both a simultaneous significant emissions reduction to the 

levels of the primary limits and a significant reduction in unit heat rate [when an Hg emission rate limit 

of 1.0 lb/TBtu or 0.008 lb/GWh and the apparent correction factor (unit heat rate) of 8000 BTU/KWh is 

applied]. According to the commenter, this scenario seems unlikely for most owners and operators.

Response to Comment 26: Conversion errors made in the proposed limits were brought to our attention 

and corrected. We believe that the final limits do not contain the issues noted by commenter.

Comment 27: Commenter 17821 states that existing IGCC units should be able to use SO2 as a 

surrogate for acid gases (e.g., HCl) as an alternative to measuring HCl since SO2 emissions are 

controlled upstream via acid gas scrubbing to reduce sulfur. Commenter collected SO2 data during the 

ICR test at Wabash River IGCC and provided that data to the EPA as requested. Commenter has 

submitted to the EPA well over a decade of SO2 data under the Acid Rain Program. According to the 

commenter, at a minimum, the EPA could set an SO2 surrogate limit to be the same value as other coalfired units, or the EPA could use data from the two existing IGCC sites. The commenter states that the 

EPA should not limit having SO2 as a surrogate just to units with a FGD system when other proven and 

effective SO2 emissions reduction technology exists and states that as an example, General Electric’s 

gasification technology, currently being installed at the Edwards port IGCC, uses water scrubbing of 
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syngas at high temperatures which removes water soluble acid gas compounds such as HCl, HCN, HF, 

and Cl2. The commenter states that the emission controls for the Wabash River and Polk Station IGCC 

units have their own variations, which are distinctively different from conventional coal-fired units. 

Commenter proposes that new and existing IGCC units should have the opportunity to use SO2 as a 

surrogate measurement of acid gases.

Response to Comment 27: The EPA has acknowledged that IGCC EGUs qualify for the alternate SO2

compliance alternative in the final rule and has based such limits on the two operating IGCCs.

Comment 28: Commenter 17881 states that to measure the mass flow of air and fuel to maintain a 

desired ‘ratio’ does not work. The commenter states that facilities will periodically calibrate flow 

transmitters on the air measurement system and coal feeders on some plants, and boiler firing controls 

are based on maintaining boiler drum pressure and trim air in order to maintain a desired excess O2

leaving the boiler; enough coal is put in to combust and maintain pressure, and enough air is put in until 

a desired excess oxygen is achieved leaving the boiler. The commenter states that coal properties vary 

greatly (heating content and moisture), so coal feed rates at a desired load can vary greatly, and 

consequently, the mass of air entering the boiler varies greatly.

Response to Comment 28: The EPA recognizes the inherent difficulties of combustion optimization 

and has modified the rule language to allow more flexibility in conducting tune-ups and maintaining 

combustion controls, including incentivizing the use of neural net combustion optimization systems.

Comment 29: Commenter 17902 states that each power plant is anticipated to require at least one 

additional full-time person to perform necessary MRR compliance demonstration tasks that are required 

on a daily, weekly, monthly, quarterly and semi-annual basis. According to the commenter, this does not 

include the external resources and costs associated with stack testing or fuel analyses. The commenter 

states that these MRR requirements are duplicative and excessive and would provide no further 

assurance of compliance with the emission limits in the Utility MACT Standard.

Response to Comment 29: The EPA has decreased the frequency of required testing and work practices 

to levels that are expected to significantly reduce the issues raised by the commenter.

Comment 30: Commenter 17914 states that while many of the proposed provisions of the rule are 

technically achievable, there are some limits which are not sustainable in day-in/day-out operation at 

EGUs which face a complex mix of fuel variability, combustion management, turbine integration and 

Air Quality Control Systems(AQCS) performance optimization challenges and constraints. Commenter 

requests that the EPA reconsider several aspects of the rule, which as proposed would severely hinder 

reliable, long-term operation of these key assets in our nation’s energy infrastructure and seriously

jeopardize the addition of new, more efficient fossil fuel EGUs.

Response to Comment 30: The EPA believes that variability has adequately been addressed in setting 

the MACT limits in the final rule as explained in response to other comments in the final rule record.

Comment 31: Commenter 17930 states that the EPA has provided no evidence that the amounts of ACI

reductions that have been achieved are not the maximum capabilities that can be achieved at those units. 

According to the commenter, the ACI technology cannot deliver results that even approach the degree of 

control or consistency that the EPA claims. Using the same ACI control technology to the fullest extent, 

and operated in the same manner, over multiple units, Commenter has experienced mercury emissions 

reductions ranging from 30 percent to 80 percent - far below the EPA’s predicted reductions of over 90 
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percent and nowhere close to the consistency that would justify setting a limit such as that proposed by

the EPA.

Commenter 18498 disagrees with the EPA proposal not to use technologies other than ACI as the basis 

for a beyond-the-floor analysis related to Hg emissions. The commenter states that Mercury Oxidation 

System Technology and addition of calcium bromide during the combustion process are control options 

that are being examined by Commenter and others. According to the commenter, given the stringency of 

the proposed standards and emerging technologies, the EPA should not limit the proposal to ACI and 

DSI. Commenter recommends that the EPA consider additional options that would allow for compliance 

while protecting grid reliability and reducing retrofit costs passed to consumers; for example, a viable 

option would allow a facility to operate at a reduced capacity factor rather than being required to retire 

or achieve the standards in the proposed rule. The commenter states that allowing a facility to adopt a 

capacity factor of 10 percent or less would achieve the desired result of reducing emissions but would 

not place the EPA in the position of dictating energy generation profiles and that such an option would 

help ensure reserve capacity for the grid and at the same time reduce emissions. According to the 

commenter, the EPA has set a standard that will be difficult for sources to comply with using technology

the EPA has recommended in the proposed rule. For example, states the commenter, using DSI 

technology to meet the acid gas HAP emission limits actually makes it more difficult to comply with the 

PM emission limits because the dry sorbent injected into the flue gas stream reacts with SO2, creating 

sodium sulfate, a particulate that must be captured by the PM control device in addition to the other 

particulates in the flue gas stream. Commenter suggests that the EPA revise its proposal and set a 

new MACT floor based on the best performing 12 percent of units overall, rather than the best 

performing 12 percent of units for each pollutant. According to the commenter, using a methodology

that considers emissions limitations for all regulated pollutants actually achieved in practice by the best 

performing 12 percent of sources will result in a MACT standard that complies with section 

112(d)(3)(A), and abandoning the pollutant-by-pollutant approach will take into account the interactions 

between pollution control devices. The commenter states that although DSI has produced some short 

term promising results, there are no long term units operational for prediction of potential unintended 

environmental concerns, but it is known that sodium bicarbonate from the DSI process is a base that will 

be disposed with coal ash, in many instances in ponds. The commenter states that where a base is added 

to the pond, the water will necessarily have to be treated with an acid to decrease the pH in the pond; at 

this time, there is insufficient information to know either the amount of treatment that will have to occur 

or the ramifications to existing ponds, and thus, at this time there is insufficient information to assess 

whether DSI will be an appropriate long term solution.

Response to Comment 31: The EPA believes that the results from ICR testing for units in the low Btu, 

virgin coal subcategory that were also using ACI, in combination with the publically available 

information from the DOE/NETL mercury control demonstration program, supports that consistent 

mercury removal levels > 90% are achievable when the correct sorbent is properly used (i.e., injected 

corrected and at the correct rate). The EPA understands and acknowledges that control technologies 

other than ACI are also available that can achieve deep reductions in mercury control. This rule does not 

mandate the use of any particular control technology (such as ACI). The comments on the pollutant-bypollutant approach have been addressed elsewhere in the response to comments document. 

Comment 32: Commenter 17702 states that the EPA’s proposed compliance requirements are overly 

burdensome and should be modified. According to the commenter, some of the compliance 

requirements may result in periods of noncompliance by EGUs that may be capable of complying with 

the emission limits under normal operations.
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Response to Comment 32: The final rule makes a number of changes to streamline the compliance 

requirements. Please see the final preamble for further discussion. 

10. Need clarification on output-based limitations.

Comment 33: Commenter 17385 states that Tables 1 and 2 of the NESHAP list output-based limitations 

in units of mass of pollutant per electrical output (lb per MWh, lb per GWh). The commenter states that 

there is no legend to clarify net or gross bases or if only electrical output is included but that in the 

Federal Register preamble discussion of the NESHAP limitations, Table 10 (76 FR 25027) does include 

a legend that clarifies units and their bases.

Response to Comment 33: The rule requires electrical output based on gross generation; all Tables 

have been updated to specify gross generation.

11. Improve sustainable efficiency.

Comment 34: Commenter 17620 states that the EPA should develop a record in the upcoming EGU 

GHG regulations that would enable accurate measurement and determination of sustainable efficiency 

improvements. According to the commenter, the record in this rulemaking is not sufficient to establish 

such procedures.

Response to Comment 34: Any GHG related comments are outside the scope of this rulemaking.

12. Support work practice standards.

Comment 35: Commenter 17790 supports the use of work practices standards included in the 

proposed EGU MACT to ensure compliance with the proposed organic HAP. Commenter also agrees 

that emissions from coal-fired boilers will likely be less than detection limits for most organic HAP, and 

further comments that this testing can be expensive and because of the low levels, results can be 

unreliable. According to the commenter, proper combustion will ensure low emissions of 

organic HAP and requiring proper combustion is the best means of control.

Response to Comment 35: The EPA acknowledges the support and has retained in the final rule a work 

practice standard for organic HAP emissions.

13. Request to modify or remove work practice standards.

Comment 36: Commenters 17638 and 17818 request that the EPA establish a work practice standard in 

lieu of emission limits for organics and dioxin/furans. Commenters disagree with some of the individual 

elements of the work practice standard, such as the 18-month work practice interval and the requirement 

to inspect flame patterns as a means of determining optimized combustion. Commenter 17818 further 

states that conducting burner inspections will often include a requirement to install scaffolding in the 

furnace, to gain access to the burners, and then removal of the scaffolding. According to the commenter, 

this is a process that is both expensive and time consuming, as well as generally not required except to 

perform burner inspections or perform repairs, and such activities are generally not done on an annual 

basis, but rather are less frequently performed during periods of extended maintenance 

shutdown/inspection. Commenters proposed that the 18-month maximum outage interval should be 

extended to 24-30 months and the inspection of flame patterns for EGUs for the purpose of tuning 

burners is improper. EGUs can have 50 or more types of burners, and not all flames are visible. 
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Inspecting flame patterns is more useful for industrial boiler practices in which an observer peers 

through a glass at the burner and then makes changes to nearby controls to optimize the flame. 

Commenter 17638 supports a CAM-type approach regarding the establishment of work practices, which 

provide for reasonable assurance of the unit operation in lieu of a “one size fits all” approach.

Several commenters (17689, 17756, 17928, 17813) state that the 18-month interval between inspections 

is not consistent with established utility practice regarding periodic outages for maintenance and repair. 

Commenters recommend a 36 month compliance period. According to the commenters, utilities should 

be able to implement their own best management practices if they are demonstrated to be best for the 

unit. For small systems, such as many rural electric cooperatives, state the commenters, many parts may

not be inventoried and may take several months to acquire, and to complicate matters, units may be in 

periods of high need, such as during summer or winter peaking when replacement parts become 

unavailable, thus making shutdown for repair not feasible due to reliability or other paramount concerns. 

In such cases, commenter 17689 believes utilities should be given reasonable time to optimize 

considering the electric demands on the system.

Commenter 17756 states that the work practice standards for EGUs to address any emissions of 

organic HAP and dioxins do not reflect some of the practical realities of operating an EGU.

Several commenters (17761, 17767, 17795) state that the proposed work practice standards regarding 

organic HAP will have a detrimental impact on the outage schedules of applicable units since every unit 

would have to perform an onerous inspection and tune-up every 18 months. According to the 

commenters, this scheduled tune-up would require additional outages in between planned major 

maintenance overhauls further affecting unit availability, overall system reliability, and generating costs. 

The commenters state that the EPA’s ICR test data demonstrated that the majority of applicable units 

emitted non-detectable levels of organic HAP, even under the utility industry’s existing work practice 

standards and maintenance outage cycles. Commenters 17761 and 17795 suggest that there is no need 

for increased scheduled outages and inspections (every 18 months) for units already emitting nondetectable levels of these HAP and, as such, these standards should be removed from the final rule. 

Commenter 17767 recommends an extension beyond 18 months.

Commenter 17851 states that the EPA should not set a dioxin/furan standard or a non-dioxin organic 

HAP standard. Doing so will not reduce the emissions of organic HAP.

Commenter 17851 states that the EPA should not set a dioxin/furan standard or a non-dioxin organic 

HAP standard and that doing so will not reduce the emissions of organic HAP.

Commenter 17930 states that the EPA should allow utilities to document their own operating practices, 

including testing, data collection, and inspection schedules. According to the commenter, each utility 

has developed documentation practices that best, and most efficiently, serve that particular plant and 

company and to require other documentation practices would be an unnecessary burden on already taxed 

utility operators. The commenter states that there are many instances where emissions are below 

detection levels and should not be used as a basis to establish a work-practice standard.

Several commenters (19536, 19537, 19538) states that the work practice standard should require that all 

EGUs install real-time software to continuously optimize boiler combustion and perform soot cleaning.

According to the commenter, these systems continuously monitor the combustion process to determine 

the optimal balance of fuel and air flows in the furnace to position dampers, burner tilts, overfire air and 

other controllable parameters at their optimal setting. The commenter states that these systems are 
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already in widespread use throughout the utility industry and have the added benefit of improving 

efficiency, thus reducing operating costs. According to the commenter, a boiler tune-up is not adequate 

to assure continuous minimization of organic HAP. The commenter asserts that the work practice 

standard assumes that all organic HAP are created by incomplete combustion and that this assumption is 

incorrect, especially for dioxins which are formed after the combustion process and whose emission rate 

depends in part of coal chlorine content.

Response to Comment 36: The EPA has reviewed the comments on the proposed frequency of tuneups, and made adjustments in the final rule. Under the final rule, the tune-up must be conducted at each 

planned major outage and in no event less frequently than every 36 months, with an exception that if the 

unit employs a neural-network system for combustion optimization during hours of normal unit 

operation, the required frequency is a minimum of once every 4 years (48 months). The EPA believes 

the minimal recordkeeping associated with this work practice standard is not unduly burdensome. The 

EPA does believe that a work practice standard is the best approach for controlling organic HAP, and 

thus has retained the work practice standard in the final rule.

14. Delegation to states (compliance dates).

a. General support.

Comment 37: Commenters 17758 and 17909 indicate that allowing states to seek delegation of the 

section 112 program will provide important compliance flexibility (particularly related to timing of 

retirements, repowerings, and installations of control equipment) for those units and utilities that have 

already made investments consistent with state environmental programs, and failure to allow state 

delegations could undermine these investments. Commenter 17758 further indicates that if states can 

demonstrate that overall emissions reductions are equivalent or greater than those that would be 

achieved by the proposed rule, the EPA should delegate the section 112 program to these states, even if 

the state emissions reductions would not necessarily occur on the same schedule.

Commenter 17798 states that the EPA needs to be aware that states with existing Hg rules may request 

approval of their rules in meeting the EGU NESHAP. According to the commenter, to this point, 

Wisconsin, under state statute, is required to establish state rules for implementing any federal NESHAP 

requirement. Commenter requests the EPA to include a process in the NESHAP rule which will 

facilitate states in establishing rules as equivalent to the EGU NESHAP. For Hg emissions and other 

accumulative impact pollutants, the commenter suggests equivalency can be measured by comparing 

total emissions on a statewide or corporate utility basis.

Commenter 17719 is concerned about existing sources subject to state-only rules for the reduction of Hg 

and other air toxic emissions. Commenter does not want the promulgation of the MATS to undermine 

the tremendous amount of work invested in creating a program to curb emissions within a reasonable 

timeframe, protecting both the economic viability of the state and the health of the public. Commenter 

seeks to make use of temporal flexibility, authorized under CAA section 112(i)(3) in obtaining 

delegation of the MATS to preserve a hard negotiated comprehensive Colorado-specific program 

designed to yield greater emission reductions than the MATS alone. The commenter states that the state 

has taken three separate actions to reduce the emissions of criteria pollutants and HAP from coal-fired 

utility boilers.
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a. The Colorado Air Quality Control Commission (AQCC) adopted state-only Standards of Performance 

for Coal-Fired Electric Steam Generating Units into Regulation No. 6, Part B, Section VIII on October 

18, 2007;

b. The Colorado Legislature passed House Bill 10-1365, the “Clean Air-Clean Jobs Act” (“CACJA”), on 

April 19, 2010; and

c. The AQCC adopted revisions to the Regional Haze State Implementation Plan (“RH SIP”) in 

Regulation No. 3, Part F on January 7, 2011.

According to the commenter, under these rules, the state has successfully negotiated both emissions 

standards and shut down provisions with Colorado utilities to reduce the emission of criteria and 

hazardous air pollutants on a timetable that protects the public interest. The commenter states that 

the CACJA in particular resulted in extensive negotiations to ensure the reliability of the energy grid 

while encouraging the use of renewable and cleaner energy sources, taking into consideration cost 

impact to customers, necessary transmission system changes, unit outage schedules and outage 

contingencies, and construction timeframes, and that ultimately, the CACJA will promote job growth 

and reduce air emissions within the State.

Commenter 18034 states that the state agencies that receive delegated authority for the final NESHAP 

rule will be tasked with enforcing the rule. According to the commenter, some of the issues will directly

impact its ability to appropriately enforce the rule, and the EPA must consider how state agencies will be 

expected to enforce the rule.

Comment 38: Several Commenters (17758, 17873, 17756) state that the EPA should allow states to 

seek delegation of the CAA section 112 program, as authorized by the Act. Section 112(l) of the CAA

allows a state to seek delegation of the section 112 program. The commenters note that in the proposed 

rule the EPA acknowledges that a number of state and local program have plans to address 

environmental issues and that these plans may lead to reductions in HAP emissions equivalent to or 

greater than the proposed rule.

b. Support for specific state/local or EGU.

Comment 39: Commenter 18019 states that they encourage the EPA in the final MACT rule to make 

clear that Oregon has regulatory flexibility to address the unique Boardman case. In particular, the 

commenter asks the EPA to expressly recognize that Oregon could obtain delegated authority under 

section 112(1) to implement the MACT consistent with the Boardman 2020 plan, where the plant will 

achieve mercury reductions both ahead of and in excess of any federal standard, meet the acid gas and 

organics standards in advance of the MACT requirements, and cease coal burning entirely by 2020. 

Commenter urges the EPA to expand on this concept in the final rule and make clear that plans, such as 

the Boardman 2020 plan, coupled with the early mercury reductions, would meet the “no less stringent”

test for state delegated programs.

Comment 40: Commenter 17867 states that early termination of coal operations and interim controls 

will result in lower aggregate emissions of haze causing pollutants than those projected under a much 

more expensive control package that would have otherwise been required to run the plant indefinitely in 

compliance with haze-related standards. According to the commenter, the EPA’s proposed 

Utility NESHAP Rule is one of several the EPA rules that will affect the nation’s coal fleet, including 

the Boardman facility. The commenter states that the Boardman plan requires Commenter to install 
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pollution controls to reduce interim emissions of NOX by about 50 percent through the installation of 

advanced combustion controls, and to reduce SO2 emissions through a combination of lower-sulfur fuel 

and the installation of a DSI system. According to the commenter, under the Boardman 2020 plan, all 

emissions associated with coal-firing at the Boardman Plant will end by 2020, resulting in dramatic 

reductions in all conventional pollutants (SO2, NOX, PM), Hg, other HAP, and GHGs. In addition, the 

Boardman 2020 Plan establishes a path toward significant reductions in CO2 emissions in advance of 

regulation by mapping a careful and reasonable transition away from coal-fired generation at this 

facility. According to the commenter, the EPA regulations would require pollution upgrades in order to 

meet air quality, water quality or waste management requirements, and once these regulations are 

finalized, a key question facing electric utility companies is whether to retrofit and run coal units into the 

future or to retire these units. The commenter states that these decisions are challenging given continued 

uncertainty about federal climate policy and that the EPA could resolve this dilemma by establishing a 

clear regulatory pathway that allows the state to preserve a Boardman-like plan and reconcile it with the 

requirements of CAA section 112. Commenter recommends that the EPA consider providing commenter 

and ODEQ specific guidance for a state plan containing the following elements, that if offered by the 

ODEQ in connection with other elements needed for compliance assurance, would be considered by the 

EPA as potentially meeting the equivalency requirements of section 112 and subpart E:

a. A Hg standard more stringent and imposed earlier than the federal rule. The commenter states that the 

Oregon Utility Mercury rule was promulgated in 2006 and requires Boardman to meet an aggressive 

standard of removal of at least 90 percent of the Hg emitted from the unit or a limit of Hg emissions to 

0.60 pounds per trillion BTU of heat input by no later than July of 2012; thus, Boardman would achieve 

Hg controls that are well below the EGU MACT proposed limits and have them installed at least 3 years 

early.

b. An acid gas standard the same as, or more stringent than, the proposed federal rule. The commenter 

states that to meet BART requirements for SO2, PGE is installing a control package that includes 

DSI technology, and anticipates the use of low sulfur coal; while installation has not been completed, 

and full scale testing to determine control effectiveness has not been done, based on preliminary

evaluations, commenter believes that the DSI technology is likely to have the collateral effect of 

removing acid gasses to achieve compliance with the standard.

c. The proposed section 112 work practices standard for dioxin/furans and for the non-dioxin/furan 

organic HAP. The commenter states that these are already contemplated under existing requirements for 

the Boardman Plant.

d. A slightly less aggressive limit for non-Hg metals. The commenter states that this might be either the 

existing PM emission limit of 0.04 lb/MMBtu (filterable) as a surrogate for non-Hg metals or slightly

relaxed individual or total metals limits. According to the commenter, while Oregon potentially could 

allow marginally higher emissions than the federal standard, the Oregon plan would require complete 

phase out of fossil fuels by 2020, which would result in significantly lower aggregate non-Hg metal 

emissions compared to continued operation in compliance with the MACT standard under the EGU 

NESHAP proposal.

e. A requirement that coal firing at Boardman be stopped by 2020, which would result in of the dramatic 

reduction in all HAP and other pollutants. Commenter believes such a set of requirements, which would 

contain some elements that are more stringent than the federal rule and others that are slightly less 

stringent, would – taken as a whole – be at least as stringent as the proposed federal rule. According to 

the commenter, given that delegations to date have been based on state regulations that are essentially 
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identical to the federal rules or contain more stringent requirements for particular pollutants (e.g., Hg), 

the EPA has not had an opportunity to provide the public with an analysis of whether an alternative state 

program may allow emissions for individual pollutants to exceed by a modest amount the EPA’s 

emissions limits so long as the state’s program obtains greater overall benefits. The commenter 

considers the Utility NESHAP Rule to be the perfect opportunity for the EPA to address this aspect of 

its delegation authority and provide guidance to the states regarding their demonstration of equivalency.

Commenter 18019 states that under “Boardman 2020” plan, PGE will install pollution controls to reduce 

interim emissions of nitrogen oxides by about 50 percent and sulfur dioxide emissions by 75 percent. 

According to the commenter, all coal-related emissions from the Boardman Plant will be reduced to zero 

with the end of coal operations in 2020. The commenter states that IRP in Oregon is a rigorous process 

for examining how to meet customer needs at the lowest cost and risk. According to the commenter, IRP 

provides substantial opportunity for public involvement during the preparation and review of a utility’s 

plan; in its IRP, a utility must assess the performance of candidate resource portfolios under different 

assumptions about key variables, such as load growth, fuel prices, and environmental costs that may be 

incurred.

Comment 41: Commenter 17867 states that the EPA should clarify that States may demonstrate 

equivalency with the EGU MACT through alternative regulation that achieves in aggregate emissions 

outcomes that are equivalent to the NESHAPs. Specifically, the commenter requests the EPA to confirm 

that Oregon has flexibility to use its Mercury Rule and the Boardman 2020 Plan to address federal 

Regional Haze requirements as the foundation for a delegated program. The commenter states that 

section 112(l) of the CAA, and the corresponding implementation regulations at 40 CFR Part 60, 

Subpart E, provide that each state may develop and submit to the Administrator a program for 

implementing the EPA’s section 112 HAP program and that the equivalency is not a line-by-line test but 

rather a demonstration that the alternatives must be holistically equivalent to the Federal requirements. 

Commenter urges the EPA to make clear that a state-implemented rule for coal units that includes 

steeper and/or earlier emission reductions of some pollutants (e.g., Hg), identical emission limits for 

other pollutants (e.g., acid gases), and marginally less aggressive emission reductions for some 

pollutants (e.g., non-Hg metals or PM), plus a commitment to early cessation of coal firing, along with 

the necessary work practice standards and elements necessary for compliance assurance, may be 

considered by EPA as no less stringent, i.e., “equivalent,” to the proposed utility NESHAP rule.

c. Concerns over delegation.

Comment 42: Commenter 17648 states that in response to request for comments on whether EPA 

would be authorized to delegate the section 112 program to states enforcing laws related to EGU

emissions and HAP reductions where the program results in greater emission reductions than the EGU

MACT but allows a compliance time extending beyond the statutory three year maximum such 

delegation would “not [be] appropriate unless the state program is at least as stringent as the federal 

program.” The commenter states that the law is “quite clear on this point” and that EPA “does not have 

the discretion to approve a state program with more lenient deadlines.”

d. Implementation.

Comment 43: Commenter 16859 requests that the EPA concurrently publish implementation guidance 

for this rule to states at the time of new rule issuance. According to the commenter, timely issuance of 

implementation guidance would facilitate state adoption of the new rule as well as increase state and 

EPA staff resource efficiency in completing activities related to new rule adoption.
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Response to Comments 37 - 43: Responses to these comments are provided in the preamble to the final 

rule.

15. Need option for percent reduction or increase compliance averaging time.

Comment 44: Commenter 17737 requests that percent reduction should be available as an alternate to a 

numerical emission rate and could be established to be based on percent reduction from the boiler inlet 

Hg concentration in a manner similar to the procedure under 40 CFR 60 subpart Da. According to the 

commenter, the percent reduction could be set at 91 percent, which is the same level as the EPA expects 

to be achieved nationwide. The commenter states that the numerical limit may be difficult if not 

impossible to achieve should a source be limited to using coal with a high Hg concentration (above 13 

lb/TBtu). The commenter asserts that switching coal sources may not be possible due to the presence of 

long term coal contracts, mine-mouth configuration, or boiler design. If the Hg coal concentration 

increases over time, Commenter may not be able to meet the standard with available technology and 

could be faced with curtailment as the sole compliance option but that this concern could be somewhat 

alleviated if the compliance averaging time were to be on a 12-month rolling basis.

Commenter 17737 states that ICR data shows some EGUs would achieve a lower emission rate with 75-

85 percent removal than others with removal rate in excess of 91 percent. According to the commenter, 

by not including a percent removal, the EPA is penalizing those EGUs that are not able to obtain coals 

with relatively low Hg content.

Commenter 17737 states that the EPA’s primary rationale for not allowing the percent reduction option 

is that it may discourage or complicate the use of coal washing as a compliance technology. According 

to the commenter, this would only be the case if the EPA elected to adopt a percent removal standard in 

lieu of a numerical limit.

Response to Comment 44: We have addressed comments related to a percent reduction format 

elsewhere in the final rule record.

16. Cannot meet mercury emission rate on continuous basis.

Comment 45: Commenter 17761 states that after a case-by-case MACT review for Hg, one of their 

EGUs was expected to achieve a Hg emission rate of 1.70 lb/TBtu (an approximate 83 percent 

reduction) but that stack testing and monitoring data from the facility has demonstrated significant 

variability in Hg emissions. The commenter states that operating and monitoring experience with Hg 

emissions at their EGU suggests that ACI performance is also highly variable and subject to decline 

based on a number of factors which may necessitate the use of additional solutions to achieve the 

expected performance criteria. According to the commenter, the inherently low chlorine content 

of their coal will make it extremely difficult for well-controlled units that utilize their coal to meet the 

proposed rule’s 1.2 lb/TBtu Hg emission rate on a continuous basis. The commenter states that Hg 

emissions as a function of ACI can vary dramatically over time for reasons that are either not completely

understood (e.g., effects of temperature, pressure drop, ammonia slip, SCR catalyst degradation, etc.) or 

outside the utility’s control (e.g., variability of Hg and chlorine content in delivered coal, variability in 

delivered activated carbon surface area, etc.).

Response to Comment 45: The rule’s Hg limit was established consistent with the requirements of 

CAA section 112(d) and it accounts for variability. As demonstrated by contemporaneous data collected 

by EGU owners or operators and submitted to the Administrator, approximately 180 EGUs are currently
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meeting the Hg standard contained in the final rule. To the extent a particular owner or operator believes 

his EGU’s Hg emissions are too high, he can and should take advantage of the three year period before 

compliance is required to find one or a combination of mercury-reducing approaches that will enable the 

EGU to meet the Hg emissions limit.

17. Allow portable monitoring equipment.

Comment 46: Commenter 17740 requests the EPA to permit sources to measure concentrations of CO 

and NOX in the effluent stream before and after adjustments with portable monitoring equipment. 

According to the commenter, industry practice is to use portable analyzers located at the boiler outlet 

duct to measure CO and NOX during combustion tuning operations.

Response to Comment 46: The EPA agrees with the comment and has modified the rule to allow 

portable emissions monitoring equipment as acceptable for meeting this requirement.

18. General clarifications needed.

Comment 47: Commenter 17740 states that the EPA should clarify the time ranges listed in 40 CFR 

section 63.10006(n). The commenter states that the proposed ranges are specified in terms of days, 

months and years, and that it is unclear whether the EPA is referring to calendar or operating days. 

Commenter recommends that the EPA adopt operating days or operating quarters. The commenter states 

that these terms are used routinely by utilities to manage emissions program schedules.

Commenter 19033 states that Table 3 of the the proposed regulation conflicts with 63.1 0006(o) and (p). 

63.10006 provides that less frequent testing than annual may be performed, if the criteria in 63.10006(o) 

and (p) are met, whereas Table 3 requires that annual testing be performed for existing EGUs. To correct 

this conflict, Commenter 19033 recommends that Table 3 be amended for existing EGUs.

Response to Comment 47: The agency reviewed the commenters’ concerns, clarified in section 

63.10006(g) that calendar days are the appropriate measurement between stack tests, and corrected 

Table 3 in the final rule. The agency finds periodic stack testing based on a time period other than 

calendar days would be confusing for not only the owner or operator but also the agency and the public. 

Note that the cited table was intended to refer to the annual performance tune-up in the proposed rule. 

Under the final rule, this has been clarified and the periodic frequency for conducting the tune-up has 

been modified. See discussion in the preamble.

19. Opposition to the EPA regulation.

Comment 48: Commenter 17768 states that citing the justification for an emissions averaging decision 

that was provided in a 16-year old rulemaking is insufficient.

Comment 49: Commenter 18477 states that Hawaii’s RPS has two significant ramifications for 

commenter’s ability to comply with the proposed rule: first, modification of a large percentage of 

commenter’s generation fleet to use renewable fuel sources has the potential to substantially reduce 

HAP emissions, but these modifications will not be completed prior to the EGU MACT compliance 

date. Second, states the commenter, compliance with both the Hawaii RPS and the EGU MACT will 

require massive capital investments, and it would be unfair to require commenter and its customers to 

invest in both, particularly when current resource plans indicate the retirement of at least four EGUs 

with relatively low capacity factors within eight to ten years. According to the commenter, installation 
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of costly control technology on these units to comply with the EGU MACT for the relatively short time 

frame before retirement would also represent significant economic inefficiency. Commenter estimates 

that installation of emission control equipment for Hg, HCl, HF, and PM would cost at least $696 

million, based on preliminary quotes provided by engineering consultants and equipment vendors. 

According to the commenter, to date, no control equipment vendor will provide performance guarantees, 

so this cost estimate does not address the risk associated with failure to comply with the proposed HAP 

emission limits. The commenter states that it is extremely difficult for companies to develop a costeffective compliance plan without control equipment vendor guarantees. Vendor guarantees allow 

companies to plan for prudent capital investments in control technology. Without these guarantees, 

Commenter is facing the untenable possibility that it will not be able to comply with the proposed 

standards despite the Company’s best efforts and significant capital investments. Accordingly, 

Commenter urges the EPA to exercise its discretion and establish work practice standards for noncontinental liquid oil-fired units.

Comment 50: Commenter 17805 states that it is inappropriate for the EPA to require utilities to expand 

energy efficiency and demand response programs as an alternative to replacing retired generation when 

retrofits are uneconomical. The commenter states that based on their resource modeling, the 

effectiveness and long-term viability of these programs are ultimately dependent on customer 

participation. According to the commenter, demand response and energy efficiency programs are 

typically more suited to be replacements for peaking type generation resources than traditional base load 

generation.

Response to Comment 48 - 50: The EPA disagrees that established precedent, no matter how old, can 

and should not be used as justification for actions within this rulemaking, particularly when the 

precedent is based on a determination that the CAA limits our discretion in the matter at issue. As noted 

elsewhere in this document, we have established a subcategory for non-continental liquid oil-fired EGUs 

in the final rule. Responses to comments related to the compliance date and emissions averaging are 

provided in the preamble to the final rule and elsewhere in the final rule record.
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CHAPTER 6: IMPACTS AND COST ANALYSIS

6A – Impacts/Costs: Emission Impacts

Commenters: 17174, 17385, 17620, 17689, 17768, 18932

Comment 1: Commenter 17174 asks that the EPA take into consideration the effect of the proposed rule 

on non-HAP pollutants and the overall air quality and public health improvement to avoid exacerbating 

air quality issues.

Response to Comment 1: The EPA has determined that the proposed rule will lead to reductions of 

criteria and HAP responsible for significant adverse health effects and that such reductions will produce 

substantial public health benefits. Accounting for ancillary impacts is standard practice in benefit-cost 

assessment since these benefits are a consequence of the rule, regardless of the rule’s intended purpose. 

This rule is expected to achieve substantial PM2.5 health benefits resulting from primary PM and SO2

emission reductions, and these co-benefits have been included in the regulatory impact assessment. 

Comment 2: Commenter 17385 asks that the EPA perform additional energy efficiency sensitivity

analyses incorporating additional policies. The commenter is pleased with the Integrated Planning 

Model (IPM) analysis of demand-side energy efficiency impacts on moderating electricity demand and 

reducing compliance costs. The IPM performed for the proposed rule included only federal appliance 

standards and utility demand side management programs. The commenter points out that there are other 

efficiency programs that could be factored in, such as building codes, tax incentives, state and local 

programs.

Response to Comment 2: The EPA recognizes that the energy efficiency sensitivity conducted does not 

represent the full array of ongoing policies in this area. The scenario does, however, illustrate in detail 

the impacts of two of the more significant policy types that are leading to increased investment in enduse efficiency: ratepayer-funded programs and federal appliance standards. These policies are not 

otherwise represented, for the most part, in the baseline electricity demand forecast from EIA that is 

used in the EPA’s modeling. Building codes and tax incentives may be accounted for to a greater degree 

in the EIA forecast.

Comment 3: Commenter 17620 argues that although the proposed rule would reduce Hg emissions so 

that on average the remaining emissions could be approximately 45 lb/unit, emissions of 22 lb/yr/unit 

cannot be considered trivial or “de mimimis.”

Response to Comment 3: The EPA disagrees with the commenter’s notion that the goal of the 

technology-based phase of regulation under CAA section 112 is to reduce emissions to levels that can be 

considered trivial or “de minimis.” In fact, there is no such goal described in all of CAA section 112 and 

today’s rule addresses the requirement of section 112(d) to establish technological performance 

standards based on what has been achieved in practice. If the commenter is actually commenting on 

whether the proposed regulation will adequately protect public health or not, under the requirements of 

CAA section 112(f), within 8 years after promulgation of this rule, the EPA will determine whether 

additional regulations are necessary to further limit emissions of Hg (or any other HAP) to protect public 

health with an ample margin of safety.

Comment 4: Commenter 17689 reports that generating and transmission cooperatives provide 41% of 

all distribution cooperative electric generation needs, of which 80% is coal-fired. The commenter also 
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states that 50% of this coal-fired equipment was constructed under CAA NSPS and more than 60% has 

FGD or scrubbers to control SO2 emissions. Also, more than 6,000 MW of the generating capacity has 

been retrofit with NOX controls, and SCR. Nearly all of the equipment has low NOX burner technology, 

making the aggregate cooperative coal-fired generation newer and better controlled than the overall 

electric utility sector.

Response to Comment 4: Existing pollution control technologies will greatly assist utilities and 

cooperatives with compliance with MATS since many existing technologies reduce emissions of 

particulates, metals, and HCl.

Comment 5: Commenter 17768 states that the rule is justified based on the co-benefits that stem largely 

from PM reductions which represent the majority of total quantified and monetized benefits. The 

commenter argues that is important to account for such co-benefits or ancillary benefits because they are 

just as significant as countervailing risks and they help to justify the cost-benefit analysis for the 

regulation. 

Response to Comment 5: Although the rule must be justified on the basis of on what is achieved in 

practice to control HAP emissions, the EPA agrees that it is valuable to quantify the PM2.5 health cobenefits of this rule. Accounting for ancillary benefits is standard practice in benefit-cost assessment 

since these benefits are a consequence of the rule, regardless of the rule’s intended purpose. The EPA 

estimates all of the anticipated costs and benefits associated with a regulatory action, to the extent 

feasible, for the purpose of determining the likely impacts, not to justify an action. This rule is expected 

to achieve substantial PM2.5 health benefits resulting from primary PM and SO2 emission reductions, 

and these co-benefits are thus an important category to quantify.

Comment 6: Commenter 18932 cites that in 2005 EGUs were responsible for 47% of anthropogenic 

cobalt emissions in the US. The commenter then cites the negative health impacts of cobalt emissions.

Response to Comment 6: Cobalt emissions will be regulated under the provisions of this rule. Under 

the requirements of CAA section 112, within 8 years after promulgation of this rule, the EPA will 

determine whether additional regulations are necessary to further limit emissions of cobalt (or any other 

HAP) to protect public health with an ample margin of safety.

Comment 7: Commenter 17627 states that the 2005 base year did not include emission reductions that 

have already occurred as a result of many enforceable federal and state programs. Additionally, the 2016 

emissions are predicated off the IPM related NODA dated October 2010 and do not include results from 

two subsequent NODAs. If the emission estimates were corrected the benefits would not be overstated 

and it is possible that the rule could not be justified on cost considerations. 

Response to Comment 7: The EPA disagrees with the commenter’s assertion that the benefits are 

overstated based on a 2005 base year. The benefits of the rule are computed based on differences 

between the 2016 baseline and the 2016 policy case, and not the differences from 2005. Therefore, to 

achieve reasonably accurate estimates of benefits, the most important feature of the EPA’s approach is 

having an accurate projection from 2005 to 2016, so that the emissions reductions and economic 

downturn referenced by the commenter are included in the future base and therefore not included as part 

of the benefits of the rule. These impacts are included in both the 2016 baseline and the 2016 policy case 

and therefore are not captured as benefits of the rule. The EPA diligently included the emissions 

reductions that have occurred from 2005 to present and the final modeling done for the RIA for this rule 

is the best available national information to reflect reductions in emissions that have occurred from 2005 
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to present. The data used at proposal were updated to reflect the comment process on the Cross-State Air 

Pollution Rule (CSAPR), for which number eastern states provided detailed updates to the EPA’s 

emissions projection assumptions for EGU, non-EGU point, stationary area, and non-road mobile 

sources. All of these comments were included in the projections used for this final rule. Furthermore, the 

comment process for this rule provided an opportunity to make the EPA aware of any other projection 

changes that were needed for improving our benefits estimates. In the rare instances where such specific 

comments were made for this rule, the EPA included those reductions in the final 2016 projections. The 

EPA used the best economic forecasts available at the time the datasets were created. This included the 

use of Annual Energy Outlook (AEO) of 2010 data in the EGU projections. Other updates to point 

sources included the incorporation of all known controls in the 2016 baseline, and the inclusion of nonEGU plant closures, federally enforceable emissions reductions, and consent decrees that have happened 

since 2005. Finally, while the EPA has attempted to provide the most reliable and accurate assessment 

of the costs and benefits expected to result from implementation of the rule, the commenter incorrectly

assumes that the rule must be justified on the basis of cost.
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6B – Impacts/Costs: Emission Reductions

Commenters: 17716, 17807, 17884, 17916, 18037, 18425, 18428, 18434

Comment 1: Commenter17716 expresses concern that the EPA’s real objectives of imposing the 

proposed rules is to retire “some of the oldest, least efficient, least controlled units” from further 

generation and virtually dictates that these units be retired. The commenter states that the EPA’s claim 

that compliance options to reduce criteria pollutants would not have HAP reductions lacks evidentiary

foundation. Further, HAP emissions by EGUs have yet to be linked to a cognizable hazard.

Response to Comment 1: The EPA disagrees with the commenter’s assertions regarding the motives 

underlying MATS and the lack of a linkage between HAP emissions by EGUs and public health 

hazards. The EPA’s full statement found in the preamble to the proposed rule does not imply that the 

EPA encourages or requires EGUs to retire rather than install control equipment but, rather, simply

observes that if companies choose to retire the units, it is unlikely to have notable impacts on electricity

grid reliability (as shown by EPA analysis). Within the context of the “appropriate and necessary”

finding, the EPA stated that if EGUs choose to comply with criteria pollutant regulations using control 

equipment that do not reduce HAP, then it remains necessary to regulate EGUs under section 112 

because imposition of the other requirements of the CAA would not eliminate the hazards to public 

health and the environment. As fully discussed in the preamble to today’s rule, and further documented 

in supporting materials found in the docket, the EPA’s peer-reviewed National-Scale Mercury Risk 

Assessment and Non-Hg Case Study Chronic Inhalation Risk Assessment confirm the known and 

potential hazards to public health and the environment. 

Comment 2: Commenter17904 suggests the EPA account for reductions in emissions that have 

occurred since 2000, and for other expected continuing reductions driven by state and other CAA

requirements. The commenter discusses the 26% reduction in annual SO2 emissions and 62% in NOX

emissions from Texas EGUs from 1995 to 2009 and the fact that nearly 50% of the coal-fired capacity in 

Texas has FGD systems. The commenter also points out that national concentrations of PM2.5 and PM10

have dropped 27-30%.

Response to Comment 2: As discussed in the preambles to the proposed and final rules, the EPA agrees 

that it is appropriate to account for emission reductions achieved by other requirements of the CAA, and 

the EPA has done so in the technical analyses accompanying this final rule. As documented in multiple 

technical support documents supporting the final rule, the EPA acknowledges that emissions from U.S. 

EGUs and other sources would be less than previous years due to controls applied to comply with other 

EPA regulations. It is standard practice for the EPA to include these emission reductions achieved 

through promulgated regulations, settlements, consent decrees, and closures in the baseline for future 

year analyses. Because the CSAPR has significant impacts on emissions from U.S. EGUs, the EPA 

specifically accounted for CSAPR in the baseline. As such, the EPA has accounted for emissions 

reductions since 2000 in the analyses supporting the “Appropriate and Necessary” finding, as the 

commenter suggests. Future year emissions modeling conducted for the final RIA was updated to reflect 

the most recently available information, and incorporates comments submitted to the docket in response 

to the proposed rule.

Comment 3: The U.S. relies on coal-fired generation for about half of its electricity. It should be taken 

into account that the U.S. power sector has reduced air emissions substantially under existing programs. 

The industry has cut SO2 and NOX emissions by 57% since 1980. Mercury has been cut by 40%. This 

has occurred while electricity use has increased by 85% and electricity from coal generating facilities 
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has tripled. The industry has made significant strides to reduce emissions. Derailing such efforts by 

piling on additional regulations that many coal- and oil-fired facilities are not able to comply with 

undermines all this hard work. Not only does the proposed Utility MACT rule in its current form 

threaten existing generating facilities, it threatens future development of an integral part of our energy

portfolio. Please withdraw this proposal.

Response to Comment 3: This regulation does not conflict or interfere with efforts cited by the 

commenter, but rather builds on them by requiring that coal-fired power plants control highly toxic 

emissions to a level that is currently being achieved by well performing power plants. These levels of 

control can be achieved with the application of widely available cost effective pollution control 

equipment and practices. Doing so will save thousands of lives and avoid hundreds of thousands of 

cases of illnesses including asthma attacks and other respiratory symptoms in children.

Comment 4: Commenter 18037 believes the use of base year 2005 overstates emission reductions from 

the proposed rule because it ignores the additional reductions realized between 2005 and the present. 

The commenter also suggests the future emissions are erroneous because they are based on 2010 NODA

that have since been updated. Finally, the commenter states that the economic downturn that began in 

2008 further reduces actual emissions, making the benefits of the proposed rule less than predicted.

Response to Comment 4: The EPA disagrees with the commenter’s assertion that the benefits are 

overstated based on a 2005 base year. The benefits of the rule are computed based on differences 

between the 2016 baseline and the 2016 policy case, and not the differences from 2005. Therefore, to 

achieve reasonably accurate estimates of benefits, the most important feature of the EPA’s approach is 

having an accurate projection from 2005 to 2016, so that the emissions reductions and economic 

downturn referenced by the commenter are included in the future base and therefore not included as part 

of the benefits of the rule. These impacts are included in both the 2016 baseline and the 2016 policy case 

and therefore are not captured as benefits of the rule. 

As discussed in the preamble to today’s rule and supporting materials, the EPA diligently included the 

emissions reductions that have occurred from 2005 to present and the final modeling done for the RIA 

for this rule is the best available national information to reflect reductions in emissions that have 

occurred from 2005 to present. The data used at proposal were updated to reflect the comment process 

on the CSAPR, for which number eastern states provided detailed updates to the EPA’s emissions 

projection assumptions for EGU, non-EGU point, stationary area, and non-road mobile sources. All of 

these comments were included in the projections used for this final rule. 

The EPA used the best economic forecasts available at the time the datasets were created. This included 

the use of AEO of 2010 data in the EGU projections. Other updates to point sources included the 

incorporation of all known controls in the 2016 baseline, and the inclusion of non-EGU plant closures, 

federally enforceable emissions reductions, and consent decrees that have happened since 2005. Benefits 

of the rule are based on emissions reductions projected by IPM modeling to occur in 2016. These 

projections are based on demand assumptions in 2016 consistent with AEO 2010. The EPA thus 

disagrees with commenter, and maintains that benefits are not overstated as a result of the economic 

downturn. See IPM documentation Chapter 3 for further details on electricity demand.

Comment 5: Commenter 18428 discusses well-controlled facilities which have installed control 

technology that reduces their emissions to area source levels. The commenter believes that applying 

generally achievable control technology (GACT) to these facilities recognizes the investment already 

made.
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Response to Comment 5: The EPA has addressed comments relating to area sources elsewhere in the 

preamble to today’s rule as well as other portions of this document.

Comment 6: Commenter 18434 states that the proposed rule’s output-based emissions limits appear to 

consider only electrical output, which fails to account for thermal energy produced and used by

cogeneration units. The commenter points out that combined heat and power (CHP) and waste heat 

recovery (WHR) units provide emission-free electricity and efficient heat, making a CHP twice as 

efficient as traditional power generation and WHR able to produce emission-free power from heat that 

would have been vented. The commenter provides a figure showing that as much as 63% of total energy

inputs are lost as wasted heat with conventional generation so the rule should incentivize CHP and WHR

projects by modifying the output-based emissions limits to account for both thermal and electric 

generation.

Response to Comment 6: The final rule provides 75% credit for thermal output in the definition of 

“gross output” (this is the value that was proposed). This value has been increased in the NSPS from the 

original 50% credit a few years ago to recognize the environmental benefit of CHP and has been carried 

over to the NESHAP.

Comment 7: Commenter 17807 disagrees with the EPA’s projection that Polk Power Station Unit 1 CA 

and Unit 1 CT, which use the IGCC process, would require installation of fabric filters as a result of the 

proposed rule. The commenter claims that the IGCC process is extremely effective for the removal of 

PM and that the fabric filter would not be warranted. The commenter requests that the EPA perform an 

additional review of the modeling process and consider that fabric filters are not feasible technology for 

the IGCC process and that the technology will not result in emission reductions.

Response to Comment 7: The EPA agrees that fabric filters are not a feasible technology for the IGCC

process. Final IPM modeling does not reflect the addition of a fabric filter to IGCC units.

Comment 8: Commenter 17916 supports the proposed rule because it will result in reductions of Hg and 

other air toxics and criteria air pollutants that cross the national boarder into Ontario. The commenter

also cites negative health impacts of such transboundary air pollution.

Response to Comment 8: The EPA thanks the commenter for their support.

Comment 9: Commenter 18425 supports the compliance schedule of the proposed rule because 

reductions in Hg emissions from Wisconsin’s largest utility WE Energies will reduce health impacts to 

the state’s residences.

Response to Comment 9: The EPA thanks the commenter for their support.

Comment 10: Commenter 17884 agrees with the National Mining Association comments and points out 

that even the EPA’s own RIA shows that most of the benefit of the proposed rule will come from 

reducing SO2 emissions, and ambient PM2.5, rather than HAP. The commenter also believes that the 

EPA exaggerates the PM2.5 emissions, which are already addressed under other CAA programs.

Response to Comment 10: The EPA disagrees with this commenter that PM2.5 health co-benefits 

should be excluded in the estimation of benefits expected by MATS. Accounting for ancillary benefits is 

standard practice in benefit-cost assessment since these benefits are a consequence of the rule, regardless 

of the rule’s intended purpose (as noted also by Commenter 17768). As such, the EPA estimates all of 
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the anticipated costs and benefits associated with a regulatory action, to the extent feasible, for the 

purpose of determining the likely impacts, not to justify an action. This rule is expected to achieve 

substantial PM2.5 health benefits resulting from primary PM and SO2 emission reductions, and these cobenefits are thus an important category to quantify. 

Consideration of ancillary benefits in benefit-cost analysis is directed by OMB Circular A-4 (p. 26, 

available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Your analysis should look beyond the direct benefits and direct costs of your rulemaking 

and consider any important ancillary benefits and countervailing risks. An ancillary

benefit is a favorable impact of the rule that is typically unrelated or secondary to the 

statutory purpose of the rulemaking (e.g., reduced refinery emissions due to more 

stringent fuel economy standards for light trucks) while a countervailing risk is an 

adverse economic, health, safety, or environmental consequence that occurs due to a rule 

and is not already accounted for in the direct cost of the rule (e.g., adverse safety impacts 

from more stringent fuel-economy standards for light trucks).”

It is also directed by the EPA’s Guidelines for Preparation of Economic Analyses (p. 11-2, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html):

“An economic analysis of regulatory or policy options should present all identifiable 

costs and benefits that are incremental to the regulation or policy under consideration. 

These should include directly intended effects and associated costs, as well as ancillary

(or co-) benefits and costs.”

In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a 

regulatory action, to the extent feasible. We further note that we were unable to monetize other 

important benefits, including health benefits of ozone reductions, additional PM2.5 health benefits, and 

direct health benefits of reducing SO2. If we were able to fully monetize these benefits, the benefits 

would exceed the costs by an even greater amount than we currently estimate. 

The EPA disagrees that the quantified PM2.5 health benefits are double-counted with the health benefits 

achieved by other regulations. The EPA’s standard practice for its rules is to estimate, to the extent data 

and time allow, all benefits of the emissions reductions achieved by a rule beyond control requirements 

for other rules. If this rule was duplicative with other rules, then there would be no additional costs or 

benefits attributable to this rule. 

When the EPA estimates the benefits for rules like MATS, the EPA includes other rules such as the 

CSAPR in the “baseline.” Any emission changes expected as a result of MATS are additional emission 

reductions beyond those regulations (e.g., CSAPR) that were considered to be part of the baseline. 

Therefore, the benefits from particle reductions are not double counting – they are real additional health 

benefits from emissions reductions achieved by MATS alone. 

Further, the PM2.5 health benefits expected from this rule are not double-counted with benefits estimated 

in the NAAQS RIAs. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air 

quality standard nationwide based on an array of emission control strategies for different sources. In 

short, NAAQS RIAs hypothesize, but do not predict, the control strategies that states may choose to 

enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or 

benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the 
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costs and benefits of other regulations that result in specific costs of control and emission reductions. 

However, some costs and benefits estimated in this RIA account for the same air quality improvements 

as estimated in the illustrative PM2.5 NAAQS RIA. 

In implementing these rules, emission controls may lead to reductions in ambient PM2.5 below the PM 

NAAQS in some areas. It is important to emphasize that NAAQS are not set at a level of zero risk. 

Instead, the NAAQS reflect the level determined by the Administrator to be protective of public health 

within an adequate margin of safety, taking into consideration effects on susceptible populations based 

on the scientific literature available at the time the standard is set. Although benefits occurring below the 

standard may be less certain than those occurring above the standard, the EPA considers them to be 

legitimate components of the total benefits estimate.
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6C – Impacts/Costs: Energy Impacts

Comments are addressed elsewhere in this document.
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6D – Secondary Impacts

Commenters: 15002, 17810, 17833, 17852, 17868, 17928, 18447, 18477

Comment 1: Commenter 15002 states that while health benefits are the main reason for supporting the 

proposed rule, they also recognize secondary impacts including improved quality-of-life due to positive 

effects on crops, plant life, and visibility.

Response to Comment 1: The EPA welcomes this comment and concurs that, although not quantified 

for this regulation, agricultural, ecological, and visibility benefits are a likely outcome of any action that 

results in reduced emissions of Hg, PM2.5, or other pollutants.

Comment 2: Commenter 17868 notes the possibility of unintended consequences of the proposed rule. 

For instance, utilities using eastern coal varieties may not be able to meet the requirements and will 

become more reliant on rail transportation to move western coal to more power plants. Some customers 

are captive rail customers who must rely on a single railroad to deliver their products. These customers 

tend to need bulk commodities such as coal, grain or lumber moved, which cannot be moved effectively

on-road. The commenter references a study by the Surface Transportation Board (STB) that showed 

44% of all tonnage shipped by freight rail is captive, which allows the railroad industry to charge rates 

500 to 700% above cost and refusing to provide adequate service to shippers who are captive to one 

railroad. The commenter provided the following site for more information: 

http://www.railcure.org/about/about_customer.asp. These increased transportation costs resulting from 

fuel switching from eastern to western coals may be a reasonable secondary impact that has not been 

considered. 

Response to Comment 2: The EPA modeling fully accounts for the cost of rail transportation, including 

a consideration of rail competition. This is reflected in the results presented in the RIA. In recent years, 

railroads have increased coal transportation rates in real terms wherever they have the opportunity. 

However, rail rates at plants captive to a single rail carrier are now close to the maximum levels 

prescribed by the STB, which limits the potential for further real increases in these rates. Moreover, 

between 2004 and 2008, the differential between rates at captive plants and rates at competitively-served 

plants narrowed. For further information, please see IPM Documentation Chapter 9.3 (“Coal 

Transportation”).

Comment 3: Commenters 17810 and 17852 recognize that the EPA can include non-air quality health 

and environmental impacts in evaluating beyond-the-floor options, but could not find any reference in 

the preamble or docket addressing the uncertainties meant in the preamble wording, “[a]s discussed 

above, the uncertainties associated with non-air quality health and environmental impacts also argue 

against determining that fuel switching is a reasonable beyond-the-floor option.” The commenters note 

that strong regulatory programs exist at the federal and state levels to protect against non-air quality 

health and environmental impacts from the production, transport and use of natural gas. Commenter

17852 states that natural gas does not involve issues as complex as those associated with nuclear waste 

disposal or the risks associated with nuclear accidents, the environmental damage from mountaintop 

coal, the technical complexity of offshore deep water oil drilling or the need for new high-voltage, longdistance transmission or large land footprints needed for utility-scale renewable energy. This commenter

goes on to say that the EPA’s record shows that non-air issues apparently do not provide a reasonable 

basis to discourage fuel switching from coal to natural gas.

Response to Comment 3:
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Comment 4: Commenter 17833 expresses concern that the proposed rule may impair the reuse of coal 

combustion residuals (CCR) such as flue gas desulfurization gypsum (FGD gypsum). The commenter

urges the EPA to achieve emissions reductions without affecting the FGD gypsum market and points out 

that ignoring the implications of the proposed rule on CCR, the cost/benefit analysis is incomplete and 

cannot be properly evaluated. The commenter explains that the use of FGD gypsum to manufacture 

wallboard rose dramatically since 1995 in part because of the >$1.5 billion expansions and retrofittings

done in 1999 to wallboard plants. That investment turned over 85 million short tons of FGD gypsum 

into building material, and kept it out of landfills. In order to be used by most wallboard plants, FGD

gypsum must be formed in a multistage process to precise specifications by the electric utilities. 

Converting operations to handle a different gypsum material requires plant closure and expensive recommissioning of the plant, as well as additional costs for transporting natural gypsum, which can 

approach the cost of the final product. The commenter discusses the 30 years the FGD gypsum industry

has spent reviewing literature and performing their own studies to be sure the it does not present human 

health or environmental concerns and provided the following references: Jessica Sanderson et al., “Fate 

of Mercury in Synthetic Gypsum Used for Wallboard Production,” USG Corp. Report for U.S. 

Department of Energy (Aug. 2005); Lisa Yost et al., “Lack of Complete Expansive Pathways for Metals 

in Natural and FGD Gypsum,” 16 Human & Ecological Risk Assessment 317-39 (2010); Scott Shock et 

al., “Evaluation of Potential for Mercury Volatilization from Natural and FGD Gypsum Using Flux 

Chamber Tests,” 43 Envtl. Science & Technology 2282-87 (Feb. 2009). Gypsum Association’s 

November 19, 2010 comments on EPA’s proposed coal ash waste rule: “Hazardous and Solid 

Management System: Identification and Listing of Special Wastes; Disposal of Coal Combustion 

Residuals from Electric Utilities, Comments Submitted by the Gypsum Association.” The commenter

states that the loss of FGD gypsum in the manufacture of wallboard would reverse the economic benefits 

of the last 10 to 15 years and would trigger major market disruption, job loss and price increases at a 

time when construction industry is vulnerable and reverse the proven environmental benefit of FGD

gypsum wallboard.

Response to Comment 4: The EPA does not expect a significant impact on the availability of FGD 

gypsum due to MATS. IPM analysis shows a potential 6 GW reduction in wet FGD operations, not all 

of which produce gypsum. This is a small fraction of the total 180 GW of wet FGD projected to operate 

in the base case.

Comment 5: Commenter 17833 sees a lack of information on the potential environmental and economic 

impacts of these emission limits on the materials and waste streams that would be generated by EGUs to 

achieve regulatory compliance to be problematic. Without such information the commenter believes the 

EPA has not performed an appropriate cost-benefit analysis. In particular, the commenter points out that 

the proposed rule may affect metal levels in EGU wastewater and waste streams. Such downstream 

impacts must be addressed to adequately assess the costs and benefits of the proposed rule. The 

commenter believes the narrow scope of each separate media review prevents the EPA from properly

assessing the costs-benefit ratio and the proposed rule’s potential to complicate or compromise the 

effectiveness of other proposed rules, and asks that the rules be considered in aggregate.

Response to Comment 5: Waste streams associated with conventional emission controls for NOX, SO2, 

and PM are already well regulated, and the costs of compliance with those regulations were considered 

as part of the promulgation of those rules. MATS may increase the number of waste streams that will 

have to be properly managed from two MATS-specific controls: ACI for Hg control, and trona DSI for 

HCl control. The EPA’s IPM modeling for MATS includes additional solid waste landfill disposal cost 

allowances as part of the variable O&M expenses associated with these controls. The EPA believes that 

adequate additional waste stream related costs were assigned in the IPM modeling, and, therefore, in the 
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benefit/cost assessment of the MATS rule as well. The EPA is not aware of, and commenter has not 

provided any information about, any waste streams associated with potential future regulations that 

cannot be properly evaluated as physically distinct systems, not complicated or compromised by the 

waste streams already considered for MATS and other existing rules.

Comment 6: Commenter 18447 states that the proposed rule has the potential to force their city to find 

an expensive landfill solution for its municipal solid waste as an alternative to burning it.

Response to Comment 6: There are multiple options for controlling HAP to the levels required by the 

final rule and the final regulation does not preclude the use of refuse-derived fuel, nor does the 

regulation require conversion from coal to gas. Each EGU is able to employ the control strategy that is 

best suited for that EGU, and there are various pollution controls that can be utilized to reduce emissions 

without requiring a new fuel source.

Comment 7: Commenter 17928 argues that the higher the level of Trona injection the more CO2 is 

produced from reactions with flue gases. The commenter states that, as will the forced oxidation wet 

limestone FGD operations, the use of Trona may result in the need for additional air permits, and urges 

the EPA to review and develop permitting procedures to assist in streamlining any permitting delays.

Response to Comment 7: The EPA is aware of the concern that installation of dry sorbent injection 

(using trona) or some other FGD technologies will result in increased hourly emissions of CO2. The 

EPA is currently designing emission guidelines for fossil-fired electric generating units and is taking this 

into consideration.

Comment 8: Commenter 18477 discusses the Hawaiian RPS laws that may be undermined by the 

numeric limits in the proposed rule. The commenter explains that Hawaii is moving toward having 70% 

of its energy use come from clean energy sources by 2030. The commenter explains that the proposed 

rule will cause Hawaii to prioritize installing controls over investments to increase clean power sources. 

The commenter describes the Hawaii Clean Energy Initiative designed to implement a fundamental and 

sustained transformation in the way renewable energy and energy efficiency resources are planned and 

used in the state. The states RPS law requires that utility sales consist of 15% renewable energy by 2015, 

25% by 2020 and 40% by 2030. A main part of the state’s strategy to achieve these goals, the 

commenter explains, is the use of liquid biofuel from renewable sources, which also leads to a 

substantial reduction in emissions. The commenter asks the EPA to establish work practice standards so 

that Hawaii has the flexibility to incorporate biofuels and biofuel blends into its power plant operations.

The commenter explains that Hawaiian Electric is a regulated entity that serves an isolated grid, so it 

does not have economic resources like those available to a merchant generator which can sell power to 

the highest bidder. The commenter believes the capital investment into control technologies that may not 

be enough to achieve compliance will impact the ability to continue to implement the biofuels plan and 

will undermine the environmental benefits of the current plans.

Response to Comment 8: As explained elsewhere in the preamble to today’s rule and in this document, 

based on comments received, the EPA is finalizing a non-continental subcategory for liquid oil-fired 

EGUs. We believe that this will help address the concerns noted by commenter. The EPA is finalizing 

emission limitations for this subcategory because it does not believe that work practice standards are 

applicable in this case as emission testing is possible and, thus, the provisions of CAA section 112 (h) 

are not met.
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6E - Impacts/Costs: Compliance Costs

Commenters: 16705, 16850, 17003, 17055, 17055, 17174, 17254, 17297, 17400, 17403, 17408, 17627, 

17629, 17638, 17648, 17681, 17689, 17697, 17701, 17702, 17707, 17716, 17718, 17731, 17732, 17743, 

17751, 17752, 17753, 17758, 17761, 17765, 17775, 17791, 17797, 17810, 17813, 17815, 17816, 17824, 

17834, 17842, 17843, 17848, 17857, 17868, 17883, 17884, 17887, 17901, 17911, 17912, 17919, 17929, 

18015, 18016, 18021, 18033, 18037, 18038, 18421, 18423, 18424, 18428, 18433, 18434, 18437, 18486, 

18497, 18500, 18575, 19114, 19121, 19199, 19212, 19213, 19653, 18023

1. Economic and reliability analysis is flawed.

Comment 1: Many commenters (16705, 17003, 17254, 17400, 17627, 17638, 17681, 17697, 17701, 

17731, 17732, 17815, 17824, 17848, 17845, 17868, 17901, 17912, 17919, 18016, 18033, 18038, 18428, 

18433, 18437, 18486, 18497, 18575, 19114, 19212, 19213, 18023) question the accuracy of the 

economic and reliability analysis in the proposed rule because it does not take into account the other 

major expenditures that will need to be undertaken by the utilities sector in the next 5 to 8 years to 

comply with up to 8 other regulations. Commenters ask that the rules be considered together, or at least 

that the Transport rule (CSAPR) be considered in conjunction with the proposed rule. Commenter 17701 

encourages multi-pollutant solutions through a robust analysis of all the rules and guidance on costeffective multi-pollutant responses. Commenter 17815 asks that the EPA especially consider impacts on 

regions such as Texas which rely more heavily on coal as a major fuel source, and commenter 17919 

made a similar request in honor of the nation’s “industrial heartland.” Commenter 18428 believes the 

EPA should evaluate the effects of regulations together, as industry does, to plan for compliance in the 

most cost-effective manner possible. Commenter 18433 also explains that military buildup in Guam will 

strain resources there, allowing insufficient capital to meet all these requirements. Commenter 18497 

states that the industry decisions pertaining to adding needed generation capacity are being exacerbated 

by the number of new or pending rules and requests a thorough analysis of the combined impacts.

Response to Comment 1: The final CSAPR was included in the baseline analysis for MATS and other 

finalized air rules and regulations. As explained in the preamble to today’s rule, the EPA considered 

impacts on regional bases as part of its overall analyses, and these are discussed in the RIA and other 

technical supporting materials.

The Agency did not prepare a cumulative impact analysis to accompany the rule for the following 

reasons: 1) the various EO requirements that the Agency must comply with require us to estimate 

impacts specific to this rule; 2) decision makers and the public need to know the impacts specific to a 

particular rule in order to judge the merits of the regulation; 3) estimates specific to a particular rule are 

more transparent than those from a cumulative impact analysis. A cumulative impact analysis lumps 

several regulations together and can potentially mask a high-cost/low benefit regulation among other 

rules that may have large net benefits. By analyzing each regulation separately, EPA makes clear 

statements about what impacts, costs, and benefits will be generated as a result of this particular 

regulation.

Comment 2: Several commenters (16705, 17884, 19741) state that the RIA is flawed and 

underestimates the real impact. Commenter 16705 sees no regional additional impacts in several states 

and references the White Paper, EPA’s Utility MACT Proposal: High Risk to the Economy and No 

Incremental Benefit, March 15, 2011. Commenter 19741 states that contrary to the retirement 

assumptions made for the agency’s RIA, the NGS is scheduled to operate for a period of time beyond 
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2015. The commenter is concerned that other faulty assumptions have been made in the RIA, including 

negative economic impacts.

Response to Comment 2: The EPA recognizes its obligations under EO 13563 to use the best available 

techniques to accurately quantify both present and future costs and benefits as well as to ensure the 

objectivity of scientific and technological information and processes used in its analysis. As such, the 

EPA relies upon guidance from its independent scientific and economic review panels and employs peer 

reviewed processes and technical literature in completing its analyses. The methodology and 

assumptions made for the analysis of the rule were included in the RIA that accompanied the proposal.

Comment 3: Commenter 17629 requests that the calculation and assumptions used to justify the 

proposed rule be reviewed in detail.

Response to Comment 3: The EPA recognizes its obligations under EO 13563 to use the best available 

techniques to accurately quantify both present and future costs and benefits as well as to ensure the 

objectivity of scientific and technological information and processes used in its analysis. As such, the 

EPA relies upon guidance from its independent scientific and economic review panels and employs peer 

reviewed processes and technical literature in completing its analyses. The methodology and 

assumptions made for the analysis of the rule were included in the RIA that accompanied the proposal.

2. General support for the proposed rule.

Comment 4: Commenter 16850 commends the EPA for allowing utilities to deploy various control 

technologies in order to meet the proposed rule’s air emissions standards.

Response to Comment 4: The EPA thanks the commenter for their observations.

3. Flexibility in compliance.

Comment 5: Multiple commenters (16850, 16859, 17701, 17732, 17753, 17758, 17797, 17887, 17919, 

18033, 18428, 19199, 19653) ask that the EPA avoid one-size-fits-all mandates and minimize costs by

allowing flexibility to choose compliance options that best fit the utility’s system and customer base. 

Some of these commenters cite EO 12866 and/or 13563 specifically in asking that the EPA allow more 

flexibility and consider all rules associated with utilities together. Commenters 17701 and 18428 ask 

that there be a continued dialogue with federal and state utility and environmental regulators to ensure 

compliance does not hinder system reliability and minimizes cost impacts on consumers. Commenter

17701 includes the National Association of Regulatory Utility Commissioners resolutions as an 

attachment. (Attachments - See DCN: EPA-HQ-OAR-2009-0234-17701-A1.pdf.)

Response to Comment 5: The EPA has attempted to provide the maximum flexibility to choose 

compliance options that is permitted by the statute. The EPA does not endorse any specific pollution 

control technology. The MACT standard is a performance-based standard that is established by

considering the maximum emission reductions currently achieved by electric generating units. 

Individual facilities are free to use whatever technologies, processes, or other means they wish in order 

to achieve this standard. The MACT standard encourages innovation by spurring companies to develop 

more effective and efficient methods for achieving the necessary emission reductions.

The EPA has also attempted to provide flexibility for compliance by including, among other things,

variability in setting emission standards; provisions allowing emissions averaging to demonstrate 
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compliance; use of surrogates to determine compliance; choice for existing sources to comply with 

input-based or output-based limits; and statutory eligibility for a 1-year extension to comply with the 

proposed rule if additional time is needed for installation of controls.

Comment 6: Commenter 17648 states that the EPA has appropriately incorporated provisions in the 

proposed rule to provide regulated EGUs with flexibility to reduce emissions to achieve compliance in 

the most cost-effective and efficient manner for that particular EGU. The commenter gives the examples 

of these provisions as being:

1. Work practice standards for dioxin/furans and non-dioxin/furan organic HAP

2. EPA’s treatment of variability in setting emission standards

3. Provisions allowing emissions averaging to demonstrate compliance

4. Use of surrogates to determine compliance,

5. Choice for existing sources to comply with input-based or output-based limits

6. Statutory eligibility for a one-year extension to comply with the proposed rule if additional time is 

needed for installation of controls

7. Provision of affirmative defense to any malfunction.

The commenter calls on the EPA to resist calls to make the proposed rule less stringent on the grounds 

that it will unnecessarily harm the industry.

Response to Comment 6: The EPA thanks the commenter for these observations.

4. Proposed rule does not properly account for all compliance costs.

Comment 7: Commenter 17758 discusses units that operate and dispatch primarily during times of peak 

load/peak demand or in emergency situations, times of natural gas curtailment, etc. The commenter

explains that the levelized cost of generation for these units is higher than most other forms of electricity

generation and would increase with retrofitting with an ESP while offering very little environmental 

benefit.

Response to Comment 7: The EPA does not believe there will be a significant impact on peaking units 

as a result of the rule for several reasons. For example, the rule only effects oil/gas steam units and does 

not cover gas combustion turbine or combined cycle units. Also, the EPA estimated that many oil/gas 

units will convert, or have already converted, to natural gas. The rule contains “limited use” provisions 

that will mitigate the impacts on many oil-fired facilities used for peaking and/or reliability purposes. 

For those units that are expected to continue firing residual oil, many already have existing air pollution 

control technologies (e.g., electrostatic precipitators) necessary to achieve the emission standards and 

the remaining units that are not capable of converting to another fuel (e.g., subject to natural gas 

curtailment) are expected to install cost-effective air pollution control technologies.

Comment 8: Commenter 17055 mentions that their initial assessment did not consider impacts the 

RICE regulations may have on the potential loss of small units relied upon by many 

municipalities. Elimination of these units could, the commenter believes, lead to local congestion and 

require transmission expansion and local programs to meet demand. The commenter believes that 

working with the industry to institute these changes will help preserve reliable system operations and 

also allow for a more gradual integration of the costs of compliance that could significantly mitigate 

reliability issues and sudden increases in consumer electricity prices. The commenter discusses an 

evaluation of costs due to potential environmental control installations required for a specific group of 
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units if the owners determine that the units require retrofitted controls instead of closure. The estimate of 

$8.5 billion would be required as initial investments for installation of the necessary controls, a number 

that may make funding difficult and which will impact the consumer bills.

Response to Comment 8: The agency has analyzed resource adequacy issues and finds that there is 

ample existing spare capacity to serve load after retirements are factored in, and industry has also shown 

that it can build new capacity quickly in response to demand. The EPA believes it has appropriately 

assessed the potential impacts of this rule, but also recognizes that individual plant retirement decisions 

for compliance with the rule are made based on individual plant circumstances, and these decisions will 

require evaluation of local market and transmission issues. The EPA will work with relevant authorities 

to ensure a smooth transition with this rule. The final rule provides greater flexibility to deal with timing 

when additional time is needed to address transmission issues arising from reliability violations related 

to plant retirements. (See the preamble for the final rule.) In addition, there are certain provisions for 

granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 9: Several commenters (17403, 18016, 18033, 18497) quote the National Economic Research 

Associates analysis results showing the combined impacts of the proposed rule and the Clean Air 

Transport Rule. The analysis shows the proposed rule is responsible for the majority of economic 

impacts that utilities will need to consider when planning for compliance. The commenters present an 

estimation of compliance costs from this analysis of $17.8 billion in annualized compliance costs and a 

total cost of $184 billion for 2011-2030, with estimated price increases from 12 to 23% in certain 

regions.

Response to Comment 9: The EPA modeling of the final rule projects lower price impacts than noted 

by commenter, and the analyses and results are fully documented in the supporting materials found in 

the docket for today’s rule (See RIA Chapter 3). The EPA has designed a rule that is intended to offer 

flexibility, to the extent possible, while ensuring public health is protected in accordance with 

requirements outlined in the CAA. History has shown that industry adapts to regulations and finds more 

cost-effective compliance approaches than the EPA can anticipate or predict, thus lowering the actual 

cost of its rule relative to what the EPA initially projected. The EPA has conducted detailed economic 

impacts analysis on the regulated sector, and finds the impact of the rule on the regulated sector is small 

compared to the overall benefits, and the industry has an excellent track record of installing pollution 

controls without greatly impacting electricity prices. The report cited by the commenter is not 

transparent with regards to several key criteria, making it impossible for the EPA to fully assess its value 

as a critique of the RIA.

Comment 10: Commenter 17638 states that the evidence shows that the EPA underestimated the impact 

of compliance costs of the proposed rule including the following impacts:

1. Electric grid reliability, including transmission

2. The number of coal fired units retired in response to the proposed rule

3. Increases in natural gas prices

4. Increases in electricity rates

5. The impact on national, regional and local economies.

The commenter requests that the EPA respond to the EIA, EEI, NERC, NERA, Credit Suisse, ICF, and 

Burns & McDonnell and explain how its approach as directed by EO 13563 utilized the best available 

techniques to quantify anticipated present and future benefits and costs...” The commenter further states 
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that the EPA does not consider the cumulative impacts of all its rules, as shown by wording on page 

25058 of the proposed rule that it has yet to consider these cumulative impacts.

Response to Comment 10: The Agency did not prepare a cumulative impact analysis to accompany the 

rule for the following reasons: 1) the various EO requirements that the Agency must comply with 

require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the 

impacts specific to a particular rule in order to judge the merits of the regulation; 3) estimates specific to 

a particular rule are more transparent than those from a cumulative impact analysis. A cumulative 

impact analysis lumps several regulations together and can potentially mask a high-cost/low benefit 

regulation among other rules that may have large net benefits. By analyzing each regulation separately, 

EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this 

particular regulation. 

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

Comment 11: Commenter 17702 questions the solitary estimate for cost of compliance as opposed to 

the range of monetized benefits for the proposed rule. The commenter believes that the EPA should 

provide a range of costs based on best and worst case scenarios from the EPA’s estimate of 11.1 GW of

coal-fired generation being shut-down, to other industry estimates of up to 48 GWs shutdown. The

commenter especially questions the EPA’s assumption that new natural gas from shale formations will 

provide sufficient gas to allow fuel switching from coal to gas, despite a recent New York Times article 

indicating that the amount of gas may be overestimated. (New York Times article June 26, 20 II 

“Insiders Sound an Alarm Amid a Natural Gas Rush”)

Response to Comment 11: The EPA agrees that providing a range of estimates can be one way to 

present the results of analyses, but it is certainly not the only way, and the EPA is not required by E.O. 

13563 to present a range of impact estimates. The EPA has conducted sensitivity analyses that explore 

key parameters in order to ensure its analyses are as accurate and reliable as reasonably possible, and the 

corresponding impacts (including cost) can be found in Chapter 3 of the RIA for the rule. To the extent 
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that the background information on which news media relied for their reports is not in the record, we are 

not able to comment on their veracity. The EPA recognizes its obligations under EO 13563 to use the 

best available techniques to accurately quantify both present and future costs and benefits as well as to 

ensure the objectivity of scientific and technological information and processes used in its analysis. As 

such, the EPA relies upon guidance from its independent scientific and economic review panels and 

employs peer reviewed processes and technical literature in completing its analyses. The methodology

and assumptions made for the analysis of the rule were included in the RIA that accompanied the 

proposal. 

Comment 12: Commenter 17718 states that the EPA’s cost-benefit analysis underestimates compliance 

costs for the commenter’s subsidiaries in Kentucky. The commenter cites the costs of over $1.7 billion 

in retrofits for the subsidiary to comply with the proposed rule, which is expected to translate into a 

12.2% to 19.2% rate increase for customers in Kentucky by 2016, depending on their provider. The 

commenter says that these rate increases do not include costs associated with retiring or replacing units 

when they become uneconomical in 2016. The commenter states that costs of this magnitude for a utility

system with under 8,000 MW of coal-fired capacity shows that the overall compliance costs of less than 

$11 billion are greatly underestimated. The commenter includes the following reference in a footnote:

In the Matter of: Application of Kentucky Utilities Company for Certificates of Public 

Convenience and Necessity and Approval of Its 2011 Compliance Plan for Recovery by 

Environmental Surcharge, KPSC Case No. 2011-00161, Application of Kentucky

Utilities Company (filed June 1, 2011); In the Matter of: Application of Louisville Gas 

and Electric Company for Certificates of Public Convenience and Necessity and 

Approval of Its 2011 Compliance Plan

Response to Comment 12: The commenter has not provided the necessary information to enable the 

EPA to evaluate commenter’s assertions. The EPA has conducted a detailed national impact analysis of 

the rule, which includes estimates of impacts to retail electricity prices that the EPA believes, in the 

absence of contradictory evidence, is reasonable. Moreover, industry has shown in the past that it can 

install significant pollution controls more cost-effectively than the EPA can sometimes anticipate.

Comment 13: Commenter 17743 states that the proposed rule’s standards will apply to all power plants 

in Oklahoma and is expected to involve widespread installation of new emission control technologies at 

great compliance cost.

Response to Comment 13: The standards do not cover all power plants in Oklahoma. Rather, the 

standards apply to coal- and oil-fired EGUs. The EPA has conducted a detailed national impact analysis 

of the rule, which includes estimates of impacts to retail electricity prices that the EPA believes, in the 

absence of contradictory evidence, is reasonable. Moreover, industry has shown in the past that it can 

install significant pollution controls more cost-effectively than the EPA can sometimes anticipate.

Comment 14: Multiple commenters (17281, 17299, 17305, 17306, 17849, 19041, 19123, 19209) 

express concern that proposed rule may affect the affordability and reliability of their electrical services, 

and ask for more flexibility.

Commenter 17753 believes that the EPA’s estimate of $10.9 billion in annual incremental compliance 

costs in 2015 are underestimated by half. The commenter asks the EPA to carefully analyze the cost 
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estimates and impact on grid reliability and energy costs and revise the final rule appropriately, or 

withdraw the rule entirely since it can’t be justified technically or economically.

Response to Comment 14: The agency prepared a reliability analysis for the proposed rule and has 

revised that analysis for the final rule. The agency is also working with FERC regarding the reliability 

impacts of this rule. The EPA has outlined the various flexibilities associated with the rule, to the extent 

permitted by the CAA, and the approaches to reliability issues in the preamble. The commenter has not 

provided evidence demonstrating that the cost estimates are underestimated. The RIA for this rule 

estimates the annual compliance costs for this rule and the results of these analyses are contained in the 

RIA documents, in various TSDs prepared for this rule, and the results are summarized in the preamble 

for this rule. Results of these analyses are available in various level of detail in the RIA and the TSDs, 

and the detailed results can be found in the docket for this rulemaking and through the official web site 

for this rule.

Comment 15: Commenter 17761 believes the EPA compliance cost estimation is too low. The 

commenter cites the $17,000 incremental cost for burner inspection and states that their experience with 

such inspections gives a very different number.

Response to Comment 15: The EPA is sensitive to the concerns raised by the commenter about the 

costs of a complete burner inspection requiring a unit outage and internal boiler scaffolding and so we 

are adjusting the time period between burner inspections not to exceed 36 months. Additionally, a unit 

that employs neural net combustion optimization software during all periods of normal operation may 

not exceed 48 months between burner inspections. This allows the burner inspection to be combined 

with other critical work projects that require internal access to the unit, and reduces the overall cost 

burden of the work.

Comment 16: Commenter 17765 reports the cost of complying with just the acid gas standard of the 

proposed rule could easily be over three times higher than the EPA’s projection and total almost $12 

billion per year. This is already more than the EPA’s estimate of $10.9 billion annually for compliance. 

The commenter goes on to state that private sector estimates of unit retirement are much higher than the 

EPA’s estimate, ranging from 50 to as high as 100 GW in retirements, as opposed to the EPA’s estimate 

of 10 GW.

Response to Comment 16: The EPA disagrees with commenter’s assertion that the EPA’s cost 

projection is understated, and maintains that the EPA’s incremental cost and retirement projections are 

reasonable. The EPA also notes that the estimates commenter refers to do not necessarily project 

impacts based on an identical policy. The EPA has conducted detailed impact analysis of the rule, which 

shows reasonable cost impacts. Industry has shown that it can install large amounts of pollution controls 

and often finds more cost-effective compliance options than the EPA can anticipate.

Comment 17: Commenter 17775 reports that a comparison of a Hg-only MACT rule to an all-HAP

MACT rule leads to an additional $30 billion in overnight capital expenditures for additional pollution 

control equipment and an additional $13 billion in overnight capital expenditures for new capacity 

additions. The commenter mentions that an all-HAP rule results in 5 GW of additional plant retirements 

when compared to a Hg-only rule.

Response to Comment 17: The EPA disagrees with commenter’s characterization of the additional 

costs associated with today’s rule as “overnight capital expenditures,” as existing affected sources have 

up to 3 years to comply with the rule (including the potential for an additional year for the installation of 
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controls), and capital costs are typically amortized over an extended period of time. Comparing the 

estimated costs of complying with today’s rule with those of a Hg-only rule is inappropriate, as that rule 

was vacated by the U.S. Court of Appeals. The preamble provides further discussion of the legal 

requirements that the EPA has sought to comply with in adopting today’s rule. The EPA believes, in the 

absence of contradictory evidence, that the costs imposed by the rule are reasonable. Moreover, industry

has shown in the past that it can install significant pollution controls more cost-effectively than the EPA 

can sometimes anticipate.

Comment 18: Commenter 17813 points out that fabric filters were not included in costs for beyond-thefloor limits, but should be included since it is still unknown if ESPs can meet the PM standard.

Response to Comment 18: The EPA has conducted detailed impact analysis of the rule and includes 

cost of fabric filters, ESPs, and ESP upgrades. The cost results can be found in the RIA of the rule, and 

EPA has also included additional information documentation for the Integrated Planning Model.

Comment 19: Commenter 17824 questions the proposed limits on the disposal of coal residuals or ash, 

which will cost up to $20 billion over the next 50 years.

Commenters 17868 and 17911 express concern that coal ash may be designated as hazardous waste 

under RCRA (Subtitle C), causing state and municipal governments to feel compelled to remove and 

remediate the coal ash fill from under buildings, at landfills, and under highways. These costs are not 

considered in the estimated cost for the proposed rule. The commenter estimates coal ash disposal costs 

as hazardous waste to range from 5% to 24% of a municipal government’s revenues.

Response to Comment 19: These comments are not within the scope of this rulemaking and, thus, the 

EPA is not providing a response. The EPA is addressing issues related to coal combustion residuals in a 

separate rulemaking.

Comment 20: Commenter 17824 discusses the proposed ozone limits being lowered from 0.075 ppm to 

0.060-0.070 ppm. The commenter states that a limit of 0.060 ppm will change 13 of Alabama’s 14 

monitored counties to non-attainment status and move 85% of monitored counties nationwide to nonattainment status, leading to a cost of $20-$90 billion annually and potentially costs up to 7 million jobs 

by 2020 and close many of these counties to new business.

Response to Comment 20: This comment is not within the scope of this rulemaking and, thus, the EPA 

is not providing a response. The EPA is addressing issues related to the NAAQS for Ozone in a separate 

rulemaking.

Comment 21: Commenter 17824 discusses the regulation of three utilities operating 12 EGUs affected 

by the proposed rule. Between them the utilities estimate compliance costs of $116.2 million in capital 

costs, and an expectation that the proposed rule would contribute to the retirement of 2 of the units for a 

loss of 253 MW. More of these units may be retired, depending on the final rules promulgated for the 

interrelated regulations currently targeting utilities.

Response to Comment 21: The EPA has designed the rule to mitigate the impacts to the extent possible 

and finds that a very small amount of the coal fleet could retire in response to the requirements (less than 

2% of the coal fleet). Sources have a wide variety of compliance options by modifying operation or 

installing pollution control technologies and it is unclear whether the commenters have undertaken a 

rigorous effort to identify and evaluate such alternatives in the course of their analysis.
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Comment 22: Commenter 17686 asks that the EPA acknowledge the price increase per MW for 

compliance as the size of the unit decreases. Commenter 18021 agrees with this additional strain on 

smaller units, due to the economy of scale. The commenter believes that the EPA did not consider the 

disproportionately large cost of compliance for small communities, many of which are also suffering 

economic hardship from falling tax revenue. The commenter cites the Bernstein and EPRI data analysis 

which chose coal plant retrofits for SOX control technologies to cost approximately 3 times more per 

MW for small units. (The commenter includes the following references : U.S. Utilities: Coal-Fired 

Generation Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses?, Bernstein 

Research, 2010., “The Hidden State Financial Crisis,” Wall Street Journal online publication, May 18, 

2011.)

Response to Comment 22: The EPA’s analysis includes scaling factors for pollution controls, 

depending upon the size of a particular unit. See documentation for the IPM for more detail.

Comment 23: Commenter 17883 owns and operates several coal-fired facilities subject to the proposed 

rule and sees the proposed Hg limits as difficult to achieve without costly modifications while other 

facilities will require modifications to meet HCl limits. The costs are estimated to be $60 million for one 

facility.

Response to Comment 23: The EPA recognizes that the final rule will obligate source owners to install 

additional controls and has attempted both to minimize unnecessary additional costs and to accurately

estimate the costs to the industry. The EPA cannot verify commenter’s assertions with regard to any 

particular unit or facility.

Comment 24: Commenter 18425 expresses concern about the compliance costs of the acid gas controls, 

which the commenter believes will have a large impact on Indiana coal industry. The commenter

considers the conclusion that regulating acid gases is necessary to be incorrect and creates costs greater 

than what is necessary to protect public health.

Response to Comment 24: The EPA disagrees with the commenter for the reasons set forth in the 

proposed rule and this final action. The commenter provides no information that causes the EPA to 

reconsider our conclusions. The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable cost impacts. Industry has shown that it can install large amounts of pollution controls and 

often finds more cost-effective compliance options than the EPA can anticipate.

Comment 25: Commenter 19121 considers the EPA’s estimated compliance costs to be underestimated 

since forced retirements and fuel switching are not properly attributed.

Response to Comment 25: The EPA disagrees with commenter’s assertion that compliance costs are 

underestimated or that there is anything in the rule that requires a unit to retire, since retirements are the 

products of economic business decisions left to the owner. Commenter does not provide detailed 

information on the “forced retirements and fuel switching” that commenter alleges are not properly

attributed.

Comment 26: Commenter 18433 explains the costs for units in Guam and references cost estimates in 

the Edison Electric Institute report on average retrofit capital cost for ESPs and DSI technology. The

commenter references a table created for the 4 units which will be subject to the proposed rule. [See 

Table 2 in EPA-HQ-OAR-2009-0234-18433-A3]
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Response to Comment 26: The EPA has included a separate category for non-continental sources (see 

preamble).

5. Proposed rule does not properly account for all other impacts.

Comment 27: Commenter 17408 considers the proposed rule and other new or proposed rules focused 

on the coal industry. The commenter points out that hundreds of thousands of people make a living from 

coal and cites a Penn State study that showed there to be up to 11 jobs created for every one coal job. 

The commenter also states that millions of people rely on the electricity that coal provides.

Response to Comment 27: The EPA has conducted detailed impact analysis of the rule, which shows 

impacts that the EPA judges to be reasonable. The EPA has designed the rule to mitigate the impacts to 

the extent possible and finds that less than a very small amount of the coal fleet could retire in response 

to the requirements (less than 2% of the coal fleet). In addition, there are certain provisions for granting 

utilities some additional time to comply, if conditions warrant (see preamble). The EPA has also 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy.

Comment 28: Commenter 17707 discusses the Alabama Power installation of $2.6 billion worth of 

emission control technologies, including SCRs and scrubbers with reduced emissions from their coalfired units approximately 65% since 1996. The commenter considers the EPA’s new standards to be 

unreasonable because any benefits would be incremental and outweighed by the costs of compliance. 

The commenter states that small coal-fired units will not be able to afford upgrades and the proposed 

rule will result in lost jobs and revenue due to high compliance costs.

Response to Comment 28: The benefits of this rule encompass the benefits of Hg reductions and cobenefits to health achieved via PM2.5 reductions. The EPA has conducted detailed economic impacts 

analysis on the regulated sector, and finds the impact of the rule on the regulated sector is small 

compared to the overall benefits, and the industry has an excellent track record of installing pollution 

controls without greatly impacting electricity prices. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the 

maximum 3-year period for sources to come into compliance. Sources may also seek a 1-year extension 

of the compliance period from their Title V permitting authority if the source needs that time to install 

controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule and 

address specific issues. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 29: Several commenters (17716, 17731, 17797, 17810, 18929) discuss the assertion that 

energy efficiency policies reduce the total cost of implementing the proposed rule. Commenters 17716 

and 17731 point out that the proposed rule has no effect on whether efficiency savings are realized and 

these savings do not serve as offsets to the higher compliance costs imposed by the proposed rule. 

Commenters believe energy efficiency had only a modest, indirect effect in later years and references 

Table 23, lines 3 and 4 on page 25074 of the proposed rule, which shows incremental annual compliance 

costs with and without energy efficiencies. The compliance cost is the same for both options in 2015, 

and changes only from $9 billion (with) to $10 billion (without) in years 2020 and 2030. The 

commenters also disagree with claims that energy efficiencies will offset rate hikes. The commenters
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believe changes in the amount of energy used are more likely to be due to the economic necessity of 

using less energy to save money following price increases, rather than due to energy efficiency

improvements.

Response to Comment 29: The EPA has designed a rule with as much flexibility as possible and in 

accordance with the requirements outlined in the CAA for HAP. Within the limitations established by

the rule, the final choice of methods for reducing emissions remains at the discretion of the owner or 

operator. However, the EPA believes energy efficiency measures can be a complement to this rule, and 

can be an important tool in helping address emissions. The EPA has not included all the likely additional 

energy efficiency measures that are likely to occur by 2015, but will continue to pursue energy

efficiency improvements throughout the economy, along with other Federal agencies, states and other 

groups. This will contribute to additional environmental and public health improvements while lowering 

the costs of realizing those improvements.

Comment 30: Several commenters (17791, 18421, 18434) acknowledge that the proposed rule 

recognizes the role of energy efficiency in reducing compliance costs and notes that the EPA cannot 

mandate energy efficiency policies. The commenters quote the EPA estimate that energy efficiency

could reduce costs of the proposed rule by $2 billion in 2015, $6 billion in 2020 and $11 billion in 2030. 

Commenter 18434 believes that since energy-efficiency investments are concentrated in densely 

populated areas with highest demand, even limited policies in the existing sensitivity analysis are likely

to have greater benefits than estimated. This commenter also states that both state and federal 

policymakers are making progress in the area of energy efficiency, making the potential for fuel savings 

through efficiency greater than that estimated. The commenter urges the EPA to modify the analysis to 

reflect the State Energy Efficiency Action Network recommendations. The commenter understands that 

the EPA cannot mandate efficiency programs, but it can urge state regulators to view compliance 

extension requests more favorably from facilities making efforts to advance efficiency.

Response to Comment 30: The EPA agrees that energy efficiency measures can be a complement to 

this rule and can be an important tool in helping address emissions. The EPA has not included all the 

likely additional energy efficiency measures that are likely to occur by 2015, but will continue to pursue 

energy efficiency improvements throughout the economy, along with other federal agencies, states and 

other groups. This will contribute to additional environmental and public health improvements while 

lowering the costs of realizing those improvements.

The final rule provides 75% credit for thermal output in the definition of “gross output” (this is the value 

that was proposed). This value has been increased in the NSPS from the original 50% credit a few years 

ago to recognize the environmental benefit of CHP and has been carried over to the NESHAP.

Comment 31: Some commenters (17689, 17824, 17887, 17912, 18021, 18037, 18500, 19212, 18023) 

express concern about the combination of multiple regulations currently proposed and the limited 

timeframe for compliance with these proposed rules. Commenter 17689 mentions the NSR and 

permitting requirements for the installation of control technology, and the fact that this process can take 

over a year. This would be likely to create a backlog at state agencies, making it nearly impossible to 

meet the compliance timeline. Commenters 17824 and 18023 in particular cite the EEI study that found 

50% of the U.S. coal fleet may be unavailable by 2015 as a result. Commenter 17887 points out that 

many generators will need the same equipment and specialized labor, leading to price pressure and 

equipment shortages due to the tight timeline. Commenters 17912 and 17689 question the need for 

outages to install equipment for multiple rules during the same timeframe, which will require more time 

than is allowed under these rules. The commenter sees this as particularly problematic for IPPs, because 
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they typically do not have enough EGUs to avoid reliability issues with such outages and will have to 

pay to replace the capacity. Commenter 18037 explains the difficulties for planning without time to 

consider economies of scale, or co-benefits that could be realized by the installation of one type of 

equipment as opposed to several. Also, this commenter discusses the physical space constraints for some 

plants looking to retro-fit control equipment. To remain competitive, facilities must add control 

equipment as it is needed, and adding equipment before it is necessary is financially imprudent.

Response to Comment 31: One of the purposes of developing the NSPS and MATS rules in tandem 

was to facilitate more cost-effective compliance planning by affected source owners and so while, the 

EPA acknowledges concerns expressed by the commenters, it continues to believe that it has sought to 

minimize any hardships associated with compliance. As part of the analysis supporting the rule, the EPA 

has included a TSD on feasibility of installing pollution controls, and additional detail on timing can be 

found in the preamble.

Comment 32: Commenter 18015 believes as an owner/operator of three large coal-fired power plants 

that the proposed rule will have significant impacts on the company’s operations.

Response to Comment 32: The EPA has conducted detailed impact analysis of the rule, which shows 

impacts the EPA has judged to be reasonable. The EPA has designed the rule to mitigate the impacts to 

the extent possible. In addition, there are certain provisions for granting utilities some additional time to 

comply, if conditions warrant (see preamble). 

Comment 33: Commenter 18486 urges the EPA to discontinue the regulation of power plants until it 

has studied the combined impact of current and pending rules on natural gas rules and how those 

impacts affect agriculture.

Response to Comment 33: The EPA is subject to a Consent Decree in the matter of American Nurses 

Ass’n v. EPA, 08-2198 (D.D.C.). That decree requires the EPA to sign the final MATS rule by

December 16, 2011.

Comment 34: Commenter 18023 reports that the roughly 400 GW of capacity affected by the proposed 

rule and other pending or new regulations are vital to adequate electricity supply and provide substantial 

generator-supplied frequency control capability to the bulk power system. The commenter states that the 

aggregate impact of these rules will require unprecedented levels of generation and transmission 

construction in a short time period and could force industry to operate in uncertain conditions. System 

changes in the electricity industry must be evaluated in advance so the system can be planned and 

operated such that the causes and effects can be understood, and costs and problems minimized.

Response to Comment 34: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) and that coal-fired generation will not change significantly. The 

agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity

in existence that will help serve load. In addition, there are certain provisions for granting utilities some 

additional time to comply, if conditions warrant (see preamble). The EPA will work with relevant 

authorities to ensure a smooth transition with this rule and address specific issues. 

6. Coordination of rules regulating similar pollutants.

Comment 35: Commenter 17627 states that NSPS requirements in the proposed rule have the potential 

to retire coal generation without an economical replacement, increasing costs to the public. The 
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commenter asks that the proposed rules that deal with the same pollutants be coordinated so that one is 

implemented and given time to realize benefits before another program controlling the same pollutants 

are implemented. The commenter believes this approach would produce the desired environmental and 

human health benefits while maintaining system reliability and minimizing costs.

Response to Comment 35: To the extent possible, the EPA has coordinated the rulemakings. However, 

CAA section 112 provides statutory compliance times which preclude doing much of what commenter 

seeks. Other comments on the compliance time issue are responded to elsewhere in this document.

Comment 36: Commenters 17681 and 17901 state that the EPA’s initiatives will each have an impact 

on electricity cost and transmission and together the compliance costs could disproportionately impact 

the elderly, minorities and low-income citizens. The commenters consider the prominent rules at issue to 

include:

(a) 2010 NAAQS for NO2;

(b) 2010 NAAQS for SO2;

(c) 2011 NAAQS for ozone;

(d) 2011 NAAQS for PM2.5;

(e) 2011 Cross State Air Pollution Rule (CSAPR);

(f) 2012 Revisions to the CSAPR;

(g) 2011 Industrial Boiler MACT;

(h) Regional Haze Rule;

(i) GHG PSD and Title V permitting;

(j) GHG NSPS;

(k) 2010 revisions to 40 CFR Part 63, subpart ZZZZ;

(l) 316(b) cooling water intake structures;

(m) Steam Electric Effluent Guidelines;

(n) Numeric nutrient criteria;

(o) Total Maximum Daily Load rules; and

(p) Coal Combustion Residuals.

The commenters also ask that the EPA honor EO 13563 by considering these rules together. Commenter

17901 estimates that the combined rules will directly impact approximately 400,000 MW or oil- and 

coal-fired generation, or 40 to 50% of national electricity generation.

Response to Comment 36: The EPA acknowledges that elderly, minority and low-income populations 

are overrepresented among those persons who live in close proximity to coal-fired power plants. For that 

reason, the EPA expects that elderly, minority, and low-income population groups would benefit 

disproportionately from the reduced emissions that will result from the rulemaking. The agency did not 

prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO 

requirements that the agency must comply with require us to estimate impacts specific to this rule; 2) 

decision makers and the public need to know the impacts specific to a particular rule in order to judge 

the merits of the regulation; 3) estimates specific to a particular rule are more transparent than those 

from a cumulative impact analysis. A cumulative impact analysis lumps several regulations together and 

can potentially mask a high-cost/low benefit regulation among other rules that may have large net 

benefits. By analyzing each regulation separately, the EPA makes clear statements about what impacts, 

costs, and benefits will be generated as a result of this particular regulation.
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This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

Comment 37: Commenter 17751 quotes EO 13563 and EO 13576 about overlapping, redundant or 

inconsistent requirements as well as doing everything in the Government’s power to stop wasteful 

practices. The commenter questions the EPA’s choice to impose several regulations instead of one. The 

commenter quotes the EPA study that states implementation of the 1997 NAAQS for ozone and PM 

may lead to Hg reductions, but went on to say that the reductions could not be sufficiently quantified. 

The commenter questions the validity of the statement and asks the EPA to develop and implement a 

procedure to provide reasonable upper and lower bound estimates of PM reductions likely to be 

achieved through state SIP programs. The commenter acknowledges that the estimates may not be 

completely accurate, but believes providing an estimate would be more helpful than not including one. 

The commenter believes that by not making a prediction, the EPA is essentially assuming the benefits of 

the state SIP programs on Hg will be zero, which is not credible and leads to inflated benefit estimates of 

the proposed rule.

Response to Comment 37: Where the opportunity is presented, the EPA seeks to coordinate efforts to 

comply with multiple CAA requirements. In implementing rules such as the MATS, emission controls 

may lead to reductions in ambient PM2.5 and ozone below the NAAQS for PM and ozone in some areas 

and assist other areas with attaining these NAAQS. Although both RIAs calculate PM and ozone costs 

and benefits, it is important to note that there are key differences in the design and analytical objectives 

of a NAAQS RIA and one for a rule such as MATS. The NAAQS RIAs illustrate the potential costs and 

benefits of attaining a new air quality standard nationwide based on an array of emission control 

strategies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, the control 

strategies that states may choose to enact when implementing a NAAQS. The setting of a NAAQS does 

not directly result in costs or benefits, and as such, the NAAQS RIAs are merely illustrative and are not 

intended to be added to the costs and benefits of other regulations that result in specific costs of control 

and emission reductions. Some costs and benefits estimated in this RIA account for the same air quality

improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA, but these effects are only

counted once when considering cumulative costs and benefits.
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Comment 38: Commenter 18033 addresses the EPA’s decision to wait until the NSPS for GHG 

emissions rulemaking before considering coordinated control strategies for EGUs. The commenter

considers this approach to be too late, since many utilities much begin complying with CSAPR within 

the next few months and will have only 3 years to comply with the proposed rule once it is finalized. 

The commenter states that the EPA is obligated to help the regulated community plan for all interrelated 

regulations and cumulatively assess the societal impacts of these regulations, which has not been done in 

this instance. The commenter sees the combined regulations impacting American competitiveness as 

increased prices undermine businesses ability to compete and sending businesses and jobs overseas.

Response to Comment 38: The EPA believes that by proceeding with the rules being adopted today, 

while were developed with explicit consideration of the impacts of CSAPR, it is striking a reasonable 

balance between seeking necessary protections of public health and coordinating efforts for the NSPS 

and MATS to minimize unnecessary costs to industry. Rules under development for GHG emissions 

will fully consider requirements adopted in today’s regulations and seek to minimize or eliminate 

disruptive impacts on compliance planning and implementation.

7. Impacts on tribal nations.

Comment 39: Commenter 17732, as a tribal nation and small government landlord of affected EGUs, 

states that the EPA is obligated to consult with the commenter and analyze the economic impacts to the 

commenter in promulgating the proposed rule. The commenter further states that EPA is required to 

tailor the proposed rule so that the costs of compliance for plants on the commenter are achievable 

within a reasonable timeframe, while taking into account the unique challenges of the plants for this and 

future rulemakings. The commenter explains that compliance costs to meet BART have the potential to 

impact the commenter’s economy significantly. The commenter is concerned that the proposed rule will 

create a recurring threat of severe reductions in the revenue received from the power plants and their 

supplying mines. The commenter explains that FCPP and NGS are subject to proposed BART 

determinations and that EPA, Region IX, proposed an Alternative Emission Control Strategy (“AECS”), 

a better-than-BART determination for FCPP. The AECS takes into account the FCPP proposal to 

shutdown Units 1, 2 and 3. The loss of this total net capacity of 560 MW by 2014 would result in 100% 

control of NOx, S02, PM, Hg and other hazardous pollutants from these EGUs, which would 

significantly reduce emissions from FCPP. Currently, the EPA, Region IX, has delayed proposing 

BART for NGS until at least December, 2011, pending consultations with stakeholder tribes. After 

publication of the ANPRM for BART, the commenter recommended a phased approach to emissions 

controls for FCPP and NGS, and suggested that the EPA consider the multiple interests at stake, 

including the significant economic interests of the commenter. The commenter asks that the EPA 

analyze the impacts from these rulemakings and provide flexibility for compliance scheduling so that 

FCPP and NGS, upon which the commenter relies, can continue operations.

Response to Comment 39: Landlords of affected facilities are not included in the definition of an 

affected small entity and, thus, were not included in the EPA’s analysis of small entity impacts. The 

EPA conducted multiple consultations with the tribes, including the Navajo Nation and has sought to be 

responsive to concerns raised in those consultations. As to comments about an obligation to tailor the 

rule to the Navajo Nation’s economy, the CAA imposes certain specific requirements and the EPA does 

not believe that it permits tailoring to the extent that appears to be requested by the commenters.

With respect to compliance, the EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 

3-year period for sources to come into compliance. Sources may also seek a 1-year extension of the 

compliance period from their Title V permitting authority if the source needs that time to install 
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controls. CAA section 112(i)(3)(B). The EPA discusses in more detail elsewhere in this notice how the 

agency plans to address those units that are still unable to comply within the statutorily mandated period.

8. Methodology and assumptions in calculations.

Comment 40: Commenter 17810 recognizes that the EPA can consider costs as part of the beyond-thefloor analysis, but asks that the EPA clarify the methodology and assumptions used and expand the 

analysis to include potential cost effectiveness of repowering coal-fired units as natural gas combined 

cycle units. The commenter provides recommendations on the technologies used in combusting natural 

gas, fuel costs and pipeline costs. (Insert included in original letter 17810-A1_Table2Page17.doc.) The 

commenter questions the pipeline construction costs for converting existing coal units to natural gas 

since they do not accurately reflect the costs a unit owner would face in repowering to natural gas. The 

commenter cites an example case in Oklahoma for which the EPA’s methods result in cost estimates 20 

times greater than a more site-specific estimate. The commenter offers a table showing two example 

coal-to-gas repowered units for which the EPA estimate is approximately $375 million while the total 

costs using Navigant estimates are $52 million. The number of pipeline laterals seems to create the 

largest estimate differences. The commenter notes that the EPA estimates seem to show laterals cannot 

draw more than 10% of the mainline capacity, but the reason for this assumption is not shown.

Commenter 17810 also requests clarification on the “Incremental Fixed Costs” equation and any 

assumptions made about plant life. The commenter questions whether the manner in which the EPA 

evaluated these costs is scientifically sound, since the report only includes costs associated with 

retrofitting a 303 MW unit at static technology, pipeline and fuel costs. The commenter notes that no 

information on why the EPA chose to estimate costs for only one unit or chose a 303 MW unit. Since 

these costs can vary greatly depending on the unit size, the commenter suggests that the EPA conduct a 

sensitivity analysis showing the costs of retrofit options for different size units and fuel price points.

Commenter 17810 suggests the EPA analyze the costs of retiring existing coal units and creating new 

capacity on sites closer to pipelines. The commenter asks that the EPA include an evaluation of 

repowering to natural gas combined cycle units in the evaluation of the cost of control options since 

there are efficiency advantages over boiler-based technologies.

Response to Comment 40: The EPA has fully documented its peer-reviewed methodology and 

assumptions for assessing the impacts of this rule, which can be found in the documentation for IPM 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/index.html). The documentation includes pollution 

control cost assumptions, fuel supply assumptions, and financial assumptions governing the power 

sector. In conducting its analyses, the EPA has attempted to be as thorough and accurate as reasonably

possible.

9. Energy efficiency reduces compliance costs and emissions.

Comment 41: Commenter 17843 appreciates the Energy Efficiency Scenario that illustrates how the 

costs of the proposed rule can be lowered through energy efficiency investments instead of retrofitting 

pollution controls or building new generation units. The commenter points out that energy efficiency

also enhances reliability as it encourages retirement of the least efficient units as demand decreases. The 

commenter points out that some states are pursuing aggressive programs and directing investments for 

energy efficiency with proven results. The commenter cites the following article: Regional Greenhouse 

Gas Initiative, Inc. (RGGI, Inc.). “Investment of Proceeds from RGGICO2 Allowances.”RGGI, Inc. 
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(February 2011), at http://www.rggi.org/docs/Investment_of_RGGI_Allowance_Proceeds.pdf (accessed 

July 8, 2011).

Response to Comment 41: The benefits of energy efficiency policies are discussed in the preamble. 

These impacts include reduced need for construction of new generating capacity as well as reduced need 

for construction of emissions controls such as FGDs. The EPA has designed a rule with as much 

flexibility as possible and in accordance with the requirements outlined in the CAA for HAP. The EPA 

believes energy efficiency measures can be a complement to this rule, and can be an important tool in 

helping address emissions. The EPA has not included all the likely additional energy efficiency 

measures that are likely to occur by 2015, but will continue to pursue energy efficiency improvements 

throughout the economy, along with other Federal agencies, states and other groups. This will contribute 

to additional environmental and public health improvements while lowering the costs of realizing those 

improvements.

Comment 42: Commenter 17929 states that new boilers can reduce emissions by incorporating energyefficient designs that allow them to use less coal to produce the same amount of electricity. The 

commenter points out that a boiler operating at 40% efficiency will use 10% less coal to produce the

same amount of power than if it is operated at 36% efficiency.

Response to Comment 42: The EPA generally agrees and thanks the commenter for their observation.

Comment 43: Commenter 18421 discusses the role of energy efficiency in reducing costs and 

preserving reliability. The commenter cites studies by McKinsey and Company, MIT’s Innovations, 

U.S. DOE and others that see benefits to more efficient processes and improved demand-side energy

efficiency programs. The commenter compares the Toxics Rule Case without energy efficiency to the 

Toxics Rule Case with energy efficiency and found that the efficiency policies reduce the need for new 

capacity by 0.3 GW in 2015, by 8.5 GW in 2020, and by 39.8 GW in 2030. The commenter also notes 

that the reductions lower annual average electricity demand growth. The commenter cites a 2009 study

by the American Council for an Energy-Efficient Economy which found by looking at programs in 14 

states that efficiency programs by the utility sector cost one-third less than investing in new generation 

of any type. A report by Synapse Energy Economics reinforced the finding and showed that the highest 

cost per kWh saved through energy efficiency was 3 cents, compared to the national average of 9 cents 

per kWh of delivered electricity. (The commenter provided the following references as footnotes: 

RIA8.13 Illustrative End-use Energy Efficiency Policy Sensitivity RIA8 Appendix D. For example, 

McKinsey& Company, “Unlocking Energy Efficiency in the U.S. Economy,” (July 2009), Hannah 

ChoiGranade, Jon Creyts, Anton Derkach, Philip Farese, Scott Nyquist, and Ken Ostrowski

(http://www.mckinsey.com/clientservice/electricpowernaturalgas/downloads/us_energy_efficiency_full_

report.pdf) and Electric Power Research Institute, “Assessment of Achievable Potential of Energy

Efficiency and Demand Response Programs in the U.S. (2010-2030),” (January 2009), 

(http://www.edisonfoundation.net/iee/reports/EPRI_SummaryAssessmentAchievableEEPotential0109.p

df).American Council for an Energy-Efficient Economy, Saving Energy Cost-Effectively: A National 

Review of the Cost of Energy Saved Through Utility-Sector Energy Efficiency Programs, September 

2009. 105 States evaluated are: California, Connecticut, Iowa, Massachusetts, Minnesota, Nevada, New 

Mexico, New Jersey, New York, Oregon, Rhode Island, Texas, Vermont, and Wisconsin Synapse 

Energy Economics, Inc, No Need to Wait: Using Energy Efficiency and Offsets to Meet Early Electric 

Sector Greenhouse Gas Targets, May 2009.)

Response to Comment 43: The studies cited provide information on the cost-effectiveness of energy

efficiency policies that are generally consistent with the sources cited for the EPA analysis.
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10. Fuel switching.

Comment 44: Commenter 18423 questions the EPA’s statements and calculations pertaining to fuel 

switching as a regulatory option. The commenter questions the lack of consideration for new gas units to 

replace coal units and the rejection of fuel switching as an option due to the lack of supply/availability of 

natural gas and the cost. The commenter reviews the capital costs calculated by the EPA and concludes 

that the ratio of cost of fuel switching from coal to gas is 18-53% higher than the alternative, rather than 

4 to 22 times the cost of the alternatives. The commenter sees an error in the EPA’s calculations because 

it does not consider that fuel switching to natural gas removes the expense of coal for retrofitted units. 

The commenter refers to the “Base and Incremental Fuel Costs” table created by the EPA in which it 

appears the cost of coal at $22.4/MWh is not included in the control technology refit scenario 

comparisons.

Response to Comment 44: The EPA disagrees with commenter’s assertion that EPA calculations 

comparing the coal-to-gas (CTG) boiler conversion option to other retrofit control options incorrectly

included the base cost of coal fuel (as well as gas fuel) in the CTG incremental fuel cost. The EPA 

incremental cost calculations are correct. Furthermore, EPA’s IPM analysis has fully considered and 

included the multitude of compliance options available to sources. The IPM analysis indicates that there 

will be a small amount of coal retirements (2% of the coal fleet) and that coal-fired generation will not 

change significantly. The agency has also assessed resource adequacy, and has determined that there is 

sufficient excess capacity in existence that will help serve load. The EPA modeling fully reflects the 

costs of competing fuels, and the results can be found in Chapter 3 of the RIA

11. Miscellaneous.

Comment 45: Commenter 17752 expresses concern about the risk of noncompliance for early action. 

The commenter explains that if controls are installed based on the proposed rule do not achieve the 

reductions required by the final rule, the unit owner faces enforcement penalties because there is not 

market in which to buy allowances to cover the compliance shortfall. The commenter also notes that 

utilities contemplating retrofits to units in rate-regulated states run a risk of non-recovery if they make 

capital commitments before the final rule is issued.

Response to Comment 45: The EPA is allowing a 3-year compliance timeframe for existing sources 

affected by the rule, and there are also conditions under which extensions could be granted (see 

preamble for additional discussion on timing). New sources that commence construction or 

reconstruction after the rule was proposed but before it was promulgated are not required to comply until 

3 years after the rule is promulgated, if the final rule is more stringent than the proposed rule.

Comment 46: Commenter 19114 questions the lack of documentation to support conclusions about the 

amount to capacity that would or would not need to add fabric filters to meet the proposed PM limits. 

The commenter requests full emission data and projections along with details on which technologies, 

controls and units are likely to meet the HAP standards with or without the use of a fabric filter.

Response to Comment 46: See Documentation Supplement for EPA Base Case v.4.10_MATS –

Updates for Final Mercury and Air Toxics Standards (MATS) Rule for a detailed description of the 

assumptions used by EPA regarding fabric filter retrofits in the modeling done in support of the final 

rule.
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Comment 47: Commenter 17701 points out that their organization members have a history of 

supporting cost-effective energy efficiency measures and are leaders in reducing emissions, increasing 

energy efficiency and promoting renewable and clean energy sources.

Response to Comment 47: The EPA thanks the commenter.

Comment 48: Commenter 18424 points out that the estimates of cost of compliance show much of the 

cost is associated with acid gas controls, which the commenter believes will have a strong impact on 

Indiana coal industry. The commenter considers the decision to regulate acid gas to be incorrect because 

the costs are more than what is necessary to protect public health.

Response to Comment 48: Section 112 of the CAA requires the EPA to regulate emissions of more 

than 100 HAP, including acid gases. Section 112(n) requires the EPA to regulate EGUs under section 

112 when it concludes that doing so is “appropriate and necessary.” In December 2000, the EPA 

concluded that it was “appropriate and necessary” to regulate Hg emissions from coal- and oil-fired 

power plants under section 112. This finding meant that EGUs were listed as a source of HAP the EPA 

was required to regulate under the CAA. The D.C. Circuit Court’s ruling that the EPA inappropriately 

delisted EGUs as a source of HAP regulated under section 112 supports this decision.

The EPA disagrees with the commenter for the reasons set forth in the proposed rule and this final 

action. The commenter provides no information that causes us to reconsider our conclusions.
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6F – Control Technology Cost Assumptions

Commenters: 16469, 16705, 16826, 16849, 17296, 17386, 17400, 17408, 17620, 17621, 17622, 17623, 

17627, 17648, 17655, 17682, 17702, 17721, 17731, 17734, 17736, 17754, 17756, 17757, 17758, 17761, 

17765, 17770, 17775, 17790, 17796, 17807, 17810, 17821, 17840, 17842, 17868, 17869, 17881, 17885, 

17904, 17911, 17912, 18017, 18033, 18037, 18421, 18433, 18437, 18447, 18484, 18500, 18575, 19114, 

19122, 19213, 19536/19537/19538, 18023

1. Coal ash/coal combustion residuals.

Comment 1: Many commenters (16705, 17702, 17400, 17754, 17758, 17770, 17775, 17821, 17868, 

17881, 18437, 18500, 18575, 19213) question the assumption that facilities will be able to sell or trade 

coal ash/coal combustion residuals despite possible changes that could occur in the sodium content of 

the ash due to new emission control technologies being required. Increased sodium could render the ash 

unable to be sold and lead to coal ash management costs in addition to lost revenue. Commenter 18500 

points out the EPA identified 93 GW of capacity that it expects to utilize ACI to meet the proposed 

requirements. This commenter states that the beneficial reuse market for fly ash tops $2 billion annually, 

so the use of ACI would risk eliminating the market and forcing landfilling of these residuals at a 

dramatic increase of operating cost. The commenters believe these considerations should be included in 

the costs.

Comment 2: Commenter 17754 states the limitations placed by the proposed rule on the sale of coal ash 

potentially interferes with broader environmental considerations because they may impede the continued 

beneficial use of coal ash for the reclamation of abandoned mining lands.

Comment 3: Multiple commenters (17621, 17758, 17754, 17775, 17821, 17868, 17881) discuss the use 

of sodium-based DSI and the impact it could have on marketability and beneficial use of fly ash in 

concrete, wallboard, asphalt products, bridge construction and mine reclamation. The commenters state 

that around 134 million tons of coal combustion residuals are currently generated every year and 56 

million of these are recycled in these applications. The loss of these uses, the commenters say, will cause 

the coal ash/coal combustion residuals to be disposed of instead of used beneficially, causing economic, 

operational and environmental burdens. Coal-based facilities will need to expand existing disposal units 

or construct new ones, which can take several years and cost millions of dollars per unit not accounted 

for in current cost estimates.

Comment 4: Some commenters (17758, 17775, 17821, 17868, 17911) explain that fly ash must meet 

product specifications to be used in certain applications to assure high-quality products, such as an 

appropriate alkali limit for use in concrete to avoid expansion and cracking. The commenters explain 

that the sodium-based sorbent injection technologies cause fly ash to exceed the appropriate alkali 

criteria, exceed necessary carbon content, and are soluble, making it unsuitable for use in ready-mix 

concrete. The commenters go on to explain that solubility is also increased, making it unsuitable for 

other established uses, such as mine reclamation. The commenters point out the previous testimony by

the EPA about beneficial uses of coal ash/coal combustion residuals saving virgin resources and 

reducing energy consumption, reducing GHG emissions and the need for land disposal and ask that the 

forfeiture of environmental benefits of coal ash/coal combustion residuals be assessed and considered in 

overall policy evaluation. Comment 5: Commenter 17821 reports that 3 million tons of coal ash/coal 

combustion residuals is beneficially reused by their organization annually, but this will end if they must 

install sodium-based DSI or ACI. This will lead to loss of jobs and an economic impact on the utility 

plant and end users of the coal ash/coal combustion residuals.
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Response to Comments 1 - 5: Multiple commenters declare that DSI and ACI controls contaminate 

coal ash/coal combustion residuals, thereby rendering the co-mingled material unmarketable. The EPA 

notes (from the comments submitted) markets purchased 56 million tons of the 134 million tons of coal 

ash/coal combustion residuals – a fraction of the total coal ash/coal combustion residuals generated. 

Removal of this entire quantity due to contamination from the marketplace can be adequately satisfied 

by the remaining coal ash/coal combustion residuals produced. By the comments submitted, not all coal 

ash/coal combustion residuals generated is sold; rather a sizable portion (58 percent) is disposed. 

Moreover, the coal ash/coal combustion residuals marketplace sets specifications for allowable 

contaminate levels; depending upon ACI and DSI flow rates, this may or may not render ash 

unmarketable. The EPA concludes negligible impacts to downstream coal ash/coal combustion residuals

end-users market.

As for coal ash/coal combustion residuals producers, only 42 percent of ash sells to the market (56 

million tons of 136 million tons) thereby making it a minor revenue stream for an EGU. As mentioned 

before, depending upon ACI and DSI flow rates in conjunction with coal ash/coal combustion residuals

buyer’s specification, the ash may retain marketability. As for contaminated ash, a station’s owner may

install a secondary particulate capture device dedicated to removal of DSI absorbents or activated carbon 

downstream of existing PM equipment. This second PM device preserves coal ash/coal combustion 

residuals ash sales while reducing waste volume generated. Finally, for those EGU’s electing to dispose 

of the contaminated ash, the EPA models this cost at $50 per ton for disposal costs. The EPA believes

multiple options exist for EGU owners to implement the most economical compliance action for 

adhering to MATS regulation.

Several commenters are concerned that sorbent injected by DSI and ACI controls will contaminate 

CCR, particularly fly ash, to such an extent that the co-mingled material is unmarketable. The EPA has 

modeled DSI and ACI in a manner that includes the cost of an additional secondary PM collection 

device, a fabric filter (FF), dedicated to the collection of injected sorbent downstream of the existing PM 

collection device. This modeling assumption incurs the additional cost of a FF on most DSI retrofits and 

on many ACI retrofits, in order to allow uncontaminated fly ash captured in the existing PM collection 

device to remain marketable. Given that DSI and ACI remain economic for many units even with this 

conservative cost assumption, the EPA concludes that there will likely be minimal impacts to the 

downstream CCR end-user market. Furthermore, although the EPA based the costs and performance 

estimates of DSI on use of Trona, the use of other reagents can mitigate or even avoid this problem 

altogether. Sodium bicarbonate has been shown to be more effective than Trona, which would reduce 

the sodium content of ash considerably. Activated lime hydrate is another alternative to Trona that 

would avoid the concern about sodium solubility altogether. The CCR marketplace sets specifications 

for allowable contaminate levels and these specifications vary based upon the ultimate purpose of the fly

ash. Depending upon ACI and DSI flow rates, the fly ash may or may not be rendered unmarketable. In 

some cases the fly ash will remain acceptable for the original purpose; in some cases it may no longer be 

acceptable for the original purpose, but it will be suitable for other purposes. Regarding any lost revenue 

due to contaminated ash issues, the EPA observes that almost all of an EGU’s revenues are derived from 

electricity sales, with ash sales representing a very minor income stream at risk to demand forces within 

the downstream market. Avoided disposal costs are often more significant than any CCR revenues, and 

if the fly ash can be repurposed for a less valuable purpose, the financial impact to the facility would still 

be small. Finally, and in any case, the EPA’s modeling indicates that the majority of DSI installations 

will likely be on smaller units because many larger units are already scrubbed for SO2 control and have 

no need for DSI. For further discussion on IPM modeling assumptions, see the IPM documentation. 

Also see the preamble for the final rule for additional discussion of DSI.
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As for activated carbon contamination issues, proper location of the injection point will prevent 

contaminating salable by-products; note an additional PM capture device may be required for collecting 

Hg-laden activated carbon downstream. An SCR with WFGD configuration burning fuels with 

sufficient halogen content will oxidize Hg in the SCR followed by capture in the downstream WFGD

thereby eliminating the need for ACI. The dissolved water-soluble Hg species is easily separated in the 

gypsum dewatering/washing process

Comment 6: Commenters 17868 and 17911 express concern that coal ash may be designated as 

hazardous waste under RCRA (Subtitle C), causing state and municipal governments to feel compelled 

to remove and remediate the coal ash fill from under buildings, at landfill, and under highways. These 

costs are not considered in the estimated cost for the proposed rule. The commenters estimate coal ash 

disposal costs as hazardous waste to range from 5% to 24% of a municipal government’s revenues. 

Commenter 17408 expresses concern about increasingly toxic fly ash as a result of using carbon 

injection to comply with the rule.

Response to Comment 6: Federal statute limits MATS to stationary source emissions (see the preamble 

for the final rule for applicability). As for contaminated ash, a station’s owner may install a secondary

particulate capture device dedicated to removal of DSI absorbents or activated carbon downstream of 

existing PM equipment. Issues regarding CCR remediation from prior utilization or disposal are not 

within the scope of the MATS rule.

2. Dry sorbent injection.

Comment 7: Multiple commenters (17623, 17765, 17770, 17775, 17781, 17840, 18033, 18023) explain 

that the estimated compliance cost and retirement rate is likely to be low because the assumption that 

DSI and a baghouse will enable a bituminous coal burning source to meet the HCl limit which may not 

be realistic. Wet scrubbers are likely to be necessary and will increase compliance costs and the number 

of plants to retire since they cannot afford compliance. Some commenters (17765, 18033, 19114) state 

that the EPA needs to examine what portion of the estimated 56 GW of the existing fleet expected to 

install DSI instead of scrubbers may realistically do so to more accurately estimate costs because the 

commenter believes that cost of complying with just the acid gas standard could easily be almost $12 

billion annually. Commenter 17770 reports findings from a testing program that shows DSI is able to 

control acid gas HAP only from units burning low rank western coals. The commenter asks the EPA to 

reconsider its projections regarding DSI to control acid gases based on data available from DOE-NETL

and others. Commenter 17775 refers to modeling that shows the proposed rule will result in tens of 

billions of additional dollars for compliance due to standards for non-Hg HAPS that will require more 

control than can be achieved with DSI alone and no measurable health benefits. Commenter 19114 

states that few coal-fired units use DSI for any purpose and none have been identified that employ DSI

for HCl control. Given the lack of practical experience in the industry, the commenter believes the EPA 

should revisit the application and performance attributes of the technology or risk understating the 

potential costs and number of induced unit retirements.

Response to Comment 7: See the preamble for the final rule for a discussion of DSI.

Comment 8: Commenter 17758 agrees that DSI can be used for compliance at many units cost 

effectively, but strongly disagrees with the assumption underlying the proposal that DSI and dry

scrubbers will be the compliance method for acid gas control at all units because DSI has not been 

widely demonstrated in practice. The commenter notes that out of 131 units that define the HCl floor, 

only 15 units currently use DSI, and only five of those units use DSI without FGD.
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Response to Comment 8: The EPA does not believe that DSI and dry scrubbers will be the only 

compliance options for control of acid gases, and utilities will choose compliance pathways based on a 

variety of considerations and available technologies. DSI is a commercially available technology and the 

EPA believes it will play an important role for achieving compliance. See preamble for further 

discussion on DSI and other compliance options.

Comment 9: Commenter 16469 explains that DSI is applicable to smaller units burning low-sulfur 

subbituminous coal. The commenter states that operational performance systems using sodium 

bicarbonate indicate SO2 removal rates in the range of 20-60%, which is below the >90% SO2 removal 

typically associated with wet scrubbers. The commenter includes a table showing removal rates for HCl

and SO2 at increasing bicarbonate flow rates in the range of 75-95% for HCl and 20-60% for SO2. The 

commenter reports that analysts believe that DSI is likely to be used by smaller units, with larger unit 

installing scrubbers. The commenter also believes that additional controls may be needed to address 

future regulations which could entail retrofit scrubbers and SCRs to achieve SO2 and NOX control. 

Commenter 19114, on the other hand, states that they have installed over 10,000 MW of coal-fired units 

and has experience with the operation of DSI and sees the quantities of Trona required for the needed 

removal efficiencies to be too expensive and logistically cumbersome to maintain for smaller units.

Response to Comment 9: See the preamble for the final rule for a discussion of DSI.

Comment 10: Commenters 17620 and 17648 report that the ACI and DSI technology required to 

comply with the proposed rule have existed for many years. Commenter 17620 states that these 

technologies require little capital for construction and normally involve installation schedules of less 

than 12 and 24 months, respectively while FGD and SCR technologies require longer schedules. The 

commenter states that industry has demonstrated its ability to add the controls by the deadline, pointing 

out that applicable compliance was achieved following past regulations being passed. The commenter

mentions the 26 GW of new SCR controls that came on line in 2003 to meet the NOX SIP, while 

approximately 70 GW of SCR and 10 GW of FGD capacity were installed in 2000-2004. The 

commenter cites IPM modeling estimates that show 83 GW of new scrubbing and 65 GW of DSI added 

to the existing 145 GW of capacity that has scrubbing. Also, the estimates add 98 GW of ACI and 26 

GW of new SCR for NOX control. Commenter 17648 confirms that ACI is a feasible control technology

for Hg emissions, regardless of the control technologies presently used to control for PM, SO2 or NOX

and gives examples of how this can be done. The commenter also points out that regulation often drives 

development of cheaper, more efficient controls. The commenter confirms that technologies exist to 

achieve the reductions called for by the proposed rule. The commenter believes that sources can 

reasonably expect to be able to alter source fuels or select and install suitable controls to achieve the 

proposed emissions limits.

Response to Comment 10: The EPA thanks the commenter for the information provided in support of 

the proposed rule.

Comment 11: Commenter 17648 disagrees with criticism that the EPA’s analysis underestimates the 

number of units that will need to install wet or dry FGD controls to meet the proposed acid gas limits. 

The commenter says that DSI is a mature technology that is well suited for units that burn fuels with 

lower or mid-level sulfur contents and is among the viable options for a number of sources to achieve 

the proposed HCl limits. The commenter points out that 73% of the sources with HCl emission data in 

the ICR database already achieve the proposed HCl limit and several of them do so using DSI. The 

commenter goes on to list coal-fired units that control SO2 using DSI.
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Response to Comment 11: The EPA thanks the commenter for the information provided in support of 

the proposed rule.

Comment 12: Commenter 17702 acknowledges that they have compliance options to meet the proposed 

requirements, such as adding carbon injection or switching to a wet scrubber. However, the commenter

feels this will add additional costs and defeat the environmental objectives that led to the selection of 

their air pollution control system, such as conserving water with a dry scrubber as opposed to a wet 

scrubber and finding a way to use the calcium byproducts. However, the proposed emission limits will 

require ACI, which will interfere with the ability to sell the byproduct.

Response to Comment 12: Although wet scrubbers (WFGD) use considerable amounts of water, 

approximately 90 weight percent of the water can be recovered in a gypsum slurry dewatering process 

and returned to the system. Water used for quenching incoming flue gas to the wet scrubber, can be 

minimized by lowering flue gas temperatures to the minimum permitted by design.

As noted above, for activated carbon contamination issues, proper location of the injection point will 

prevent contaminating salable by-products; note an additional PM capture device may be required for 

collecting Hg-laden activated carbon downstream. An SCR with WFGD configuration burning fuels 

with sufficient halogen content will oxidize Hg in the SCR followed by capture in the downstream 

WFGD thereby eliminating the need for ACI. The dissolved water-soluble Hg species is easily separated 

in the gypsum dewatering/washing process.

Current scrubbing technology captures MATS acid gases with superior effectiveness relative to SO2;

19

as a result, the EPA does not anticipate scrubber retrofits for MATS compliance on units equipped with 

a wet or dry scrubber.20 The EPA expects that a dry scrubber with a fabric filter is a control 

configuration where no additional controls may be required in some cases.21 Where additional controls 

are needed, the EPA believes that units with dry scrubbers with fabric filters may choose ACI, but they

may also find other approaches effective. In many cases, especially bituminous coal units, high cobenefit capture occurs without the need for ACI. For low rank coals, capture can be enhanced with 

bromide addition. Experience has shown that addition of oxidizing agents (i.e., bromide) and/or the use 

of sorbents designed to mitigate or avoid the adverse effects of activated carbon on fly ash, including 

mineral-based sorbents, are available and effective.22 As a result, the EPA believes that facilities with 

dry scrubbers are especially well suited to comply with the rule at relatively low expense.

Comment 13: Commenters 17736 and 19114 question the effectiveness of DSI to control acid gas 

emissions from coal-based EGUs and point out that no such units have been identified as employing DSI

for HCl control. The commenters have experience installing Trona injection systems on coal-fired units 

and understand the shortcomings of DSI injection. As such, the commenters find SO2 removal by DSI to 

be too costly and cumbersome to be practically applied. Specifically, the commenters find the nozzle 

 

19 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011, pp. 11-12, 21

20 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, 

URS Corporation, April 5, 2011; p.7, Table 2-1

21 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011, p. 20

22 Hizny, W., Magno, G., Yang, X., “BASF Mercury Sorbent ZXTM for Control of Coal-fired Power 

Plant Hg Emissions,” Paper # 176, Power Plant Air Pollutant Control “MEGA” Symposium, August 30 

– September 2, 2010, Baltimore, MD
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pluggage and antagonistic effects on ESPs would make achieving HCl and PM limits difficult over a 30-

day period. Commenter 19114 questions the EPA’s “Documentation Supplement for EPA Base Case 

v4.10_PTox – Updates for Proposed Toxics Rule” which quotes a DSI test done by a company

specializing in this technology using Trona and other sodium-based sorbents to remove SOX and other 

acid gases and will substantially benefit from regulation requiring DSI technology. The commenter

points out that the document referenced by the EPA is a simple slide presentation about a single test, and 

lacks technical specifics that allow the data to be extrapolated to such a broad range of units as those in 

the utility industry. The commenter expresses concern that the EPA allows for the use of DSI in 

conjunction with existing ESP systems without regard to size or performance, as this is not supported by

available data. The commenter also questions the assumed SO2 removal of 50-70% with DSI, as it is not 

supported by the indicated data. The commenter also worries that there could be potential cost premiums 

for affected units if they are all forced to rely on a single vendor for the required technology and points 

out that the testing reports used by the EPA do not evaluate potential operations concerns. The 

commenter also states that the costs associated with maintaining a DSI system due to pluggage and 

antagonistic effects on ESPs would make achieving both the HCl and PM limits very difficult to achieve 

over a 30-day operating period. The commenter calls on the EPA to expand the quantity and quality of 

their review.

Response to Comment 13: The EPA has determined that DSI is an effective acid gas control 

technology since MATS acid gas removal exceeds SO2 capture rates with this technology.

23 Despite 

comments claiming DSI as too costly or cumbersome, this control technology occupies less space and 

requires substantially less capital investment than a unit employing a wet or dry scrubber.24 However, a 

DSI system’s operating costs tend to exceed a wet or dry scrubber for high sulfur fuels. As a result, the 

EPA’s IPM modeling limited the DSI retrofit option to units combusting fuel less than 2.0 lb 

SO2/MMBtu. Pluggage issues result from poorly designed systems for powdered solids conveyance. A 

variety of causes can lead to blockage; for example, poorly designed piping systems, inappropriate 

storage practices, incorrect system operation, plus others. Similar problems arose and were solved in 

analogous industries of food processing (wheat flour, powdered sugar), concrete (dry Portland cement), 

and pharmaceuticals etc. regarding dry powder material transfer. The EPA has noted that there are 

commercially available solutions to address these issues.25 Pluggage problems at a particular facility do 

not disqualify DSI as a commercially available control technology. With regard to impact on ESP 

performance, DSI using sodium-based reagents has been shown to improve ESP performance; this has 

been a consistent phenomenon that is the result of the beneficial impact of sodium sorbent on fly ash 

resistivity. Also see the preamble for the final rule for a further discussion of DSI.

Comment 14: Commenters 17758 and 18033 discusses the EPA’s acknowledgement that if DSI does 

not achieve the required HCl reductions, utilities will need dry or wet scrubbers to achieve compliance, 

which the commenters believe will prompt more unit retirements. Commenter 17758 also mentions that 

the cost for DSI varies from $4/MWh to $15/MWh and there are few suppliers of DSI technology, 

especially the Trona. Commenters 17758 and 17775 cite difficulties with the Trona supply with 

estimates of costs to deliver Trona to the eastern U.S. as high as $200/ton due to logistical difficulties. 

For instance, the special rail cars needed, the limited plant storage silo sizes and short shelf-life of the 

product al contribute to making increased Trona supply difficult to achieve. Finally, the commenters

note that units using DSI or ACI often need PM control downstream, such as a baghouse or ESP and a 

 

23 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011, p. 22

24 ibid, p. 13

25 UCC web site; DSI FAQ #3 Plugging Issues. Web site: http://unitedconveyor.com/dsi.aspx
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baghouse typically takes 36 months to install and costs $200/KW. Overall, the commenters question the 

cost-effectiveness of DSI, quoting BPC as saying that, “...capital costs for an alternative, dry sorbent 

injection are significantly lower. On a levelized cost basis, however, the difference is far less 

significant...” Commenter 17781 agrees with this conclusion and says that while DSI can be economic 

with low sulfur fuels and/or operated over short time periods, many EGUs will need to install spray 

dryer adsorbers (SDAs) in lieu of using DSI, which means longer lead times for procurement and 

installation of at least a year.

Response to Comment 14: The EPA disagrees with the commenters and does not expect that scrubbers 

are necessary solely for acid gas control under the MATS rule. The EPA has analyzed the supply of 

Trona and sodium bicarbonate and determined that it is ample, as soda ash (a product of mined Trona) is 

already used extensively for other industries (such as glass manufacturing, detergents, etc.) that need a 

reliable supply. DSI has also been shown to improve ESP performance, so that a fabric filter is generally 

not necessary unless otherwise needed for PM control. Facility owners may choose to install scrubbers 

for control of acid gas; however, this does not change the EPA’s determination that other technologies 

are available and can be used to comply with the rule at reasonable cost and in the time frame of the 

rule. Also see the preamble for the final rule for a further discussion of DSI. 

Comment 15: Commenters 17765 and 18033 report that private sector estimates of retirements are 

higher than the EPA’s estimates because of the unproven effectiveness of DSI, the lack of reliability of 

the reagent supply chain, the lack of industry experience with the technology and the potential impact of 

dispatch. These concerns lead to retirement estimates of 50 to 100 GW. Commenter 17765 believes that 

without further testing to show that DSI technology can be relied on for compliance, few utilities will 

choose it. The commenter finds the EPA’s compliance timeline makes it difficult for utilities to obtain 

information necessary to make decisions about control technologies or unit retirement. The commenter

also points out that many of the 56 GW capacity units the EPA estimated would choose DSI will not 

have that option due to overlapping CAA rules.

Response to Comment 15: The EPA disagrees with the commenters’ assumptions. There have been 

numerous private sector studies that examine retirements due to several EPA rules that have been 

proposed or finalized over the past 2 years. Many of these studies were based upon assumptions of what 

a rule might require prior to its proposal or finalization, and the assumed requirements were generally

more stringent than the actual requirements proved to be. Although the EPA’s modeling for MATS 

predicts that some units will choose DSI, the EPA recognizes that some of these units may not actually

do so, for a variety of reasons that may involve owner preferences and site specific circumstances. Also 

see the preamble for the final rule for a further discussion of DSI.

Comment 16: Commenters 17775 and 18037 discuss various adverse consequences of DSI use, 

pointing out that it can hinder compliance with Hg and PM limits as the injected reagent adversely 

affects baghouses, and requires that three times the normal amount of ACI be used to achieve the same 

level of Hg control, as well as leading to the mission of a visible brown plume from the high sodium 

content.

Response to Comment 16: The EPA is aware that there is some data suggesting DSI can adversely

impact ACI performance. In particular, the Presque Isle tests where this was observed were for SO2

control, and the Trona treatment rate for those tests was therefore higher than would be necessary for 

control of HCl for PRB fuel. PRB fuel typically has low HCl emissions and likely will not need 

additional controls for HCl in most cases. On the other hand, DSI can improve ACI performance for 

bituminous units because of the reduction in SO3, which interferes with ACI capture of Hg. DSI using 
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sodium compounds (Trona, etc.) has actually been shown to improve ESP performance. Therefore, little 

or no adverse impact is expected with regard to PM. Improper DSI operation can adversely affects PM 

and Hg control. Insufficient bag house capacity or excessive sorbent injection rate can adversely affect 

PM control performance.

26 An improper operating temperature reduces activated carbon’s ability to 

capture Hg27 while high concentrations of SO3 compete with mercury for capture.28 DSI systems failing 

to remove sufficient SO3 negatively impact ACI system performance.29 Hg speciation exiting the 

furnace significantly impacts controls selection and performance, with multiple factors affecting 

speciation (e.g., fuel constituents, halogen presence, installed emissions controls, and temperature).30,31

ESP performance typically improves with sodium based sorbents; on the other hand, a calcium based 

species tends to negatively impact operation.32 The brown plume phenomenon apparently can occur 

under conditions of high treatment rates on units that do not have NOX controls,33 but this is not 

anticipated for HCl control due to the lower treatment rate needed for HCl removal. Formation of a 

brown plume appears to be an event too infrequent to disqualify DSI as a control scheme within the 

MATS. Represented by the Presque Isle tests, one system produced a brown plume; on the other hand, 

over 30 other DSI systems did not generate a brown plume.34 Also see the preamble for the final rule for 

a further discussion of DSI.

Comment 17: Commenter 17775 explains that the assumption that an adequate supply of dry sorbents 

will be available is not a good one. The commenter explains that sorbent production will need to 

increase by 10 to 20 times in order to meet the EPA’s projected DSI demand. This is a problem, the 

commenter explains, because the industry is not going to spend hundreds of millions of dollars on plant 

expansions without a secure market, but until the utilities decide to install DSI, they will not know what 

the demand will be. Once a commitment is made, it will take more than 18 months to increase sorbent 

production to necessary levels to supply all the projected new DSI units.

Response to Comment 17: Multiple comments submitted claim insufficient absorbent (or sorbent) 

production capability exists to serve the DSI market. The agency researched this issue and determined 

that DSI utilizes the following absorbent materials for pollution control: Trona, sodium bicarbonate, 

sodium carbonate (common name: soda ash), calcium carbonate, and calcium bicarbonate - sodium 

based chemicals are favored over calcium based materials due to economics. Trona is mined in 

Wyoming as a naturally occurring ore by four companies with mining operations extracting 16.5 million 

 

26 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, 

URS Corporation, April 5, 2011; p.A-10

27 Ibid., p.A-8

28 Ibid.

29 Ibid.

30 Solvay Chemicals publication “Mercury (Hg)”

31 Tutorial: Mercury Chemistry in Boilers and Mercury Control Technology (Part 1) by C Senior, 

Reaction Engineering Intl., 30th International Technical Conference on Coal Utilization & Fuel Systems; 

April 17-21, 2005

32 UCC web site; DSI FAQ #1 ESP Performance. Web site: http://unitedconveyor.com/dsi.aspx

33 Sjostrom, S.,Senior, C., Durham, M., Bustard, J., “INTEGRATED MACT COMPLIANCE 

PLANNING,” http://www.adaes.com/PDFs/presentations/AQVIIIIntegrated%20MACT%20planning.pdf

34 “Comparison of Sodium Bicarbonate and Trona for SO2 Mitigation at a Coal-Fired Plant” by Kong & 

Vysoky (Solvay Chemicals) Electric Power 2009 presentation, May 12-14, 2009. 

ref: http://www.solvair.us/static/wma/pdf/1/5/8/4/0/SO2_Mitigation-Electric_Power_2009.pdf
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tons in 2010.35 Production peaked at 18.1 million tons in 2006.36 In 2010, end consumers received 

176,000 tons of Trona via direct shipment37 while the balance was converted into soda ash and related 

chemicals. Note that soda ash is an acceptable absorbent for DSI pollution control. Exports claimed onehalf of the 10 million tons of soda ash produced in 2010.38 Currently, the industry (ANSAC) alleges 

unfair foreign practices negatively impacting domestic exports.39 Considering the excess Trona mining 

capacity, the fact that nearly 50 percent of Trona-based derived soda ash is exported, and the fact that 

alleged foreign competition practices negatively impact exports - the agency concludes that Trona 

supply is not an issue.

The EPA disagrees with commenter’s estimate and has concluded that current U.S. Trona production 

may already have adequate surplus capacity to meet projected DSI demand. See the preamble for the 

final rule for a further discussion of DSI.

Comment 18: Commenter 17790 explains that the EPA’s analysis of emission reduction technologies 

required by their facilities to comply with the proposed rule is erroneous because it assumes they will 

install fabric filters on all coal-fired units. However, the commenter’s analysis showed that DSI is only

economical on units which are able to achieve compliance-level reductions of HCl using ESPs, and 

spending additional money on fabric filters is not economical for them.

Response to Comment 18: The EPA’s IPM modeling for the MATS final rule now takes into 

consideration that there are less costly options than FF for PM compliance, particularly the upgrading of 

existing ESPs. Please see the documentation for IPMv4.10_MATS. In addition, Trona DSI has been 

shown to improve ESP performance, a benefit that the EPA’s IPM analysis has conservatively has not 

incorporated. For these reasons, many units that were previously modeled as installing a FF may find 

that only the installation of DSI upstream of the existing ESP may be needed for MATS compliance. 

Also see the preamble for the final rule for a further discussion of DSI.

Comment 19: Commenter 18033 requests that the EPA address integrated planning after the proposed 

NSPS for GHS from EGUs are issued to create a cumulative cost analysis. The commenter states that 

neither a utility or public utility commission would permit the investment in DSI technology and sorbent 

storage facilities if a scrubber would be needed a few years later. The commenter went on to explain that 

not every coal type within the projected 56 GW expected to install DSI will be able to meet the 

compliance limits using that technology. The commenter refers to Sargent & Lundy report which states, 

“[t]he DSI technology should not be applied to fuels with a sulfur content of greater than 2 lb 

SO2/MMBtu.” (Footnote 57 to EPA-HQ-OAR-2009-0234-18033-A2 gives NMA revised cost estimates 

for DSI.)

Response to Comment 19: Issues regarding a NSPS for GHG from EGUs are not within the scope of 

the MATS rule, although the EPA does intend to seek to coordinate requirements under today’s rules 

with those of the pending NSPS for GHG emissions. Also see the preamble for the final rule for a 

further discussion of DSI.

 

35 http://www.wma-minelife.com/trona/TronaPage2/ trona_production.htm

36 ibid

37

http://www.onrr.gov/ONRRWebStats/StateAndOffshoreRegions.aspx?state=WY&yeartype=FY&year=

2010&dateType=AY

38 http://minerals.er.usgs.gov/minerals/pubs/commodity/soda_ash/mcs-2011-sodaa.pdf

39 http://www.ansac.com/news/2011/06/01/
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Comment 20: Commenter 18421 states that DSI can be used with a variety of sorbents to allow an 

approach tailored to the source and unit characteristics. The commenter quotes NESCAUM “Control 

Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal-Fired Power Plants,”

March 31, 2011, as estimating capital costs and storage silo costs for DSI at around $20/kW. The report 

also cites approximately 90 coal units currently using DSI, showing that it is effective at reduction HCl

by more than 99% and works efficiently with a downstream fabric filter or ESP. The commenter also 

quotes SOLV Air, a Trona distributor, as refuting claims that Trona is likely to be unavailable by saying

“hundreds of years of reserves of Trona are available.” Commenter 17621 agrees with the idea of 

various options for sorbents used with DSI technology and explains the various pros and cons of some 

options. The commenter reports on a Trona injection test that resulted in a visible brown plume and 

degradation of Hg removal by ACI. The commenter explains that while hydrated lime injection would 

remove SO3 without the adverse impacts of Trona, it is unknown if the hydrated lime could meet the 

proposed limit at any injection rate or if it would increase pressure drop across a baghouse to 

unacceptable levels. The commenter also mentions the practice of grinding sodium sorbent before 

introducing it to the feed system, then injecting the finer material upstream of the air preheater. This 

practice is believed to increase mixing and residence-time, providing greater SOX and HCl reduction. 

However, the method can also lead to air preheater pluggage in some cases. The commenter describes a 

field test program in which Trona or sodium bicarbonate was used to achieve high HCl and SO2 removal 

rates without pluggage problems. The commenter explains that the site has an atypical system including 

both hot- and cold-side ESP, and sorbent was injected upstream of the hot-side ESP which may have 

minimized pluggage and plumes. This commenter believes that further investigations are needed of DSI

over a range of power plant designs, coal types and air pollution controls to fully evaluate HCl and SO2

removal performance and impacts on balance-of-plant operations.

Response to Comment 20: The EPA thanks the commenter for the information provided in support of 

the proposed rule.

Comment 21: Commenter 18424 considers the EPA estimates for control technologies to be suspect 

since they may not be appropriate for use by many power plants, depending on the coal burned and the 

impacts DSI will have on PM and Hg emissions. The commenter questions the method of developing 

emission rules for each pollutant independently without considering how one control device may impact 

the control of other pollutants.

Response to Comment 21: The EPA disagrees with commenter. The EPA evaluated the effects of DSI

on different fuels and considered the effects on Hg and PM emissions. See the documentation for 

IPMv4.10_MATS, and the preamble for the final rule for a discussion of DSI. It is important to note that 

the EPA established emission standards based on the best-performing sources of the different emitted 

HAP and is not specifying the use of a particular control device, leaving it to the discretion of the source 

owner or operator to select controls that will meet the applicable standards considering the 

characteristics of the particular source.

Comment 22: Commenter 18023 disagrees with the assumption that 56 GW of coal plants will not need 

a FGD system because DSI will suffice at a lower cost and shorter timeline for installation. The 

commenter states that even if DSI can achieve the HCl removal levels required to comply, it would not 

do so under all operating conditions. The commenter states that the EPA’s model predicted that several 

of the commenter’s power plants would not achieve continuous compliance with the proposed acid gas 

limit using DSI. (Commenter includes Figure 6 showing necessary technology to achieve compliance 

with proposed HCl limit.) Therefore, the commenter believes the costs and timeline on which the 

proposed rule is based are erroneously low. The commenter also disagrees with the assumption that wet 
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scrubbers will not be widely required to meet the proposed emission limits since dry scrubbers are more 

appropriate for smaller units with lower sulfur fuels, which does not describe all units. The use of wet 

scrubbers will also drive up compliance costs so the commenter asks that the EPA update cost 

assumptions to account for these requirements.

Response to Comment 22: The EPA disagrees with the commenter. The EPA has determined that wet 

scrubbers, while beneficial for acid gas control, are not necessary for compliance with the MATS rule. 

Also see the preamble for the final rule for a further discussion of DSI.

Comment 23: Commenter 17775 states that the proposed rule will require large-scale installation of 

new control technologies to meet the Hg, HCl and total PM limits. The commenter restates the EPA 

estimates that the proposed standards will require the installation of 93 GW of ACI, 56 GW of DSI, 26 

GW of wet FGDs and dry FGDs, 166 GW of FF and 5 GW of SCR, and that this $46 billion (in 2007 

dollars) of control equipment can be installed in 3 years. The commenter considers the EPA’s estimate 

to be unreasonable because it is based on incorrect assumptions about the efficacy of DSI.

Response to Comment 23: See the preamble for the final rule for a discussion of the efficacy of DSI. 

Also see the RIA for projected controls retrofits and costs as updated in EPAs analysis for the MATS 

final rule.

Comment 24: Commenter 17775 questions the EPA’s conclusions about the effectiveness of DSI since 

they are based on limited information and incomplete analyses. The commenter points to ICR data from 

plants using DSI systems to see that only 11 of the 28 units using DSI do so to control SO2 and only two 

of those 11 units report ICR emissions data that show compliance with the proposed existing source HCl

limit. In fact, those two cases the units burn low chloride fuel and do not need to install DSI to meet the 

HCl limit. Therefore, the commenter states that there is no example of an EGU system that complies 

with the HCl limit as a result of having a DSI system. The commenter also explains that the Sargent & 

Lundy report cited by the EPA to support its views on DSI are lacking information on how DSI may

affect PM or Hg emissions. Also, the commenter says that the Solvay Chemicals case study to predict 

Trona feed rates for HCl and SO2 removal was for sodium bicarbonate injection, not Trona, making the 

feed rates inaccurate. In addition, the commenter points out that the flue gas make-up in the case study

was not representative of low sulfur coals.

Response to Comment 24: The EPA disagrees with commenter’s conclusions. Also see the preamble 

for the final rule for a further discussion of DSI.

Comment 25: Commenter 18963 notes that there have been no commercially demonstrated applications 

of DSI for the control of HCl from coal refuse-fired CFB units. Further, even to the extent that it is 

technologically feasible to use sorbent injection to control HCl from coal refuse-fired CFB units, the use 

of different sorbents for this purpose may affect the quality of the ash residue. Such ash is currently used 

in the environmentally-beneficial step of reclaiming lands and protecting and enhancing streams 

damaged by acid mine drainage.

Response to Comment 25: See the preamble for the final rule for a further discussion of DSI.

Comment 26: Commenter 16849 states that even under revised averaging periods, Trona and DSI are 

not a viable option for Empire, as is incorrectly stated by the EPA (“IPM Parsed Results - Policy Case,”

Unplanned DSI Installations by 2015 includes Asbury: 2076_B_1).
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Response to Comment 26: The EPA believes that DSI has the potential to be a useful and costeffective control technology option for many units. We also understand that it is not an appropriate 

option for all facilities. Overall the EPA believes that the technology is most applicable for units burning 

lower-sulfur content coal (including, potentially, low-sulfur bituminous coal).

3. Electrostatic precipitators.

Comment 27: Commenter 17622 explains that ESPs are the primary particulate collection equipment 

for many utility units and are designed to have sufficient Specific Collecting Area (SCA) to meet the 

proposed total PM emission limits. The commenter considers it to be in the best interest of the industry

to retain existing plant assets as much as possible while complying with the proposed rules. The 

commenter explains that ESPs can be upgraded by improved maintenance/repair, parts replacement, etc., 

or rebuilding to increase SCA. However, the commenter points out that the potential for upgrading 

existing ESP installations to meet the proposed limits depends on the age and design of the existing 

equipment. Not all equipment was designed to achieve 0.03 lb/MMBtu to begin with, and may not be 

able to comply with the proposed emission limits even after being rebuilt. Some equipment may require 

expanded collecting area, but not have the space to accomplish this. Another solution, where space is 

available is to add a polishing fabric filter after the ESP. Also, an existing ESP may be converted to a 

pulse jet fabric filter. The addition of a fabric filter or conversion from an ESP to a fabric filter would 

allow better utilization of Trona or lime for HCl and SO3 control and allow the potential to include other 

reagents for Hg control. There is an impact on the ID fans and structure to convert to a fabric filter, but 

much of the existing support structure and ducts/casings could be used. The final solution suggested by

the commenter is the addition of a wet ESP to an existing wet FGD to capture filterable and condensable 

particulate. The commenter offers the Dallman and HL Spurlock plants in the ICR PM database as 

examples of this approach and explains that this alternative has the advantage of using existing air 

pollution control equipment with low increase in pressure drop.

Response to Comment 27: The EPA thanks the submitter for the information provided in support of the 

proposed standard MATS and notes that this information corroborates the EPA’s views about the 

availability of multiple compliance options for many affected sources.

4. Timeline.

Comment 28: Several commenters (17627, 17655, 17911, 19114) express concern over the compliance 

timeline of the proposed rule. In particular, the number of regulations focusing on the same pollutants in 

the same timeline is a concern because of the pressure likely to be placed on control equipment suppliers 

and skilled labor for installation will not allow all the units to acquire the needed equipment in the given 

time period. Commenter 17655 reports that an SCR originally estimated to cost $33 million actually cost 

them $61 million entirely due to the fact that all the CAIR-affected units were competing for the same 

design, material and labor pools during a compressed construction schedule to comply. The commenter

expects the same thing to happen to a greater extent in response to the proposed rule.

Response to Comment 28: Commenters recalling price escalation during CAIR’s implementation 

phase understandably convey concerns regarding the EPA’s cost estimating; however, the present 

economic situation does not reflect current national or global conditions. During CAIR implementation, 

high global demand for construction commodities (especially from China) attributed to cost escalation. 

Presently, commodity prices are relaxed from their peak due to lower global economic activity. 

Considering the current economy, the EPA anticipates the first wave of retrofit controls orders to be less 

costly than recent historical prices since suppliers shall compete for work to utilize idle resources. As an 
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indicator, demand for power plant construction labor declined from its peak in 2008.40 For example, 

Colorado Springs Utility plans to retrofit its 254 MW Martin Drake unit with a FGD for $113 million 

with projected construction completed by 2014.41,42 Timeline compliance date attainment and available 

resources are addressed in the preamble for the final rule and Response to Comments section 5C01 

“Compliance Dates.”

Comment 29: Commenter 17627 explains that facilities must start now to assemble justification of 

supplier and construction constraints to receive an extension from state regulatory agencies. However, 

the commenter points out that this step is unreasonable before the final requirements are known and 

compliance plans are designed, and permitting authorities generally do not allow any construction 

preparation until permits are granted.

Response to Comment 29: The agency believes that the MATS proposal offered sufficient regulatory

detail to inform prudent retrofit planning activities, some of which at least could be commenced without 

further delay. To cite an example, a station owner ordered two wet scrubbers (465 MW and 515 MW 

units) with scheduled start dates of 2013 and 2015.43 Timeline compliance and resource availability are 

discussed in the preamble for the final rule and Response to Comments section 5C01 “Compliance 

Dates.”

Comment 30: Commenter 17758 states that compliance for many utilities, especially those burning

eastern bituminous coals, may have to install a wet FGD which presents challenges in cost and 

installation time. The commenter estimates wet FGD will cost approximately $350/KW more than DSI, 

and the timeline for wet FGD installation will be around 60 months as opposed to 9-18 for DSI. This 

makes the EPA’s assumptions about both the cost estimates and ability to comply within 3 years 

incorrect, the commenter believes.

Response to Comment 30: The EPA disagrees with comments warning wet scrubbers are necessary for 

units burning eastern bituminous coal. The EPA examined this issue and determined DSI adequately

suffices for units burning low sulfur eastern bituminous coal. The EPA’s IPM analysis for MATS limits 

DSI retrofit controls for compliance to fuels containing less than 2 lbm SO2/MMBtu. Timeline, 

feasibility, and emissions control capability issues are discussed in the preamble for the final rule, and 

Response to Comments section 5C01 “Compliance Dates.”

Comment 31: Commenters 17775 and 17904 discuss the many steps involved in adding controls to 

coal-fired EGUs, such as initial design, development of project specifications, procurement, 

identification of bidders, solicitation, review of bids and contract negotiations, permitting, landfill 

issues, obtaining financing, final design, mobilization of workforce, construction, process tie-ins and 

 

40 Staudt, J., E., Andover Technology Partners, “Labor Availability for the Installation of Air Pollution 

Control Systems at Coal-Fired Power Plants,” www.AndoverTechnology.com, viewed November 6, 

2011

41 McIlvaine Utility E-Alert #1045; October 7, 2011

42 Colorado Springs Independent; Oct 4, 2011 “Update: Utility Strikes Deal on Emissions Control” by 

Pam Zubeck

Ref: http://www.csindy.com/IndyBlog/archives/2011/10/04/utilities-strikes-deal-on-emissions-control

43 B&W press release June 29, 2011; “B&W to Design and Supply $54 Million Emissions Control 

System for Indiana Power Plant” ref: web site: 

http://www.babcock.com/news_and_events/2011/20110629a.html
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startup testing. Commenter 17775 includes a memo (J. Edward Cichanowicz, “Feasibility of Retrofitting 

Fabric Filter Particulate Matter Control Technology to the Electric Generating Unit Inventory as 

Projected by EPA” (July 2011) Attachement 12 of EPA-HQ-OAR-2009-0234-17775) showing estimates 

of 48 months to install a single scrubber for a large unit, 50 months for a single scrubber at a small unit, 

51 months for installation of two scrubbers and 54 months to install three or more scrubbers at a single 

facility. The memo also estimates that not all existing EGUs that need a new fabric filter will be able to 

meet a 3-year compliance schedule, and even if given 4 years to comply, only 54% would be able to 

comply. The commenter also explains that time needed to obtain financing can vary greatly, with some 

regulated utilities needing to obtain approvals from their State PUCs to recover the costs, and some rural 

cooperatives needing to access the private market for funding. Commenter 17904 refers to Davis Cnty. 

Solid Waste Mgmt. v. EPA, 101 F.3d 1395, 1400 (D.C. Cir. 1996) wording that states the EPA’s MACT 

floor would “impose significant retrofitting costs that [are] unreasonable given the limited additional 

pollution control that stricter standards would achieve.” The commenter expresses concern over the high 

costs and short timeline for the necessary control retrofits.

Response to Comment 31: For discussion on the issues mentioned above, see the preamble for the final 

rule and Response to Comments section 5C01 “Compliance Dates.”

Comment 32: Commenter 18039 questions the suggestion that existing units be allowed to run for an 

additional year while a replacement is constructed, without being subject to MACT standards for that 

year. The commenter agrees that this is a reasonable scenario for facilities that will use that year to 

construct a replacement unit with significant long-term emission reductions. However, the commenter is 

concerned that a facility in the process of building replacement power may decide to operate a highemitting unit for an additional year, specifically due to the extension. The commenter therefore objects 

to the extension for fear a large amount of pollutants will result. The commenter also asks that if 

construction replacement power lasts longer than the 1-year extension, the final rule wording make clear 

that the older unit is not permitted to avoid MACT compliance beyond that year, even if the replacement 

is not yet on-line.

Response to Comment 32: Issues regarding compliance dates, extensions, state programs regarding 

agreements, replacement power construction, etc., are discussed in the preamble for the final rule.

Comment 33: Commenter 18017 states that if the proposed rule and other pending rules require 

installation of new control equipment costing hundreds of millions of dollars, the potential result could 

be early closure of their plant because the owners will be required to comply before they know whether 

the approvals necessary to operate after 2019 can be obtained. The commenters concern is that the EPA 

may establish final emission limits governing NGS PM emissions that are so stringent that a new PM 

control device will be required with compliance dates before approvals can realistically be obtained. 

This would lead to high compliance costs and could jeopardize continued operation of the NGS facility

with severe economic impacts on numerous Indian Tribes.

Response to Comment 33: The EPA will work closely with other regulatory authorities to support 

timely implementation of MATS. For further description/discussion, see the preamble for the final rule.

5. One technology per pollutant.

Comment 34: Commenter 17682 considers the EPA estimate of compliance technologies to be suspect 

because of the proposal of adopting an untested compliance technology to reduce sulfur emissions, and 

which may impact PM and Hg emissions. The commenter asks that the EPA refrain from developing 
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emission rules for each pollutant independently without considering how one compliance measure may

impact the control of other units. The commenter believes this approach leads to cost estimates that do 

not adequately reflect the cost for other sources of energy that may be required to make up for lost coalfired generation. The commenter would like to see cost estimates that adequately reflect the ultimate 

cost increases that individual home owners will need to pay.

Response to Comment 34: The agency reviewed all technologies presented within the proposal for 

adequacy and commercial availability; moreover, independent publications and trade organizations 

confirms their capability towards achieving MATS compliance.44,45,46

The EPA determined a pollutant-by-pollutant (or HAP-by-HAP) emissions standard to be appropriate in 

light of the specific language of section 112 as previously interpreted by the U.S. Court of Appeals for 

the D.C. Circuit. For a detailed discussion, see the preamble for the final rule.

Average projected cost increases to the rate payer are addressed in the preamble for the final rule.

6. Dual liquid-powder sorbent technology.

Comment 35: Commenter 17721 discusses a multi-emission reduction technology called involving a 

dual liquid-powder sorbent (DLPS), which is particularly effective in removing Hg and other HAP by up 

to 98.7%, along with SO2 and NOX emissions from coal-fired EGUs without adding control equipment 

into the flue gas stream. The commenter suggests that the effectiveness of the DLPS system for highsulfur coals makes it a valuable revision to the proposed rule as an available technology for achieving 

the emissions limits. The commenter also explains that limiting EGU MACT technology to ACI will 

limit innovation of new technologies and flexibility within the industry and asks that the proposed rule 

allow for a variety of Hg control systems.

Comment 36: Commenter 17721 considers the proposed rule vague on the point of demonstrating 

compliance with the Hg emissions limit using a Hg CEMS or a sorbent trap monitor without installing 

ACI or DSI. The commenter suggests revising the final rule to recognize DLPS technology as an 

available emission control technology for Hg and other HAP, or at least make it clear in the preamble 

that the use of a DLPS system instead of, or in combination with other technology, is permitted. The 

commenter describes three power companies operating eight generating stations that have DLPS 

technology installed, with results of up to 98.7% Hg reductions. The commenter points out that while it 

is not yet used as extensively, the DLPS technology is superior to ACI in that it has been shown to 

improve boiler efficiency in certain conditions, and fly ash from coal treated with DLPS has improved 

characteristics for reuse, unlike ACI. The commenter describes testing done between 2005 and 2008 and 

provides the results. (The commenter includes a table of “Full Scale Multi-Pollutant Test Results” in 

EPA-HQ-OAR-2009-0234-17721-A1.)

Comment 37: Commenter 17721 questions the proposed rule’s focus on ACI technology, which works 

differently from DLPS technology because ACI and DSI involve injecting a sorbent into the flue gas 

 

44 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011

45 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, 

URS Corporation, April 5, 2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf

46 ICAC, web site: http://www.icac.com/i4a/pages/index.cfm?pageid=1
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stream upstream of a PM control device to react with acid gases and Hg in the exhaust stream. DLPS 

technology, the commenter explains, captures Hg, HAP metals, SO2 and NOX during combustion to 

keep them out of the exhaust stream. The commenter points out that DLPS technology offers effective 

Hg and other HAP metals control for high-sulfur coals without the assistance of additional SO2

mitigation, making it a reasonable or superior choice compared to the DSI suggested in the proposed 

rule. The commenter asks that the proposed rule be amended to allow DLPS technology as an available 

control technology for Hg, HCl and other HAP metals, and allow units equipped with DLPS or DSI to 

qualify for SO2 emissions limits as an alternative to the HCl emissions limit.

Comment 38: Commenter 17721 points out that the proposed rule focuses on controlling acid gas 

emissions in the exhaust stack, while DLPS allows acid gas control in the furnace. The commenter states 

that DLPS can achieve a 75% reduction in SO2 emissions before the exhaust reaches the stack, where 

further emissions reductions could be achieved by a scrubber.

Response to Comments 35 - 38: Multiple comments were received advocating control technologies 

that were not represented in the EPA’s compliance cost analysis of the MATS proposal. The agency 

notes that control technologies mentioned within the proposal are neither an exhaustive nor an exclusive 

list; rather, these listings demonstrate proven available technologies for industry sector compliance. The 

EPA is not selecting, nor precluding, any particular technologies in this rulemaking but is instead 

allowing each facility to determine its preferred means of compliance with the emission rate standards.

7. Retirements.

Comment 39: Commenter 17731 questions the EPA’s view that utilities can easily retire and replace 

units that are unable to comply with the new emission limits. The commenter considers the option of 

replacing older units with more efficient units to be risky because the utility may spend the time and 

money to build new coal-fired units only to find out that the units cannot comply with the stringent new 

unit emission limits.

Response to Comment 39: This issue is discussed in the preamble for the final rule.

8. Activated carbon injection and alternatives.

Comment 40: Commenter 17734 discusses the use of amended silicates as an environmental and 

economical way to comply with existing and pending Hg regulations. The commenter describes 

amended silicates as a “drop-in” alternative that is often superior to partially activated carbon, at a cost 

competitive with ACI. The commenter explains that the amended silicates are added to the coal 

combustion gases upstream of PM control equipment to modify Hg into an inert and insoluble state. The 

commenter states that amended silicates have been designed to be compatible with concrete, allowing 

for preservation of fly ash value, and passes the EPA leachability tests. The materials have also been 

developed to avoid the sensitivity to SO3, so a high rate of Hg capture is maintained in ESPs. The 

commenter requests that the EPA revise the proposed rule to clearly state that newly developed and 

commercially-available products besides powder activated carbon can achieve similar or better results 

under different or similar chemical mechanisms.

Response to Comment 40: Multiple comments were received advocating control technologies that were 

not represented in the EPA’s compliance cost analysis of the MATS proposal. The agency notes that 

control technologies mentioned within the proposal are neither an exhaustive nor an exclusive list, 

rather, these listings demonstrate proven available technologies for industry sector compliance. The EPA 
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is not selecting, or precluding, any particular technologies in this rulemaking but is instead allowing 

each facility to determine its preferred means of compliance with the emission rate standards.

Comment 41: Commenter 17761 reports a dramatic decrease in performance of an ACI system between 

the years of 2007 and 2009. Given this unexplained decline, the commenter feels it is necessary for the 

EPA to review the longer term operating performance of control equipment when setting a Hg standard.

Response to Comment 41: Like any air pollution control technology, numerous parameters impact ACI

performance with possible causes due to operational changes, equipment degradation, etc. The owner 

retains responsibility to maintaining their emissions control system and understanding its operation to 

continuously achieve compliance. ACI is a proven technology for Hg removal with multiple successful 

installations.47 See the preamble for the final rule for more information.

Comment 42: Commenters 17796 and 17869 indicate that the pollution control technology industry 

continues to develop new and more cost effective ways to reduce Hg emissions. Commenter 17796 

discusses the DOE research on costs of applying activated carbon at various sites. The commenter states 

that this and other studies show a continued decrease in Hg control costs, with a decrease approaching 

50% less for coal-fired EGUs than 1999 baseline estimates. Commenter 17869 quotes the OMB review 

of ACI technology which states; “the availability and development of ACI technology has shown that 

implementation can be done by a majority of utilities, and the competitive marketplace will continue to 

reduce the costs for these technologies.”

Response to Comment 42: The EPA thanks the commenters for the comments supporting the standard.

Comment 43: Commenters 17813 and 17816 state that the EPA fails to provide complete cost-benefit 

analysis of beyond-the-floor limit. Commenter 17813 considers this to be an underestimate, in part 

because more units will be impacted than predicted. The commenter sees the benefit for lignite beyondthe-floor limits to be smaller than the annual benefits predicted for Hg reductions, since there are fewer 

lignite units and they already comply with the floor limit.

Comment 44: Commenter 17930 states that the EPA failed to provide the proper cost-benefit analysis

given the disproportionally high cost of the beyond-the-floor limit compared to any potential gains. 

According to the commenter, the EPA’s estimate of annual cost of implementing the beyond-the-floor 

limit ($86.7 million) is far greater than the possible benefits of the beyond-the-floor limit. The EPA 

predicts that the annual benefit of Hg reductions for the entire rule is merely $450,000 to $890,000 by

2016. (See Utility MACT Rule Proposal at 25078. Price estimate at a 7% discount rate. At a 3% 

discount, the estimated Hg-related benefits are $4.1 to $5.9 million.) The commenter adds that the 

benefit for the lignite beyond-the-floor limit must be much smaller given the proportion of lignite units 

compared to other coal- and oil-fired units and since lignite units would already be complying with a 

floor limit.

Comment 45: Commenter 17904 questions the EPA assumption that a unit equipped with ACI and a 

fabric filter can achieve the beyond-the-floor standard with no additional cost. The commenter explains 

that such systems have performance limitations and will not achieve the proposed limit consistently, so 

alternative and additional controls will need to be considered. The commenter agrees with the dismissal 

of fuel switching because the variable Hg content of lignite combined with captive mine mouth designs 

 

47 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011
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makes the economic impact a marker for establishing actual costs of compliance, which would be 

prohibitive.

Response to Comments 43 - 45: A quantitative analysis of costs was included in the MACT Floor TSD

to illustrate the feasibility of the beyond-the-floor standard for lignite. The EPA established the BTF 

limit since ample evidence for ACI and fabric filters consistently show high Hg removal rates with a 

wide range of coals. The BTF limit may be achievable through other means, such as a wet scrubber with 

bromide addition. In other cases, halogen addition to promote Hg oxidation and capture may be 

beneficial. ACI is a proven, mature technology for capturing Hg.

48 Comments claiming BTF Hg 

emission rates for lignite fuels as financially impractical and technically unattainable are unfounded. 

Besides fuel blending, commercial products exist to augment49 Hg capture by ACI - such as ToxeconTM 

for hot side ESPs, halogen addition for PRB,50 brominated sorbents for low chlorine fuels.51

The EPA acknowledges lignite fuels contain increased Hg levels and display greater Hg variability than 

PRB or bituminous fuels; however, these two aspects do not make BTF emission rates unattainable or 

financially prohibitive. ACI selectively captures the oxidized form of Hg regardless of fuel source or 

rank.52 Yet, the presence of SO3 interferes with Hg capture and requires removal to avoid high activated 

carbon injection rates.53 Furnaces discharging high concentrations of elemental Hg are indicative of low 

chlorine content fuels (like Texas lignite) and impede ACI performance; under these circumstances, 

chemical addition to promote oxidization (such as a halogen, as cited earlier) improves performance. 

Halogens can be inserted: pre-combustion (added to fuel), during combustion (furnace insertion), post 

combustion (gas stream injection) or through carbon impregnation.54,55 Meanwhile, adjusting carbon 

injection rate will compensate for fuel Hg variability. Consequently, the EPA maintains current 

technology allows BTF Hg capture rates as proposed. See the preamble for the final rule for further 

discussion.

9. Coal rank/type.

Comment 46: Commenter 17757 explains that coal rank or type has an impact on the design and 

operation of boilers and associated control equipment. The commenter believes the EPA has not 

considered the costs of boiler modifications and control technology retrofits in the proposed rule with 

respect to the coal rank and related factors. The commenter believes these distinctions should be 

considered and points out that they were factored into the emission rates for the acid rain program and 

prior Hg proposals issued by the EPA.

 

48 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” p. 19, March 31, 2011

49 ICAC Report: “Enhancing Mercury Control on Coal-Fired Boilers with SCR, Oxidation Catalyst and 

FGD”

50 NESCAUM report, op. cit., p.20

51 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, 

URS Corporation, April 5, 2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf

52 NESCAUM Report, op. cit., pp.19-20

53 Ibid. p.19

54 Solvay Chemicals publication “Mercury (Hg)”

55 ICAC Report, op. cit.
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Response to Comment 46: Although the Acid Rain Program considered coal rank effects, statutory 

structure for creating Utility MACT (MATS) required the best performing 12% of operating units to 

determine emission limits. A survey of operating units (ICR data request) established the standards set 

forth within the MATS proposal. 

Numerous criteria establish boiler/furnace design56 with coal rank serving as a starting point. However, 

coal rank is not the sole factor in furnace design. Fuel combustion properties like: heat liberated, ash 

content, ash fusion point, percent carbon, and moisture content influence boiler design. Likewise, to 

establish desired pollution removal rates, proper design of emissions control equipment requires 

consideration of multiple criteria such as flue gas constituents and process chemistry.

57 Coal ranking, as 

established by ASTM D388, serves to provide basic information on combustion properties for 

commercial application;58 it is an inadequate metric for the controls industry. Consequently, the EPA 

finds no basis for additional creation of fuel based sub-categories from the proposal – see the preamble 

for the final rule for additional reasoning.

The EPA examined fuel switching and fuel blending during the promulgation of CSAPR (Transport 

Rule) regulation; the same issues arose during MATS comment period. Coal switching is another 

mechanism for compliance often serving to supplement other operating pollution controls. Switching to 

lower sulfur within eastern bituminous fuels may impact performance of a cold-side ESP. Some ESPs 

operating at acceptably high collection efficiencies with the unit burning high- or medium-sulfur 

bituminous coal may experience lost collection efficiency with lower sulfur coal; the extent of this 

occurrence depends on existing ESP design margins, coal sulfur content percentage change, and other 

factors. In any case, industry experience demonstrates inexpensive practices are available to regain high 

ESP performance with lower sulfur fuels; these include ESP upgrades to components and/ or flue gas 

conditioning.59 The EPA assumes costly ESP replacement is unnecessary for units switching from 

higher to lower sulfur bituminous fuels. 

For switching across ranks, a cost adder was also included in the IPM modeling to capture the potential 

cost burden of de-ratings that might accompany switching from high rank to a lower rank fuel (very low 

sulfur sub-bituminous coal) or blend. The EPA’s analysis examined a unit’s past historical data for 

lower rank fuel firing capability; if demonstrated, the agency assumed units made the investments in the 

past to handle lower ranked coals, and thereby can return to firing these fuels in the future. For policy 

crafting, IPM analysis included a coal switching option, assuming units capable of firing low rank fuels 

can increase from a historically demonstrated low percentage to a higher percentages, if economic. This 

option includes an appropriate derate in output, increase in heat rate, and additional capital and operating 

costs. Details of this and other IPM updates for this rule are provided in the IPM Modeling 

Documentation.

Finally, the MATS regulation is an emissions rate-based compliance program. The EGU owner has 

multiple options for attaining compliance: fuel switching, fuel blending, retrofit with controls, etc. 

Changing fuel is an owner’s decision, not a regulatory requirement.

 

56 Steam, 41st Ed. 2005, Babcock & Wilcox Company

57 Ibid.

58 Ibid. p.9-5

59 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, 

URS Corporation, April 5, 2011, http://www.supportcleanair.com/resources/studies/file/4-8-11-

URSTechnologyReport.pdf
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Comment 47: Commenter 17796 states that the cost and degree of Hg reduction depends on coal type 

and additional costs to upgrade particulate pollution control to accommodate additional particle loading 

from ACI. The commenter references a DOE study finding that western coal with low chlorine levels 

emits higher amounts of elemental Hg, and is more readily controlled with ACI impregnated with 

bromine, with one example facility estimate of $26,200/lb of Hg controlled at 90% using halogenated 

activated carbon. The DOE estimated the beyond-the-floor option to be $22,496/lb of Hg removed. The 

most recent report cited states that “the ACI systems have the potential to remove more than 90% of the 

Hg in many applications based on results from NETL’s field testing program, at a cost estimated to dip 

below $10,000/lb of Hg removed. However while the results achieved during NETL’s field tests met or 

exceeded program goals, only through experience gained during long term continuous operation of these 

advanced technologies in a range of full-scale commercial applications will their actual costs and 

performance be determined.”

Response to Comment 47: The EPA thanks the commenter for the comments submitted.

Comment 48: Commenter 17807 discusses the lower chloride coals ranging from 0.05 to 0.10% in the 

Illinois basin, but states that it would be difficult to obtain necessary chloride levels to achieve 

compliance with the proposed HCl emission limit. The commenter goes on to say that other facilities 

will be faced with similar issues and will need to consider other coal sources to achieve compliance with 

the HCl limit, which will increase demand and impact long term availability of these coals and decrease 

fuel procurement flexibility and reliability.

Response to Comment 48: The EPA determined further fuel subcategorization is unwarranted. For a 

complete discussion, see the preamble for the final rule.

Comment 49: Commenter 18033 quotes the EPA position stated in CAMR, “[a]t some point in the 

future, the performance of control technologies on Hg emissions could advance to the point that the rank 

of coal being fired is irrelevant to the level of Hg control that can be achieved....” The commenter states 

that while controls for Hg emissions have arguably reached this point based on the proposed MACT 

standard, this is not the case for acid gas control for higher sulfur coals. If a well-controlled unit burning 

higher sulfur coals cannot meet the standard, the commenter believes the EPA needs to revise the 

proposed rule accordingly through further subcategorization to ensure that all coals are able to meet the 

applicable standards.

Response to Comment 49: The EPA determined further coal subcategorization is unnecessary for 

compliance since commercially available technologies for SO2 control exhibit superior removal 

performance for MATS acid gases.60 For scrubbed units firing high sulfur coals, sufficient MATS acid 

gas capture is expected for compliance.61,62 A complete discussion follows in the preamble for the final 

rule.

10. IPM modeling.

 

60 “Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants”

by Lipinski, Leonard, Richardson; published by URS; April 5, 2011

61 Ibid.

62 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” p. 19, March 31, 2011
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Comment 50: Commenter 17775 commissioned a consultant to conduct IPM modeling runs using 

control technology assumptions the commenter considers to be more realistic than those chosen by the 

EPA. The modeling involved three runs to evaluate the consequences of the EPA’s decision to regulate 

all HAP, not just Hg. The commenter says the reference case was run assuming CAIR was implemented

in 25 states and the District of Columbia, and one sensitivity run assuming that the proposed Transport 

Rule would be implemented with the proposed rule with only Hg emission limits. The final run was the 

same as the sensitivity run, except that the proposed rule was assumed to cover all HAP. The commenter

states that the run results show that regulation of the non-Hg HAP adds approximately $10.5 billion to 

the total system costs in the first years of compliance and over $8 billion annually in following years 

with the 2030 compliance cost difference at over $9 billion annually. Together with the proposed rule, 

the Transport rule was estimated to add $22.2 billion to total system costs in 2015, $21.1 billion by 2020 

and $25.7 billion annually by 2030.

Response to Comment 50: The EPA has updated its modeling in the final rule, compliance costs are 

found in the RIA and the preamble for the final rule.

The agency received numerous comments regarding independent modeling analysis performed by

commercial entities to contest EPA’s IPM results. The EPA contends these sources incorporate 

inaccuracies within their models which dramatically influence the basis of these comments. For a 

discussion addressing the limitations of industry performed modeling studies, see the preamble for the 

final rule.

Comment 51: Commenter 19114 feels revisions are needed for the inputs to the IPM model. The 

commenter gives the SCR cost estimates as an example, as they are below industry estimates for 

installed costs and should be increased by at least 20%. The commenter also states that it is unclear if the 

EPA is correctly accounting for allowance for funds used during construction (AFUDC) and owner’s 

cost on fabric filter retrofits. The commenter also asks if ACI and DSI costs include transfer, handling 

and storage. The commenter gives the example of IPM model results for Northeastern unit 3-4, which 

showed they could comply with the proposed rule using DSI. However, the commenter states that in 

March 2011, the EPA issued a Federal Implementation Plan requiring FGDs to reduce SO2, making the 

HAP scenario proposed by the EPA unrealistic. The commenter asks that the EPA reevaluate its 

modeling with correct inputs based on all current and proposed rules.

Response to Comment 51: IPM calculates fabric filter AFUDC correctly for a 2-year construction 

cycle; the typically anticipated cycle for a fabric filter.63 The B2 calculation description (as illustrated on 

the spreadsheet view) is in error. The mathematical calculation actually performed is: B2 = 6% x 

(CECC+B1) {incorrectly typed as: 6% x CECC + B1}. 

Both ACI and DSI estimated costs calculations include all equipment from unloading to injection. 

 

63 Sargent & Lundy, “IPM Model – Revisions to Cost and Performance for APC Technologies Particle 

Matter Control Cost Development Methodology FINAL,” March 2011, Project 12301-009, Perrin 

Quarles Associates, Inc
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Due to surrogacy co-benefit effects of controls, FGD controls capture HAP acid gasses more efficiently

than SO2.

64 Depending upon a unit’s control configuration, equipment performance and fuel 

characteristics, ACI may be unnecessary.

65

Comment 52: Commenter 19114 expresses concern that the gas supply curves in the IPM model are 

short on supply and inelastic in the near-term, based on comparison with data from EIA’s 2011 Annual 

Energy Outlook. The commenter disagrees that gas prices have the most significant impact on unit 

retirements and considers the exposure of a coal unit to future environmental constraints and potential 

expenditures to be the biggest factor in retirements. As such, the commenter suggests the EPA include 

future regulatory constraints within the model or risk understating the impact of the rule being proposed.

Response to Comment 52: Besides retrofit controls, payroll, debt service, and maintenance, an EGU’s 

largest fiscal expense is fuel procurement with market conditions determining operational viability of an 

EGU. The EPA approached gas supply market conditions conservatively. The agency has fully 

documented its assumptions and framework for modeling natural gas in IPM for both the proposed and 

final MATS. This information can be found in Chapter 10 of the IPM documentation 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter10.pdf). The documentation 

provides a thorough overview of the natural gas module, describes the very detailed process-engineering 

model and data sources used to characterize North American conventional, unconventional, and frontier 

natural gas resources and reserves and to derive all the cost components incurred in bringing natural gas 

from the ground to the pipeline. Also documented are the resource constraints, liquefied natural gas 

(LNG), demand side issues, the natural gas pipeline network and capacity, procedures used to capture 

pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key 

gas market parameters. Current and projected natural gas prices significantly impact anticipated coalfired retirements. IPM Natural Gas (NG) modeling is discussed in the preamble for the final rule.

Comment 53: Several commenters (19536, 19537, 19538) discuss the EPA’s documentation of IPM 

modeling that shows the EPA found that the costs of complying with a 0.0001 lb/MMBtu HCl MACT 

limit, which would be achieved through installation of scrubbers or scrubber upgrades, installation of 

baghouses at fluidized bed boilers, and/or DSI with baghouses to achieve SO2 removal efficiencies of 

92% to 96%, would be cost effective. The commenters point out that the EPA did not account for the 

fact that numerous units will have to achieve the required level of SO2 controls soon under other state or 

federal regulation to meet ambient air quality standards. The commenter goes on to list additional 

findings by the EPA based on IPM modeling, and agrees with the EPA’s assessment that the 

environmental and health benefits outweigh the costs, thanks to the cost-effective technologies and 

methodologies summarized.

Response to Comment 53: The EPA thanks the author for the comments submitted. 

The EPA’s IPM modeling of MATS accounts for all finalized state and federal regulations. See RIA 

chapter 3 and “Documentation Supplement for EPA Base Case v.4.10_MATS – Updates for Final 

Mercury and Air Toxics Standards (MATS) Rule” for additional discussion.

11. Difficulties with control technologies.

 

64 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” by

Lipinski, Leonard, Richardson; published by URS; April 5, 2011

65 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” March 31, 2011
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Comment 54: Commenter 17702 acknowledges that they have compliance options to meet the proposed 

emission reduction requirements, such as adding carbon injection or switching to a wet scrubber. 

However, the commenter points out that these options will increase cost and defeat the environmental 

objectives because they will increase water use and eliminate the sale of the byproduct material from a 

dry fabric filter.

Response to Comment 54: The EPA does not anticipate units with fabric filters necessarily increasing 

water consumption because scrubber retrofit becomes unnecessary with the DSI option for rule 

compliance. Depending upon treatment rate and reagent (sorbent) selected, ACI or DSI may impact fly

ash sales; on the other hand, activated lime reagent effectively removes acid gases and should not 

adversely impact fly ash marketability. Mineral-based Hg sorbents are effective and commercially 

available for overcoming concerns with activated carbon. 66 Additionally,see response to comment 4 

(above).

Comment 55: Multiple commenters (17868, 17912, 19213) state that the EPA did not address physical 

space and age-of-plant issues when setting BDT, MACT, and NSPS because it did not recognize that 

older coal-fired power plants have space constraints and may only be able to “build up” if they install a 

fabric filter. This means that smaller and older plants will not be able to comply with the proposed rule. 

Commenter 17868 considers the EPA’s projection that only 3% of the industry’s coal-fired capacity will 

become uneconomical due to the proposed rule to be flawed and also points out that the EPA did not 

identify how many of the public power units will implement control technologies under separate 

regulations or state implementation plan changes and revisions to effluent guidelines which may take 

power plants offline for weeks or months in the next 5 or more years. Commenter 17868 believes the 

EPA’s estimates of the number of plants that will require additional controls, and these impacts will hit 

the upper and lower midwest, southeast, and southwest the hardest.

Response to Comment 55: For discussion on available space limitations, small stations, small 

companies and control equipment available, see Response to Comments section 5C01 “Compliance 

Dates” which discusses controls for congested sites and combing emissions from multiple units into a 

single control device. Additional discussion is provided in the preamble for the final rule.

The agency accounts for current state air emissions regulations in its IPM modeling platform; for 

detailed discussion, see RIA chapter 3 and “Documentation Supplement for EPA Base Case 

v.4.10_MATS – Updates for Final Mercury and Air Toxics Standards (MATS) Rule.”

Comment 56: Commenter 18433 states that the suggested method of controlling PM emissions from 

oil-fired units is ESP because the PM is generally too “sticky” from organic content to be collected 

reliably in fabric filters due to plugging the pore holes in the bags.

Response to Comment 56: The EPA thanks the submitter for their input. The agency responded by

creating a subcategory for oil-fired, non-continental units (excluding Alaska-based units) – see final 

rule. Additionally, the final regulation will change the PM standard from total PM to filterable PM. The 

EPA acknowledges oil-fired units typically control PM emissions with an ESP and believes the final 

MATS standard for oil-fired units can be met with a well-designed, well maintained ESP for 

maintaining PM control. The EPA does not select any specific technology for MATS compliance; rather 

 

66 Hizny, W., Magno, G., Yang, X., “BASF Mercury Sorbent ZXTM for Control of Coal-fired Power 

Plant Hg Emissions,” Paper # 176, Power Plant Air Pollutant Control “MEGA” Symposium, August 30 

– September 2, 2010, Baltimore, MD
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the standard sets permissible emission rates which allow the owner flexibility in selecting controls and 

fuels for compliance. See the preamble for the final rule.

12. Natural gas prices.

Comment 57: Commenter 17810 does not believe that the EPA has adequately considered the best 

available data on natural gas prices and supply, and requests that the EPA perform additional analyses of 

control options using updated information.

Response to Comment 57: The agency has fully documented its assumptions and framework for 

modeling natural gas in IPM for both the proposed and final MATS. This information can be found in 

Chapter 10 of the IPM documentation (http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of the natural gas 

module, describes the very detailed process-engineering model and data sources used to characterize 

North American conventional, unconventional, and frontier natural gas resources and reserves and to 

derive all the cost components incurred in bringing natural gas from the ground to the pipeline. Also 

documented are the resource constraints, liquefied natural gas (LNG), demand side issues, the natural 

gas pipeline network and capacity, procedures used to capture pipeline transportation costs, natural gas 

storage, oil and natural gas liquids (NGL) assumptions, and key gas market parameters.

Comment 58: Commenter 18033 considers replacing coal with natural gas to be problematic given that 

the cost of natural gas is volatile and makes up over 70% of the levelized cost of electricity (LCOE). The 

commenter describes a price spike from $6/MMBtu to $13/MMBtu in 2005 and details some of the 

environmental issues recently created by harvesting shale reserves. The commenter asks the EPA to 

examine a constructive policy framework that removes this and other regulatory impediments and 

promotes the deployment of advanced coal technologies. The commenter states that replacing older U.S. 

coal plants with advanced supercritical generation could create $1.2 trillion in economic benefits and 6 

million jobs during construction as well as avoiding the release of 440 million metric tons of CO2.

Response to Comment 58: The agency fully documents its assumptions and framework for modeling 

natural gas in IPM for both the proposed and final MATS. This information can be found in Chapter 10 

of the IPM documentation (http://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of the natural gas 

module, describes the very detailed process-engineering model and data sources used to characterize 

North American conventional, unconventional, and frontier natural gas resources and reserves and to 

derive all the cost components incurred in bringing natural gas from the ground to the pipeline. Also 

documented are the resource constraints, liquefied natural gas (LNG), demand side issues, the natural 

gas pipeline network and capacity, procedures used to capture pipeline transportation costs, natural gas 

storage, oil and natural gas liquids (NGL) assumptions, and key gas market parameters.

13. Fuel switching.

Comment 59: Commenters 18433 and 19213 disagree with the assumption that all coal and fuel-oil 

units can be used with available control technologies. The commenters state that such fuel switching 

from one fuel type to another or fuel blending can be expensive, and facilities in Guam are restricted in 

their fuel choices and must rely on oil currently.

Response to Comment 59: The difficulties American territories experience is acknowledged. The 

agency created a subcategory for oil-fired, non-continental units (excluding Alaska-based units) 
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realizing the unique situation and limitations these units face – see final rule. The MATS standard sets 

permissible emission rates which allow the owner flexibility in selecting controls and fuels plus 

establishes alternatives for compliance. See the preamble for the final rule.

Comment 60: Commenter 19114 expresses concern with the IPM analysis suggesting that units will 

switch fuel to meet the beyond-the-floor standard. The commenter considers this unreasonable because 

fuel switching could change the subcategory of the unit, thus subjecting it to a more stringent Hg limit. 

Also, the commenter points out that fuel switching costs used by the EPA do not account for all required 

coal conversion activities or for projects such as new coal unloading and coal yard facilities to 

accommodate subbituminous coal which is often delivered by rail instead of truck or conveyor like 

lignite fuel generally is. Additional facility upgrades that the commenter would like to see in the EPA’s 

estimate include dust collection, new coal conveyers, fire protection, ventilation, ESP performance and 

water cannons to handle new fuel, soot and ash characteristics.

Response to Comment 60: Compliance issues, as they relate to sub-categories, are discussed in the 

preamble for the final rule. 

Beyond-the-Floor (BTF) issues are discussed in the preamble for the final rule.

The agency believes that the fuel switching costs used in IPM are accurate. A few commenters 

expressed concern about the technical feasibility of switching to 100% subbituminous coal for power 

plants originally designed for 100% lignite. The EPA carefully considered these comments by analyzing 

units currently burning either 100% lignite or a blend of lignite and subbituminous coal. Lower rank 

coal (e.g.: lignite) fired units are over-designed for the requirements to successfully burn higher rank 

(sub-bituminous) fuels. Evidence for this over-design becomes apparent through boiler furnace size 

comparison for equal unit sizes. Low-slagging lignite furnaces are as large (or larger) than an equivalent 

subbituminous furnaces while high-slagging lignite furnace dimensions can be up to 50% larger.67,68

Lignite’s lower heat of combustion (compared to higher rank coals) requires increased material flow 

rates, thus requiring larger system components (coal handling systems, pulverizers, boiler draft fans, air 

emission controls, and ash handling systems) to produce an equivalent amount of power. Lignite units 

currently blending a significant percentage of sub-bituminous coal likely made the important but 

relatively minor improvements in coal handling and dust suppression systems needed to safely

accommodate the friability and dusting associated with sub-bituminous fuels.69,70 Because of its low 

heating value, lignite rail transportation becomes uneconomical; typically, lignite fired stations are 

located close to local mines, so called “mine mouth” plants, which convey coal by belt or transfer by

large earth hauling trucks directly to the plant. Switching from local lignite to a distant subbituminous 

fuel source may entail minor rail improvements to spur and coal receiving systems; on the other hand, 

these systems may already be in place at many lignite plants. Aside from these fundamental 

requirements, minor upgrades to boiler cleaning systems71 with modern “water cannons”

72 or 

 

67 Alstom Power, Inc, Clean Combustion Technologies, Fifth edition, 2009 

68 Steam, 41st Ed. 2005, Babcock & Wilcox Company

69 http://www.powermag.com/coal/Luminants-Big-Brown-Plant-wins-for-continuous-improvement-andsafety-programs_117.html

70 http://www.powermag.com/coal/Monticello-Steam-Electric-Station-Mount-Pleasant-Texas_464.html

71 http://www.cba-ssd.com/Applications/knowledgeBase/PRBcoal/FurnaceClean.htm

72

http://www.clydebergemann.com/content_manager/go/ID/28544/dbc/c40320c1b648988300168ec8918e

855d
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“intelligent sootblowing”

73 systems to cope with various issues from slagging or higher reflectivity of 

ash may be required. As a noteworthy example, the 480 MW Gibbons Creek station of Texas Municipal 

Power Agency (TMPA) switched from 100% lignite to 100% sub-bituminous coal firing. “In 1996, 

TMPA management switched exclusively to PRB [Powder River Basin] coal to improve the economics 

of Gibbons Creek and to lower SO2 emissions. The switch required relatively minor changes to the 

physical plant and its control systems. Only one of the original eight mills was removed from service, 

although only five mills are needed for full load operation using PRB coal as fuel.”

74 For all of the 

reasons discussed above, the EPA believes that a switch from lignite to 100% subbituminous coal or to a 

lignite/subbituminous blend is a technically feasible compliance option. Lignite units choosing to make 

a switch to higher grade sub-bituminous coal would be expected to reduce total coal consumption with 

lower air pollutant emissions while increasing boiler efficiency and net electrical output.

Coal blending is further discussed in the preamble for the final rule.

Comment 61: Commenter 17621 notes that the following comment presents the commenter’s 

observations and experience with this [EPA’s] approach to reducing HCl at a site burning Powder River 

Basin (PRB) coal and another site burning an eastern bituminous coal. Both of these studies were shortterm in nature, with the test period of several weeks, evaluating a number of different parameters each 

day. Thus these results are not able to provide any insight on the long-term performance and impacts of 

dry sorbent injection. The commenter is not aware of other demonstrations of this approach that have 

been conducted by independent, third parties. However, because of their citation in the technical 

supporting documents for the proposed MACT rule, we also discuss tests conducted by a sodium sorbent 

supplier.

The commenter participated as a technical advisor in the first commercial demonstration of the 

TOXECON(r) process at We Energies’ Presque Isle Power Plant. The project was co-funded by DOE 

under the Clean Coal Power Initiative. The primary objective of the project was to demonstrate the 

TOXECON configuration-downstream of a hot-side ESP in this case-with ACI for Hg control. A 

secondary goal was to determine the ability of powdered Trona injection to reduce SO2 by 70% and also 

to realize some NOX emission reductions. These pollutant reductions were to be obtained while 

simultaneously injecting activated carbon for Hg control (ADA-ES, 2008). The tests showed that the 

Trona could reduce SO2, but that it also converted enough nitrogen oxide (NO) to nitrogen dioxide 

(NO2) to produce a visible brown plume. Trona injection also reduced Hg capture by ACI significantly. 

Without Trona injection, the Presque Isle unit was able to maintain 90% Hg reduction at ACI rates of 1 

to 2 pounds per million actual cubic feet (lb/MMacf). During Trona testing, the unit was unable to 

achieve a 90% Hg removal over a short 1-hour test, even when the ACI rate was increased to 4.6 

lb/MMacf.

As these tests were conducted before the EPA made known its intent to regulate acid gases from EGUs, 

the project did not measure HCl emissions-especially not as a function of activated carbon sorbent 

injection rate. Therefore, these tests do not inform us about the amount of Trona or sodium bicarbonate 

that would be needed to meet the proposed HCl limit, nor whether that amount would cause a brown 

plume and/or plugging, as well as impact Hg capture by ACI. Tests by Solvay Chemicals (a major 

supplier of Trona and sodium bicarbonate) at a low-sulfur eastern bituminous-fired power plant 

(reporting ~ 0.5-1% sulfur in the coal and 50-60 ppm HCl in the flue gas) may provide some clues. In 

 

73 A. Manay, Clyde Bergemann, Inc, Study of the full implementation of the SmartCleanTM System at 

SRP Navajo Power Generation Unit 3, 2010 Coal Gen Conference, August 2010.

74 http://www.prbcoals.com/pdf/PRBCoalInformation/Power-Oct03-Smallmuni.pdf
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this one test campaign, Solvay Chemicals reported 50% HCl removal at a sodium bicarbonate injection 

rate sufficient to capture 10% of the SO2-i.e., a relatively low injection rate (Davidson, 2010).

Since brown plumes have been observed at plants using sodium sorbents for SO2 control, but not at 

plants using these sorbents for SO3 control, it is possible that low sodium injection levels may not 

produce brown plumes or plugging; this may apply for western bituminous coals with coal chloride 

concentration slightly greater than the proposed limit for HCl. However, this may not be possible for 

subbituminous coals with chloride concentration greater than about twice the proposed limit, where HCl

removals up to 90% may be required. The situation for eastern bituminous coals, with their higher 

chlorine content, is discussed below. To go beyond a reliance on engineering judgment, it is important to 

determine-via independent tests fully open to public scrutiny-whether these single results obtained on an 

eastern bituminous coal are representative of results for the fleet of PRB-fired power plants. Only then 

will the public and the industry truly understand the ability of sodium sorbent injection combined with a 

fabric filter to reduce HCl emissions to the proposed limit at plants burning western coals, and to do so 

without impacting plume opacity and/or Hg emission reductions.

In 1996-97, the commenter conducted tests of both sodium bicarbonate and hydrated lime DSI upstream 

of a pilot baghouse at Hudson Generating Station owned by Public Service Electric and Gas (EPRI, 

1998). This plant burned a coal that typically contained less than 1.0% sulfur and less than 0.1% 

chlorine; the corresponding flue gas HCl concentration at the pilot’s inlet duct was 61-97 ppm. The 

results of these tests, presented in the document, show that HCl reductions up to 90% could be achieved, 

but only at sorbent-to HCl injection ratios of about 12. For a 500 MWe plant with 100 ppm HCl, a 

normalized stoichiometric ratio (NSR) of 12 is equivalent to increasing the ash loading by 50-60% or by

250-300 tons/day (normal ash loading is about 500 tons/day).

The Hudson site, with an HCl concentration in the mid-range for eastern bituminous coals, would have 

required 97-98% HCl removal to achieve the proposed MACT limit (equivalent to ~ 2 ppm). Plots of 

pollutant removal versus sorbent injection rate typically become very flat at high injection rates-i.e., 

increase very slowly if at all with increasing sorbent injection-so it is not clear from the available data if 

hydrated lime or sodium bicarbonate could routinely provide greater than 90% reductions at any 

injection rate.

Response to Comment 61: The EPA appreciates the commenter’s observations. See the preamble for 

the final rule for more discussion on DSI technology.

14. Miscellaneous.

Comment 62: Commenter 18033 questions the EPA assumption that 50% or more of the current fleet 

have scrubbing technology installed and that the number will be nearly two-thirds by 2015. The 

commenter says that over half of the scrubbers mentioned will be at the end of their useful life by 2015, 

so cost will be associated with upgrading these scrubbers to achieve compliance. Also, the commenter

points out that the scrubbers were only required to achieve 70% SO2 removal when constructed. 

Bringing these scrubbers into compliance will require more than modifying spray heads and adding 

absorber trays and could double the projected upgrade costs for older units and increase retirements. 

This leads the commenter to conclude that approximately 25% of the current coal-fired fleet will retire 

early as a result. The commenter also mentions that as the MACT floor is set on the average of the top 

12%, only 6% can be expected to meet the standard without modification.
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Response to Comment 62: The agency has a different outlook regarding replacement of existing 

control equipment. The EGU sector continuously demonstrates the ability to operate equipment beyond 

its originally intended lifespan (typical design life of 30 years) through replacement or upgrade of worn 

components. For example, 592 units (59% of the coal fired fleet) exceed 40 years of age.75

Consequently, the agency believes owners will operate emissions control equipment well beyond a 20-

year period and shall attempt the more economically attractive option of upgrading equipment rather 

than replacement. Depending on scrubber age and current SO2 removal rates, a wet scrubber can be 

upgraded for $5-$100 per kW of unit size.76 Furthermore, for acid gas removal compliance, an owner’s 

option includes augmenting existing controls by installing DSI.

Comment 63: Commenter 18023 reports that many of their units have SCRs and scrubbers but will not 

be able to meet proposed emission limits in most cases and will need baghouses and CEMS installed at a 

cost of $8.5 billion to comply with the proposed limits and monitoring requirements. The commenter 

notes that this price could increase due to the large number of plants rushing to comply with all existing 

and proposed regulations which could drive up the costs of materials and skilled labor. The commenter 

also shows that the EPA’s estimate for the same facilities gives a $4 billion cost, showing that the EPA’s 

estimates are understated.

Response to Comment 63: The EPA disagrees with commenter’s assertion that the EPA’s cost 

projection is understated, and maintains that the EPA’s incremental cost projections are reasonable. The 

RIA includes projected controls retrofits and costs as updated in the EPA’s analysis for the MATS final 

rule. The EPA has provided the maximum 3-year period for sources to come into compliance. Sources 

may also seek a 1-year extension of the compliance period from their Title V permitting authority if the 

source needs that time to install controls. The EPA will work with relevant authorities to ensure a 

smooth transition with this rule and address specific issues. For discussion on some of the issues 

mentioned above, see the preamble for the final rule and Response to Comments section 5C01 

“Compliance Dates.” In addition, there are certain provisions for granting utilities some additional time 

to comply, if conditions warrant (see preamble).

Comment 64: Commenters 16826 and 17386 consider the cost and logistic burdens to comply with the 

proposed rule a concern because they know of a unit containing a once-through circulating water system 

that must meet NPDES water discharge limits. The commenters say that these permit limits indirectly

restrict the hours of operation and load, and request a “Limited Use” category to relieve this and other 

oil-fired facilities in a similar scenario.

Response to Comment 64: Based on the concerns submitted, the EPA established a “limited-use”

subcategory for liquid oil-fired EGUs. For a detailed discussion, see the preamble for the final rule.

Comment 65: Commenter 16849 reports a compression of resources available between 2007 and 2008 

that led to the price of SCR installation to jump from $31 million in 2007 to $58 million in 2008 at a 

neighboring, like-sized facility.

 

75 M.J. Bradley & Associates Report; “Ensuring a Clean, Modern Electric Generating Fleet while 

Maintaining Electric System Reliability,” August 2010, p.16; Table 5 “Characteristics of U.S. Coal 

Plants.” Ref: 

http://www.mjbradley.com/sites/default/files/MJBAandAnalysisGroupReliabilityReportAugust2010.pdf

76 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” by

Lipinski, Leonard, Richardson; published by URS; April 5, 2011
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Response to Comment 65: Many factors influence retrofit cost besides locality;77 a neighboring facility

does not necessarily mean an “identical” facility. The present economic conditions differ drastically 

from the situation experienced in 2007-2008; retrofit controls cost models were determined during this 

time period and based on 2009 pricing. With excess resources currently available, the agency anticipates 

aggressive competition by suppliers to win project award subsequently resulting in price relaxation from 

pre-2009 levels.

Comment 66: Commenter 17296 provides information regarding the use of calcium bromide as a costeffective way to reduce Hg emissions from coal-fired units. The commenter says that calcium bromide 

has been found to effectively oxidize elemental Hg so that it can be better controlled by traditional 

control devices. (The commenter provides a White Paper on Calcium Bromide Technology for Mercury

Reductions (August 2010) as part of EPA-HQ_OAR-2009-0234-17296-A5 and additional research as -

17296, -17296 and refers to NESCAUM report “Technologies for Control and Measurement of Mercury

Emissions from Coal-Fired Power Plants in the United States: a 2010 Status Report” at 

http://www.nescaum.org/topics/mercury.)

Response to Comment 66: The EPA thanks the submitter for the information provided in support of the 

proposed rule. Multiple comments were received advocating control technologies that were not 

represented in the EPA’s compliance cost analysis of the MATS proposal. The agency notes that control 

technologies mentioned within the proposal are neither an exhaustive nor an exclusive list, rather, these 

listings demonstrate proven available technologies for industry sector compliance. The EPA is not 

selecting, or precluding, any particular technologies in this rulemaking but is instead allowing each 

facility to determine its preferred means of compliance with the emission rate standards.

Comment 67: Commenter 17807 discusses a new $1.2 billion project to upgrade environmental controls 

and repower a power station which led to an annual reduction of Hg, SO2, NOX and PM emissions in 

2010 by 90%, 94%, 91% and 87%, respectively, below 1998 levels. The commenter says that the EPA’s

proposed emissions limits will likely require further optimization and adjustments and be difficult to 

implement despite these recent upgrades.

Response to Comment 67: The agency set emissions standards based on data collected (ICR) from the 

best performing 12% of operating units within the domestic EGU fleet; thereby, demonstrating 

operational, existing control technologies for compliance. Owners have a multitude of options and may

choose to: retrofit, optimize current controls, upgrade existing controls, fuel switch/blend, employ a 

combination of technologies, or retire and replace power. The EPA understands recently retrofitted units 

may require further upgrades for compliance; however, controls for SO2 mitigation typically suffice for 

MATS acid gas capture while economical upgrades of existing controls or optimization may suffice for 

compliance.78

Comment 68: Commenter 17842 believes the implementation of a “total” PM limit in the proposed rule 

contributes largely to the rule’s estimated costs as utilities will need to replace existing PM controls with 

more costly fabric filters.

Response to Comment 68: Although the EPA proposed a total PM standard, the EPA is finalizing 

MATS to include a filterable PM standard instead. See the preamble for the final rule. The EPA does not 

 

77 Steam, 41st Ed. 2005, Babcock & Wilcox Company

78 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” by

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believe that MATS automatically necessitates replacing existing PM controls with fabric filters. Many

older ESPs are oversized and suffer from inadequate maintenance resulting in degraded performance; 

simply restoring performance will improve capture rates. Upgrading with modern components (such as: 

modern power supplies, electrode replacement, additional fields) or enhancing air flow and rapping 

allows improvement beyond original performance metrics. In fact, many older ESPs have sufficient 

room for extension thereby increasing collecting area by 10-20 percent.79 As another option, an EGU 

may consider retaining the old ESP and install a supplemental smaller-sized “polishing” baghouse80 to 

augment particulate collection. In short, the EPA does not foresee ESPs becoming obsolete with 

promulgation of MATS.

Comment 69: Commenter 17885 states that many cooperative EGUs will be forced to retrofit with 

additional emission controls under the proposed rule and others will need to shut down because they will 

be unable to retrofit under the timelines or cost-effectively justify the retrofits. The commenter expresses 

concerns with the practical application of the proposed rule and the procedures used by the EPA in the 

rulemaking process.

Response to comment 69: The EPA believes that the flexibility of the rule permits a multitude of 

options for economical compliance. Flexibility, other regulations, and compliance date attainment are

discussed in the preamble for the final rule, feasibility TSD, and in Response to Comments section 5C01 

“Compliance Dates.”

Comment 70: Commenter 19122 describes the startup and shutdown process for their oil-fired unit, 

which requires bypassing of the fabric filters to prevent damage that would require replacement of bags 

after each startup. Requirements that include startup and shutdown episodes in PM emissions on a 

lb/MMBtu basis would lead to the need to use the fabric filter with temperatures well below the acid 

dew point, leading to bag binding and acid degradation. The commenter explains that this would involve 

using at least one casing out of three in service to handle flow during start up. One casing has 16 

compartments with 396 bags each. The bags in the compartment that would need replacement cost $1.2 

million, leading to an additional cost of $15 million per year.

Response to Comment 70: The EPA acknowledges start-up/shut down issues involving fabric filters 

(acid attack, blinding, etc.) during oil firing. The agency points out that the coal-fired boiler industry 

overcame this issue by installing chemically resistant bags81 and/or pre-coating the bags82 with an 

alkaline powder. Another option employs firing low sulfur fuels. Additionally, the EPA established 

requirements for PM control during start-up, shutdown and malfunction – see the preamble for the final 

rule.

 

79 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” by

Lipinski, Leonard, Richardson; published by URS; April 5, 2011

80 NESCAUM report; “Control Technologies to Reduce Conventional and Hazardous Air Pollutants 

from Coal-Fired Power plants” p. 19, March 31, 2011

81 Neundorfer web site: http://www.neundorfer.com/knowledge_base/baghouse_fabric_filters.aspx ; 

Lesson #4, p.7 Table 4-1 [ref.: 

http://www.neundorfer.com/FileUploads/CMSFiles/Fabric%20Filter%20Material[0].pdf ]

82 CoalPower mag; May 1, 2007; “Coal Plant O&M: River Locks and Barges are an Aging Workforce, 

Too” ref.: web site: http://www.coalpowermag.com/plant_design/Coal-Plant-O-and-M-River-Locksand-Barges-Are-an-Aging-Workforce-Too_36.html
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6G - Impacts/Costs: Testing and Monitoring Cost Assumptions

Commenters: 17197, 17386, 17681, 17696, 17716, 17718, 17730, 17737, 17761, 17772, 17795, 17796, 

17843, 17856, 17881, 17886, 18014, 18444, 18502, 18023

Comment 1: Commenter 17197 believes the 18 months burner inspection interval is unreasonable 

because it introduces substantial costs not reflected in the cost estimates shown in Table 14 of the 

proposed rule. The commenter reports costs for pre-boiler entry slag blasting for personnel safety costs 

approximately $10-12,000, scaffolding the boiler for burner access is about $80,000 and requires at least 

6 weeks of pre-planning and post-outage boiler combustion testing and tuning costs around $50,000.

Response to Comment 1: The EPA generally agrees with the commenter and has altered the burner 

inspection interval to reduce the cost burden of this rule. Under the final rule, the inspection and tune-up 

must be conducted at each planned major outage and in no event less frequently than every 36 months, 

with an exception that if the unit employs a neural-network system for combustion optimization during 

hours of normal unit operation, the required frequency is a minimum of once every 48 months.

Comment 2: Commenter 17386 objects to the requirement to conduct monthly or bimonthly

performance tests, as it is an economic burden, especially for smaller facilities. The commenter also 

states that such testing could result in increased annual HAP emissions exceeding any reduction in 

hourly emission rates achieved by the rule. The commenter points out that oil is a homogenous fuel for 

which metal concentrations are unlikely to fluctuate. The commenter goes on to say that since oil-fired 

EGUs are a minor source of HAP except for nickel, the frequent testing is unwarranted. The commenter

states that the cost of such a testing program involves the ancillary cost of operating the EGU on a mustrun basis for the testing, even on EGUs that operate intermittently. Such testing will interfere with the 

ability to meet regional electricity demands if the EGUs have a monthly circulating water flow limits as 

part of their NPDES permit. The commenter also notes a problem for dual-fired EGUs which often 

operate on natural gas during the ozone season. However, for testing purposes, the commenter will be 

required to fire the fuel with the capacity to generate the most HAP emissions, leading to emissions that 

would not have otherwise been released. The commenter requests that for these reasons, the EPA require 

only one performance test for oil-fired EGUs be conducted every 3 years.

Response to Comment 2: The EPA recognizes the cost burden of testing and we are relaxing the testing 

frequency to require that oil-fired EGU’s be tested at least quarterly rather than monthly or bimonthly. 

The EPA generally agrees with the comment regarding oil-fired testing during the ozone season and is 

changing the rule language accordingly to require that testing be conducted on the fuel type fired during 

the operating quarter that is likely to result in the highest emission rate. In this manner, if there are no 

oil-fired operations during ozone season quarters, there is no requirement to test while firing oil.

Comment 3: Commenters 17386 and 17696 consider monthly or bimonthly stack testing for HCl to be 

wasteful due to high annual costs of around $78,000 for a single stack, $127,000 for two stacks and 

$176,000 for three stacks. The commenters believe that a more reasonable approach would be to 

perform an initial stack test for PM followed by the use of PM CEMS, and annual PM stack tests as long 

as the coal type or mixture of fuels did not change. The commenters state that a stack test vendor 

estimates that annual total PM and non-Hg metals stack testing plus non-Hg metals bimonthly stack 

testing would impose a cost of $67,000 for one stack, $115,000 for two stacks and $162,000 for three 

stacks, which would be unnecessary to assure compliance if the suggested approach were used.
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Response to Comment 3: The EPA disagrees with the commenters’ notion that PM is an appropriate

surrogate for HCl emissions. HCl testing frequency has been reduced to a quarterly requirement and is 

required only if SO2 controls and monitoring, or HCl monitoring (optional) are not employed. PM 

CEMS and PM CPMS options are being added to this rule to optionally reduce the burden of monthly or 

bimonthly stack testing.

Comment 4: Commenters 17716 and 18014 discuss linearity checks required under Appendix B. 

Commenter 17716 states that section 63.10010(e)(6)(iii) should define the term “nominally,” and should 

not require the introduction of a calibration gas. The commenter points out that Part 75 requirements 

already assure an analyzer span that provides accurate data. Coupled with the Part 75 requirements, the 

three linearity gas concentrations are sufficient to determine that the analyzer is linear. Commenter

18014 states that the system will need to be modified to include an additional regulator, the data 

acquisition and handling system (DAHS) will need to be reprogrammed and costs will be incurred for a 

fourth calibration gas and monthly cylinder demurrage. Both commenters state that the section 63 

requirements will increase SO2 CEMS operating costs.

Response to Comment 4: The EPA agrees with the commenter that Part 75 requirements already 

provide for a linear instrument response that should, by definition, include the emissions limit level and 

beyond, and has removed this requirement from the final rule.

Comment 5: Commenter 17718 requests guidance from the EPA on what should be included in a sitespecific test plan mentioned in the proposed rule (40 CFR 63.10007(a)) as the development of quality

assurance programs with testing firms can be burdensome without clear guidance.

Response to Comment 5: Section 63.100007(a) points to section 63.7(c) which contains specific 

information about QA programs including test plans and internal and external QA programs. The EPA is 

a proponent of Data Quality Objectives (DQOs) as these are the pretest expectations of precision, 

accuracy, and completeness of data.

An example of a DQO requirement is:

“The sample volume must be sufficient to provide the required amount of analyte to meet both the MDL

of the analytical method and the allowable stack emissions. It may be calculated using the following 

formula:

Sample Volume = A x 100/B x 100/C x 1/D

Where:

A = The analytical Method Detection Limit in ng

B = % (%) of the sample required per analytical run

C = Sample recovery (%)

D = Allowable stack emissions (ng/dscm)

Test contractors are experienced with developing and working with Test Plans, DQOs, and QA 

programs and the EPA feels this requirement should not present an undue burden to facilities.
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Comment 6: Commenter 17730 and 18023 discuss the Hg compliance options. Commenter 17730 

believes that the proposed Hg emission standards for existing units is not based on representative data 

and the limit will be difficult to achieve routinely and will eliminate new coal-fired units. However the 

commenter appreciates the EPA’s providing of the alternative of conducting fuel analysis for ongoing 

compliance for existing low emitting electric generating units (LEEs), and urges the EPA to make it 

available to new units as well. Commenter 18023 questions the EPA’s assumption that “most, if not all, 

of the units that were subject to CAMR purchased Hg CEMS and/or sorbent trap systems prior to the 

rule vacatur...” The commenter reports that while their facilities did install Hg CEMS, the systems will 

need extensive upgrades as they will require three more CEMS be installed to meet the proposed 

requirements. Also, full quality assurance measures have only been completed on a fraction of the 

previously installed CEMS. The commenter goes on to say that the Hg CEMS have required an 

unexpected degree of maintenance, which will increase with lowered emission limits and some Hg 

CEMS have been inexplicably unreliable. The commenter believes others in the industry are in a similar 

situation, which means that the EPA cost estimates underestimate the cost of new installations, 

expensive upgrades and additional maintenance required by the proposed rule. In addition to the 

equipment-related expenses, the commenter lists costs associated with modifying the data acquisition 

and reporting systems associated with the Hg CEMS to meet the new procedures and requirements. The 

commenter estimates that these changes will cost approximately $20 million upfront and another $2.5 

million annually.

Response to Comment 6: The EPA generally agrees with the commenter that many Hg CEMS

installations were not undertaken or fully implemented as a result of the CAMR vacatur, and we are 

increasing our estimated cost impacts accordingly. The EPA does not agree that existing mercury CEMS

installations would need upgrades to comply with this rule.

Comment 7: Several commenters (17737, 17761, 17886, 18023) comment on the burden of outage 

intervals required to meet the proposed rule requirements. Commenter 17737 reports that in addition to 

the cost of the inspection and repair work, the facility may be required to purchase power during outages 

at higher prices that the electricity normally produced. This cost could exceed $1 million for a 3-week 

outage during peak season. By requiring a major outage every 18 months, the rule makes it difficult to 

schedule outages for off-peak seasons when demand for power drops and replacement power is less 

expensive. Commenter 17761 states that major maintenance outages are generally scheduled only every 

4 or 5 years. The requirement to do burner inspections every 12 to 18 months is excessive because large 

companies multiply these outages across a fleet of 20-30 units, making the annual costs large, increasing 

electricity rates and interfering with system reliability. Commenter 17886 considers the requirement of 

an outage for burner inspection and repair more often than every 36 months to be excessive because of 

increased costs without actual benefit. Commenter 18023 estimates that the impact of shortening its 

outage interval by only 6 months would amount to approximately $140 million for 5 years across their 

system, taking into account the cost of replacement generation.

Response to Comment 7: The EPA acknowledges the concerns raised by the commenters and has 

altered the requirement for burner inspections to a schedule more likely to coincide with planned major 

outage schedules.

Comment 8: Commenter 17772 requests clarification on the proposed rule language that verifies no 

requirement to retrofit boilers with viewing ports where none previously existed. The commenter quotes 

section 63.100021(a)(16)(iii) and asks that the “as applicable” provision be clarified to show if it is 

intended to exclude observation of flame pattern in boilers that do not have viewing ports. The 
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commenter considers the addition of view ports to units without them costly and of little benefit as flame 

pattern viewing can be subjective when trying to assess CO levels and tells little about NOX levels.

Response to Comment 8: The EPA generally agrees with the commenter and has revised the rule 

language as suggested.

Comment 9: Commenter 17772 discusses the option of calibrating oxygen monitors instead of 

calibrating all other equipment to optimize total CO and NOX emissions. The commenter recommends 

that oxygen monitors be calibrated annually instead of the air flow or fuel measurement devices, as 

proposed in section 63.100021(a)(16)(iii). The commenter reports that air-to-fuel ratios are usually fixed 

by the manufacturer at the time of installation and calibration is done as needed or during a planned 

outage. Some systems are difficult to adjust or unable to be adjusted. Therefore, the commenter

considers CO and NOX emissions to be dependent on oxygen, so monitoring oxygen levels is a better 

indication of optimal emissions. In addition, oxygen sensors are more easily monitored and calibrated, 

and their calibration would be a better requirement. The commenter also requests that the proposed 

language in section 63.100021(a)(16)(iv) be altered from “...optimization should be consistent with the 

manufacturer’s specification.” to “...optimization should be consistent with burner industry operating 

procedures.” This wording change is important because the burners are set by the manufacturer at the 

time of installation, but the operator is responsible for adjustments based on future operational changes 

such as coal quality.

Response to Comment 9: The EPA generally agrees with the commenter in that not all parameter 

changes are applicable at all facilities and for all burner installations. We are modifying the rule 

language to clarify this requirement and allow for adjustment of burners that have had post-manufacturer 

modifications or adjustments for fuel quality or type.

Comment 10: Commenter 17795 requests that the facility averaging requirement to not exceed current 

emission levels be removed on the grounds that the current language penalizes units that have controls in 

place and are currently meeting the EPA’s HAP standards, which is counterintuitive to how these units 

should be viewed. The commenter lists the following reasons for the requested change in the provision:

1. Facilities in many cases do not have CEMS installed (e.g., Hg and PM CEMS) and do not know the 

current rate being achieved at given unit.

2. There is too much variability in emissions data to set an arbitrary emissions ceiling that may not be 

reflective of the upper end of the normal range of emissions at a given facility.

3. To demonstrate that the control technology is no less effective is in essence requiring an initial 

compliance test shortly after the rule is finalized and again 3 years later when the compliance is 

required. Again this scenario places too much emphasis on emissions testing and fails to recognize the 

variability of those tests. The commenter includes a table which shows this potential variability and the 

wide spread of Hg emissions (all within EPA’s proposed Hg standard) at one of GenOn’s facilities in the 

first seven months of 2011. [EPA-HQ-OAR-2009-0234-17795-A1, 

17795_2011_Hg_Emission_Data.doc]

Response to Comment 10: The EPA disagrees with the comments provided. The ICR testing 

requirements were designed with the goal of collecting data representative of the cross section of units. 

The UPL calculation performed on emissions test data takes variability into account in the effort to find 
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levels where 99% of emissions test results will fall below the set limit. Performance testing conducted to 

assess control technology effectiveness are standard compliance procedure.

Comment 11: Commenter 17796 considers the option of stack testing with Method 5 or 201/202 

monthly or bimonthly depending on PM control equipment to be burdensome for the source and the 

state agencies required to witness the tests and review the reports. The commenter also points out that 

the proposed testing does not assure additional public health benefits.

Response to Comment 11: The EPA has modified the requirement for monthly and bimonthly testing 

to a quarterly testing requirement. This requirement is an option and as such is not a necessary burden 

for the facility to bear. The proposed testing is in lieu of continuous monitoring and as such is meant to 

assure that public health benefits are akin to what would be shown by continuous monitoring of 

emissions.

Comment 12: Commenter 18023 reports that the cost to install and operate PM CEMS for compliance 

with the proposed rule will exceed $30 million initially and at least $0.6 million annually.

Response to Comment 12: The EPA recognizes the costs associated with PM CEMS compliance 

requirements and is modifying the rule language to reduce the cost burden while maintaining continuous 

monitoring using the technology as a continuous parameter monitor (PM CPMS).

Comment 13: Several commenters (17796, 17761, 17843, 17856, 18444) comment on the costs for state 

agencies required to observe or review emissions tests, read reports and protocols related to the proposed 

rule, and send the EPA summaries of the data. Commenter 17843 suggests that once the initial test is 

conducted for PM and non-Hg metals, and fuel sampling or operating parameters are established, fuel 

sampling would be a simpler and less costly approach than stack testing. The commenter mentions that 

having the EPA revise the monthly and bimonthly testing requirement to quarterly or biannual testing 

would be more reasonable. Commenter 17856 also discusses the need to modify each unit’s Title V

permit and the time required for state agencies to complete the extensive modifications to each unit’s 

unique operational characteristics. The commenter sees these requirements as especially burdensome 

because they would be required to repeat the process every two months, indefinitely, and for every unit 

subject to the bimonthly performance tests. The commenter states that budgetary constraints mean the 

states simply do not have the resources to carry out these responsibilities, so the EPA should revise the 

rule to alleviate this burden. Commenter 1844 mentions that minimum sample volume of 4 dry standard 

cubic meters (dscm) means approximately 4-hour sample runs, which will increase workload. Also, the 

commenter points out that some rule sections with operating limits in need of establishment will require 

multiple load testing, which is another resource drain for state agencies.

Response to Comment 13: The EPA generally agrees with the comments and has dropped fuel 

sampling requirements for non-Hg metals since the detection levels are not low enough to show 

compliance with the limits. This removes the requirement to update Title V permits as the rule will also 

drop the control device operational limits. Now, source owners/operators would establish the milliamp 

value during successful Method 29 testing, and use just that value as an operating limit. The EPA has 

also modified the rule requirement to require testing on a quarterly basis rather than monthly or 

bimonthly. The EPA has undertaken an effort to better assess detection limits of test methods which may

serve to reduce the 4 dscm requirement in the future.
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Comment 14: Commenter 17881 requests a change to report a total for all metals, rather than reporting 

filterable and condensable values because the separate analysis will add costs without providing 

necessary information.

Response to Comment 14: The EPA disagrees with the comment and is not modifying the requirement.

EPA Method 29 has always included the analysis of the impinger contents for all of the metals. For 

several of the metals such as selenium and arsenic there are specific reagents in the impingers which are 

designed to collect the metals that pass through the filter. Since digestion and analyses would be 

required for the filterable component and digestion of the impinger contents is required for those metals 

with special reagents, the additional cost is due to the analysis by the ICP instrument. Since this 

instrument analyzes all metals concurrently, there would be no or little reduction in the analysis cost for 

the impinger contents. In addition, for a few of the Method 29 tests conducted for the Phase III portion 

of the ICR, substantial percentages of the metals were in the impinger analysis. Eliminating the results 

of the impinger contents would introduce a significant negative bias into the results.

Commenter 15: Commenter 18502 discusses the increased cost for non-continental EGUs of emissions 

testing to document compliance with the proposed limits. The commenter explains that as a noncontinental unit, they contract with emissions testing firms located in the continental U.S. and have 

higher costs per test despite having smaller units than is common in the continental U.S. The commenter

also cites the requirement to test for individual metals rather than filterable PM as a cause of increased 

cost of compliance testing per megawatt of capacity to be significantly higher than for continental EGUs

with little environmental benefit associated with frequent emissions testing.

Response to Comment 15: The EPA generally agrees with the commenter and has modified the testing 

requirements and monitoring options of this rule in an effort to decrease costs to affected units.

Comment 16: Commenter 17758 states that DSI will be a useful and cost-effective control tool for 

many units, but it is not a viable option for all coal-based units for compliance with the acid gas 

standard. In many circumstances, the EPA’s analysis of DSI significantly underestimates the time 

needed for, as well as the cost of, compliance in many circumstances. First, DSI could have limited 

application as a compliance option due to operational impacts and cost considerations that the EPA has 

not taken into consideration. Second, the use of DSI could impact beneficial use of fly ash, resulting in 

increased disposal volumes, costs and loss of revenue. Third, DSI is not a viable option for eastern 

bituminous coals, which require the use of wet FGD; compared to DSI, wet FGD is more costly and 

takes more time to implement, leading to timing concerns for compliance. Many companies will need 

more than the 3 years and will spend more than the EPA estimates to achieve compliance.

Response to Comment 16: The EPA also believes that DSI has the potential to be a useful and costeffective control technology option for many units. We also agree that it is not an appropriate option for 

many facilities. Overall the EPA believes that the technology is most applicable for units burning lowersulfur content coal (including, potentially, low-sulfur bituminous coal). The EPA has considered 

operational impacts and cost considerations. In some cases the EPA has assumed that a “polishing”

fabric filter will be installed downstream of the primary control device. This configuration (similar to the 

TOXECON(tm) configuration for Hg control) allows dry sorbent to be injected after the primary PM 

control device, thus keeping the ash and dry sorbent (both alkaline sorbent for acid gas control and 

activated carbon sorbent for Hg control) separate. This will help to preserve the salability of the fly ash 

and may reduce the costs of disposal if the ash and spent sorbents can be disposed of separately. 

However, the EPA did include an analysis evaluating the impact of increased disposal costs for ash 

residuals that contain sodium containing sorbents (such as Trona or sodium carbonate). The EPA’s 
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analysis of the final rule includes an IPM sensitivity case using a DSI waste disposal cost of $100/ton.

The sensitivity case indicates that a 100% increase in assumed DSI waste disposal cost produces slightly

less than a 1% increase in the projected cost of the rule. Regarding the compliance time - this is 

addressed elsewhere in response to comments.

Comment 17: Commenter 17681 questions whether the EPA factored in the cost of additional catwalks 

required due to the additional CMS and/or sorbent trap system equipment. According to the commenter

some facilities cannot place additional CMS ports where the current catwalk is located due to a lack of 

physical space on the stack surface area at the elevation and such additional equipment may require 

additional catwalk levels. Commenter notes that the Lakeland coal unit does not appear to have 

sufficient room on its current elevation where the monitors are located at this time for an additional 

monitor without bringing the integrity of the stack into question (if additional stack ports must to be 

carved out). Lakeland’s Unit 3 coal unit already has existing monitor equipment and the addition of a 

PM CEMS and/or Hg monitor/sorbent may require the installation of an additional catwalk.

Response to Comment 17: The Agency’s analysis represents the average cost of purchasing, installing, 

operating, and maintaining emissions control equipment. Application of emissions control equipment at 

an individual site with unique circumstances may cost more or less than the average, depending on 

factors such as the owner or operator’s ability to engineer effective approaches that ensure compliance 

with the rule’s emissions limits.

Commenter 18: Commenter 16849 states that the EPA makes the assumption most units currently

monitor moisture content. The commenter does not measure moisture content continuously and it is their 

understanding that the majority of units do not monitor moisture content. The commenter asserts that the 

EPA needs to remove this assumption from floor and cost calculations.

Response to Comment 18: The Agency finds the commenter’s concern unfounded. No assumption 

regarding continuous moisture content monitoring has been made for this rule, even though the Agency

is aware that owners or operators of many EGUs subject to the acid rain program choose to monitor 

stack moisture on a continuous basis.
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6H - Impacts/Costs: Projection of New Units

Comments are addressed in Section 4 of this document.
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6I - Impacts/Costs: Economic Impacts/Employment Impacts

Commenters: 12050, 15002, 16469, 16549, 16705, 16849, 16856, 16858, 16859, 17004, 17022, 17026, 

17028, 17123, 17137, 17254, 17265, 17386, 17400, 17403, 17409, 17620, 17623, 17627, 17629, 17638, 

17639, 17640, 17648, 17654, 17656, 17676, 17681, 17682, 17689, 17690, 17692, 17697, 17698, 17701, 

17702, 17705, 17707, 17710, 17711, 17712, 17716, 17718, 17725, 17730, 17731, 17732, 17736, 17743, 

17745, 17751, 17756, 17761, 17765, 17767, 17771, 17772, 17774, 17775, 17791, 17797, 17799, 17800, 

17805, 17806, 17807, 17808, 17811, 17812, 17813, 17815, 17817, 17821, 17824, 17829, 17834, 17839, 

17840, 17842, 17844, 17853, 17854, 17855, 17867, 17868, 17875, 17877, 17879, 17880, 17881, 17884, 

17886, 17887, 17901, 17903, 17904, 17909, 17911, 17917, 17919, 17921, 17930, 17931, 18014, 18016, 

18017, 18018, 18021, 18025, 18026, 18030, 18033, 18038, 18039, 18419, 18421, 18422, 18422, 18424, 

18425, 18428, 18430, 18432, 18433, 18433, 18433, 18435, 18436, 18437, 18441, 18447, 18477, 18478, 

18480, 18481, 18484, 18486, 18488, 18489, 18497, 18498, 18500, 18502, 18538, 18540, 18575, 18907, 

18933, 18961, 19041, 19042, 19114, 19121, 19199, 19211, 19212, 19213, 19214, 19580, 19653, 19536, 

19537, 19538, 19742, 18023 

1. Job losses and economic impact/cost.

Comment 1: Multiple commenters (16549, 17137, 17656, 17736, 17840, 17887, 17901, 17931, 18488, 

18023, 19742) believe the proposed rule will weaken industry, cause job losses and hurt power 

consumers. Commenter 16549 reports that the proposed rule will affect 1,350 coal- and oil-fired units at 

525 power plants and that NERC reports that by 2018 nearly 50,000 MW of capacity will be retired by 

the proposed rule. This commenters compare the various cost estimates released in addition to the $10.9 

billion cost estimated by the EPA. The EIA report of $358 billion and a Representative Upton and 

Senator Inholfe estimate of $300 billion by 2015 show that some believe the EPA’s cost estimates to be 

very low. The commenters express concern for the electricity price increases that are likely to be up to 

24% in some regions as a result of the proposed rule. In addition to the economic difficulty the proposed 

rule could place on consumers, the commenters believe that many in the energy sector will lose their 

jobs due to coal-fired capacity losses. The commenters believe coal-fired plants in the southeast 

especially will mean the loss of high-paying, high-skilled jobs and drastic price increases in energy

costs.

Response to Comment 1: The agency has estimated the annual costs of the rule in 2015 to be $9.6

billion in 2007 dollars. The estimate of early retirements of coal-fired units is 4.7 Gigawatts. Both of 

these estimates were prepared using the IPM, a model that has been extensively reviewed and has been 

utilized in several rulemakings affecting the power generation sector over the last 15 years. The 

agency’s analyses are credible and accurate to the extent possible. Limitations and caveats to these 

analyses can be found in the RIA for the rule. Retail electricity price impacts are estimated to increase 

by 3.1% in 2015.. The agency also found that the impact on employment nationally should be small on 

net, with about 46,000 job-years of one-time construction labor supported or created by this rule, and a 

loss of 15,000 to an increase of 30,000 jobs expected on an annual basis. The agency has used peerreviewed studies in the preparation of the employment impact analyses. In addition, commenters are not 

comparing apples to apples. EIA has at no time provided an analysis of the costs of MATS as proposed 

or finalized, and other studies showing large negative impacts have many flaws. The primary

weaknesses with these studies are the poor reflection of the actual rule requirements, inadequate 

inclusion of proven technologies, and speculation with regards to other policy, like climate policy.

Comment 2: Several commenters (16705, 17403, 17123, 17400, 17771, 17817, 17829, 17909, 18437, 

18575) express concern that the proposed rule, if finalized in its current form, will significantly impact 
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jobs and electricity rates, leading to closed businesses. Commenter 17123 also calls for a practical, 

affordable, achievable energy solution. Commenter 17771 expresses concern specifically about the 

burden of the proposed rule on New Mexico. Commenter 17909 believes the leveling of the national 

electricity price and modernization of the fleet is outside the scope of the EPA’s regulatory authority. 

Commenter 18575 expresses concern for the impacts likely in South Dakota, Minnesota and Iowa.

Response to Comment 2: The agency has estimated that there could be employment impacts on the 

power sector of up to 46,000 job-years of construction labor supported or created from new pollution 

control equipment installed, and a range of annual employment impacts of a loss of 15,000 jobs to a gain 

of 30,000 jobs. Although the agency does not claim what the total employment impact will be of this 

rule, it is important to note that there will be some positive gains in certain sectors, and overall the 

impact is likely to be small. The EPA estimates that there will be an increase of 3.1% in retail electricity

price on average nationwide in 2015 as an outcome of this rule, with the range of increases from 1.3 to 

6.3% in regions throughout the U.S. These results are found in the RIA for the rule. The agency also 

examined the impact of the increases in electricity prices to industries outside of the electric power 

sector and found that changes in product price and output should be less than 1 % in 2015 for the many

industries (100) included in the analysis. There may be impacts on a firm-level that could be higher than 

this, but these analysis results suggest that the economic impacts on average nationally should be 

modest.

Comment 3: Commenter 19212 urges the EPA to give state regulators the flexibility in implementation 

to allow consumer protection against massive utility rate increases.

Response to Comment 3: Utilities have discretion in how to meet the requirements of this rule, and 

EPA analysis indicates that the impact to electricity consumers will be reasonable given the large 

benefits,

Comment 4: Several commenters (16858, 17022, 17028) express concern that a 10 to 20% increase in 

electricity costs can lead to profit loss and job loss. The commenters believe that the most effective way

to protect the environment is to ensure economic prosperity so that resources are available for 

improvements.

Comment 5: Several commenter (17004, 17022, 17026, 17028) report being advised by their utility

provider that the proposed regulation could result in double-digit price increases for power.

Response to Comments 4 - 5: The agency’s analysis in the RIA for the rule finds that retail electricity

prices will increase by 1.3 to 6.3% in 2015. No region of the U.S. is expected to experience a doubledigit increase in retail electricity prices in 2015 or in any year later than that, according to the agency’s 

analysis. In addition, the agency finds that sectors experiencing these electricity price increases will not 

experience increases in prices or decreases in output of more than 1 %. The agency believes the 

economic impact of this rule is modest in light of the benefits that will accrue to those who will now 

experience less pollution of HAP and other pollutants than previously.

Comment 6: Commenter 17842 questions the lack of consideration of the cumulative effects of 

interrelated rules, which may collectively lead to more retirements. The commenter states that local 

utilities have reported temporary job gains due to the replacement of retired generation, but a net 

decrease in full-time work. The commenter asks the EPA to reassess the costs and impacts of the 

proposed rule.
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Commenter 18424 states that the EPA’s conclusion that bituminous coal production will increase as a 

result of Utility MACT is based on two flawed assumptions. First, as discussed above, the EPA assesses 

the impacts of the Utility MACT as if it were the only regulatory driver affecting a company’s 

compliance and economic decisions. The EPA analysis ignores the cumulative impact of all the new 

CAA regulatory requirements a utility will have to consider when it determines its compliance strategy. 

As a result of ignoring the cumulative impacts on decision making by utilities, the EPA projects 

approximately 10 GW of coal units will be retired because of Utility MACT. In contrast, the NERA 

analysis, which considers the impacts of both Utility MACT and CSAPR together, projects nearly 48 

GW of coal unit retirements - most of which are smaller and older units burning bituminous coal. Other 

studies predict similar levels of coal unit retirements. This degree of retirements would have a 

devastating impact on Indiana’s coal industry and consumers of electricity.

Response to Comment 6: The final CSAPR was included in the baseline analysis for MATS. The 

agency did not prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) 

the various EO requirements that the agency must comply with require us to estimate impacts specific to 

this rule; 2) decision makers and the public need to know the impacts specific to a particular rule in 

order to judge the merits of the regulation; 3) estimates specific to a particular rule are more transparent 

than those from a cumulative impact analysis. A cumulative impact analysis lumps several regulations 

together and can potentially mask a high-cost/low-benefit regulation among other rules that may have 

large net benefits. By analyzing each regulation separately, the EPA makes clear statements about what 

impacts, costs, and benefits will be generated as a result of this particular regulation. The EPA analysis 

also indicates that there will be relatively modest amounts of retirements and installation of pollution 

controls will be a cost-effective compliance measure. In addition, many coal facilities have already

invested in pollution controls, and they are well positioned to comply with this rule with modest changes 

to operations. In addition, the EPA has conducted an updated employment analysis which shows some 

potential positive and negative employment changes from the rule, but overall expects the employment 

impact to be relatively small in comparison to the affected sector and the overall economy. 

Comment 7: Commenter 17824 reports that the majority of coal-fired units that do not have scrubbers 

are small units that may find the cost of upgrades too expensive and will shut down instead, leading to 

job loss and decreased local revenue.

Response to Comment 7: The requirements of the rule do not mandate a particular technology, and 

there are other options available to utilities that will assist with compliance. In addition, the EPA has 

included in its analyses various cost functions for pollution controls that reflect differences in cost across 

unit sizes, and the projected impacts reflect these effects.

Comment 8: Commenter 17639 encourages the Federal Government to implement cost benefit and job 

impact analyses before enactment of all rules and regulations. This commenter also states that the 

proposed rule compliance costs would make it challenging for older coal-fired units to comply and lead 

to retirement and energy cost increases of 17.6% in 2016. These increases would disproportionately 

affect economically vulnerable families.

Comment 9: Commenter 18502 believes there is a disjunction between the President’s public policies 

and the proposed rules as they relate to job creation, public burden, and economic development. The 

commenter cites EO 13563, EO 13132, EO 12866, and EO 13211 as the Executive Orders of concern.

Response to Comments 8 - 9: The agency followed all requirements under Executive Orders 12866, 

13563, 13132, 13175, 13045, 13211, 12898, and the Unfunded Mandates Reform Act in preparing this 
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proposed rule. The analyses completed in adherence to these requirements can be found in the RIA and 

in various TSDs in the public docket for this rulemaking. The agency estimates a nationwide retail 

electricity price increase of 3.1% in 2015 in response to this rule. The agency is mindful of the potential 

impacts of retail electricity price increase in response to the rule, but state and local agencies are best 

equipped to develop rate structures that may mitigate these price increases. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy. This is also consistent with the economic 

literature on this subject.

Comment 10: Commenters 17656 and 18023 quote an IHS/Global Insight estimate that every $1 billion 

spent on upgrades to comply with the proposed rule will put 16,000 jobs at risk and reduce gross 

domestic product (GDP) by as much as $1.2 billion.

Response to Comment 10: The agency’s modeling of impacts for this rule is concentrated on effects to 

the electric power sector. Our analysis of employment impacts finds a short-term impact of 46,000 jobyears supported or created, with a longer-term impact of between a loss of 15,000 jobs and a gain of 

30,000 jobs annually. We do not include impacts of employment beyond the regulated sector. We do not 

provide an estimate of a change in GDP. The EPA has conducted an updated employment analysis 

which shows some potential positive and negative employment changes from the rule, but overall 

expects the employment impact to be relatively small in comparison to the affected sector and the 

overall economy. This is also consistent with the economic literature.

Comment 11: Commenter 17840 considers the proposed rule to discourage technology improvements, 

raise electricity costs and harm the economic well-being of the country, so the EPA needs to rescind the 

proposed rule.

Response to Comment 11: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices.

Comment 12: Commenter 17839 questions the concerns expressed about increased costs for electricity

consumers. The commenter states that public utility commissions in each state will determine a fair and 

reasonable rate structure. The commenter states that any increased cost to the utility caused by the 

proposed rule will be amortized as a capital expenditure over a number of years, reducing the rate 

impact. The commenter calls on utilities to substantiate their claims of increased costs and points out 

that it is not the EPA’s responsibility to factor rate increases into the adoption of the proposed rule.

Response to Comment 12: The EPA will work with relevant authorities to ensure a smooth transition 

with this rule. Public utility commissions and other regulatory authorities have extensive experience 

with regulatory requirements and treatment of costs to consumers, and are prepared for responding to the 

cost of future pollution control equipment or other response measures. In addition, there are certain 

provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).
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Comment 13: Commenter 17716 rejects the EPA’s view that the proposed rule will encourage energy

efficiency savings to offset higher electricity costs. The commenter points out that table 23 of 76 FR 

25074 does not support this claim and shows only a slight reduction in compliance costs from 2015 to 

2030.

Response to Comment 13: The EPA believes energy efficiency measures can be a complement to this 

rule, and can be an important tool in helping address emissions. The EPA has not included all the likely 

additional energy efficiency measures that are likely to occur by 2015, but will continue to pursue 

energy efficiency improvements throughout the economy, along with other federal agencies, states and 

other groups. This will contribute to additional environmental and public health improvements while 

lowering the costs of realizing those improvements. A reduction in compliance costs with the rule does 

take place over time, and so does a reduction in retail electricity price increases across the U.S. as seen 

in the RIA for the rule. Thus, while this reduction in impacts is modest, it does suggest that energy

efficiency increases may somewhat mitigate the impacts of the rule.

Comment 14: Commenter 17868 refers to the American Coalition for Clean Coal Electricity

(www.cleancoalusa.org) projecting net nationwide employment losses totaling 1.44 million job years by

2020 as a result of the proposed rule.

Response to Comment 14: The estimate of employment losses supplied by the commenter reflects a 

cumulative estimate of employment losses over the time period of 2012 to 2020 related to 

implementation of both the CSAPR and the MATS proposal, and has many weaknesses. Thus, this 

estimate is not for the proposed rule alone, and is not a transparent analysis whose assumptions and 

inputs can be verified. In addition, the report upon which this estimate is based (NERA report, 

September 2011) does not show what type of employment impacts are assessed (construction, operation, 

etc.). The Agency’s estimates both short-term and long-term employment impacts specific to this rule, 

which can be found in the RIA for the rule. The updated employment analysis for the final rule shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

This is also consistent with the economic literature.

Comment 15: Commenter 19042 presents the results of an analysis by the EOP Foundation on the 

proposed rule. The commenter estimates that the proposed rule will increase federal outlays by $286 

million annually due to electricity purchases and costs absorbed by federal agencies for boiler 

modifications. The analysis shows increased annual federal agency costs from $1 million to $17 million 

annually per region, or an increase of 1 to 5%.

Response to Comment 15: The agency has considered this data as part of its UMRA analysis for the 

final rule.

Comment 16: Commenter 18023 estimates that capital spending and fuel switching required for 

compliance with the proposed rule could increase electricity prices by 10 to 20% over the next 10 years 

in the south. The commenter also cites a NERA analysis showing a 10 to 25% increase in the same 

timeframe, with job losses of 250,000-500,000. These losses could result in financial difficulty for local 

governments dependent on tax revenues that have a short time period in which to implement budget 

cuts. The commenter estimates that there are 6 to 10 jobs at a coal-fired EGU for every job at a 

comparably sized NGCC EGU, and the jobs lost to coal-fired EGU closures are among the higher 

quality jobs. Also, jobs associated with mining and transportation of coal will be lost, creating a net loss 

of jobs for decades.
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Response to Comment 16: The agency’s analysis of impacts on retail electricity prices resulting from 

this rule shows that there is an average increase nationwide of 3.1% in 2015, with a range of increases 

from 1.3 to 6.3% in that same year. The employment impacts estimated by the agency include a shortterm increase of 46,000 job-years of construction labor, and a range of impacts on long-term labor from 

a loss of 15,000 to an increase of 30,000 jobs annually nationwide. We disagree that the rule will cause 

the size of impacts that are presented in the NERA analysis, which actually estimates the impacts from 

four EPA power plant rules - not just from MATS, and has many flaws. The EPA has conducted detailed 

economic impacts analysis on the regulated sector, and finds the impact of the rule on the regulated 

sector is small compared to the overall benefits, and the industry has an excellent track record of 

installing pollution controls without greatly impacting electricity prices. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy. This is also consistent with the economic 

literature.

Comment 17: Commenter 17761 expresses concern about the potential impacts on electricity rates and 

grid reliability problems created by the proposed rule and the cost of replacement generation 

alternatives. (The commenter shares the following link to the organizations resolutions concerning the 

proposed rule: See Resolutions ERE-5 and EL-3 at: 

http://summer.narucmeetings.org/2011SummerFinalResolutions.pdf and 

http://www.naruc.org/Resolutions/Resolution%20on%20the%20Role%20of%20State%20Regulatory%2

0Policies%20in%20Development%20of%20Fed%20Enviro%20Regs.pdf.)

Comment 18: Commenter 17877 urges the agency to include in its consideration the negative impacts 

of increased electric power costs as it finalizes the rule and believes that significant changes should be 

made to the proposed standards.

Comment 19: Many commenters (17829, 17830, 17831, 17889, 17892, 18480, 18481, 18924, 19564, 

19565, 19574, 19581, 19601) express concerns about the negative impacts that the proposed rule could 

have on the economy and ask that the EPA reconsider the rule. 

Response to Comments 17 - 19: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the 

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices.

Comment 20: Commenter 17919 discusses the impact on the Federal Budget Deficit. The commenter

explains that the federal government is a major consumer of electricity, and the proposed rule is 

estimated to increase the federal outlays for electricity by a minimum of $286 million annually, plus 

embedded energy costs associated with good and services. States and municipalities will be likewise 

impacted.

Response to Comment 20: The UMRA analysis done by the agency covers impacts to states and 

municipalities and shows the results in aggregate in the RIA for the rule. We have considered the federal 
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impacts presented by the commenter in the analyses for the final rule as well and found them to be 

reasonable in light of the expected benefits of the rule.

Comment 21: Multiple commenters (12050, 17844, 17854, 17875, 17880, 18025, 18421) support the 

EPA’s impact analysis and dispute claims by other commenters that the projected rule will harm 

economic growth. Several commenters (12050, 17875, 18421) mention testimonials by power company

CEOs stating that the proposed rule will not affect the economic health of the industry and a survey

showing nearly 60% of the coal-fired units already comply with the EPA’s proposed Hg standard, as 

well as several other meaningful quotes from utility executives. Commenters also point out that 17 states 

already require plants to address Hg pollution, with some imposing more stringent emission limits than 

the EPA proposes. Commenters believe that utilities use the threat of power plant closures and lost jobs 

to delay Hg reductions from coal-fired plants. Commenters 17875 and 18421 also believe that the rules 

will drive innovation and job creation as new technologies to reduce pollution are created. These 

commenters, along with commenter 18478, quote the Economic Policy Institute finding that the 

proposed rule will increase job growth by 28,000 to 158,000 jobs by 2015 (including approximately

56,000 direct jobs and 35,000 indirect jobs), the University of Massachusetts study that showed an 

increase in 1.4 million jobs in 5 years, and the Constellation Energy Group installation project that 

employed nearly 1,400 skilled workers. Commenters 17844 and 17854 also cite the University of 

Massachusetts study statement that a net gain of over 4200 long-term operation and maintenance jobs 

will result.

Response to Comment 21: The agency thanks the commenters for their comments. The agency’s 

estimates of employment impacts, which are found in the RIA for the rule, are smaller than the 

commenters’ though we use a different methodology that focuses on impacts to the electric power 

sector. The EPA has conducted an updated employment analysis which shows some potential positive 

and negative employment changes from the rule, but overall expects the employment impact to be 

relatively small in comparison to the affected sector and the overall economy.

Comment 22: Several commenters (17265, 17638, 17681, 18023) express concern about the impact of 

the proposed rule on electricity rates and Florida’s economy and job loss. Commenters believe the EPA 

has underestimated the impact. Commenter 17265 reminds the EPA of the Presidential Order 13563 

which calls for the EPA to exercise its authority to minimize burden, explore all other options and 

include discussion in the preamble of measures evaluated. Commenters 17681 and 18023 point out that 

by 2015 these impacts will disproportionately affect the elderly, minorities, and low income populations, 

resulting in:

1. Average electricity rate increase of nearly 25%

2. Gross State Product loss of nearly $18 billion (nearly 2.5%)

3. Annual job losses of 157,000

4. Unemployment rate of nearly 13%

5. Lost annual manufacturing output of $1.3 billion

6. Lost annual state and local government tax revenues of $2.1 billion

7. Additional costs for control and monitoring equipment, upgrading transmission capabilities and 

impacts to municipal generating utilities.

Response to Comment 22: The agency has estimated economic impacts to the extent possible and as 

accurately as possible. The agency is also mindful of EO 13563, and has included an extensive 

discussion in the preamble of measures and options evaluated in the course of designing this rule. The 

agency estimates an increase in average retail electricity price nationwide of 3.1% in 2015. The agency
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also estimates employment impacts of an increase nationally of 46,000 job-years due to construction of 

new pollution control equipment, and a range of a loss of 15,000 jobs to a gain of 30,000 jobs nationally

for operating this equipment. We do not include employment estimates specific to individual states due 

to a lack of specific information to provide credible estimates. The EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy.

Comment 23: Commenter 19580 believes that if the EPA finalizes this rule it is only a matter of time 

before our strong manufacturing base moves overseas, taking high wage jobs. The commenter sees the 

proposed rule as an excessive regulation that will cost billions of dollars, lead to higher electricity prices 

and job losses as well as compromising reliability.

Response to Comment 23: The EPA has designed a rule that is intended to offer flexibility, to the extent 

possible, while ensuring public health is protected in accordance with requirements outlined in the CAA. 

History has shown that industry adapts to regulations and finds more cost-effective compliance 

approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule relative to what 

the EPA initially projected. The EPA has conducted detailed economic impacts analysis on the regulated 

sector, and finds the impact of the rule on the regulated sector is small compared to the overall benefits, 

and the industry has an excellent track record of installing pollution controls without greatly impacting 

electricity prices. Based on the information provided in the RIA and supporting materials, the EPA does 

not agree that the impacts of this rule will transfer significant industrial production overseas. 

Comment 24: Several commenters (19536, 19537, 19538) state that the EPA is obligated to impose 

lower HCl emission limits because the cost-benefit analysis did not quantify the improved reductions of 

other acid gases such as HF that should be achieved with HCl controls, and the EPA’s cost-benefit 

analysis likely underestimates true benefits of a 0.0001 lb/MMBtu HCl limit. Also, commenters point out 

that the EPA analysis does not take into account the SO2 controls required to meet other rules, so the 

costs are likely to be overstated.

Response to Comment 24: The agency has quantified the reductions in HF emissions as part of its 

analysis of the impacts of setting HAP emissions limits as part of the rule. We are unable to monetize the 

benefits of such emissions; this is also true of other acid gas HAP reductions that could occur as a result 

of this rule. Finally, the agency has included SO2 controls in existence or planned that it is aware of for 

sources to be subject to this rule in the baseline for the analysis presented in the RIA.

Comment 25: Commenter 17648 believes the proposed rule will promote long-term economic health by

encouraging investment in modern, efficient EGUs. The commenter cites upgrades to existing nuclear 

plants to improve zero-pollution nuclear generation by several gigawatts, investments in alternative, 

renewable technologies, co-generation, improved energy-efficient combined cycle gas-fired plants, 

modern coal-fired plants, coal gasification combined cycle plants and technology to recover domestic 

shale gas resources as potential opportunities.

Response to Comment 25: We thank the commenter for their comments and the data they have 

provided. The agency’s employment impact analysis does not include estimation of impacts using this 

BLS data, but we think our analysis of employment was appropriate given our approach and the data 

available to the agency for the proposal. Investment in more modern power generation capacity and 

pollution control technology is a likely outcome of this rule. The agency does believe that retail 
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electricity prices nationwide will be higher in 2015 as a result of the rule, though that increase is modest 

(3.1% on average in 2015, with a range of regional impacts from 1.3 to 6.3%).

Comment 26: Commenter 18419 cites the Edison Electric Institute study of impacts from the proposed 

rule and found that 50% of the U.S. coal fleet may be unavailable by 2015 due to insufficient time to 

acquire controls or find replacement generation. In addition, the commenter notes that the study shows 

that utility providers will spend up to $20 billion in the next 50 years disposing of coal ash, and the 

proposed ozone limits are also a concern if lowered to 0.060 ppm because 13 of 14 monitored counties 

in Alabama will become non-attainment areas. According to the commenter, nationwide, 85% of 

monitored counties will become non-attainment for ozone and the cost for coming into attainment will 

be $20-$90 billion annually.

Comment 27: Comment 18488 cites the ICF report that concludes the proposed rule will impose 

incremental capital costs on industry of $141-247 billion and will lead to significantly more retirements 

than the EPA predicts, leading to reliability issues and increases in costs.

Response to Comments 26 - 27: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the 

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices. In addition, the EPA has analyzed resource adequacy issues and 

finds that there is ample existing spare capacity to serve load, and industry has also shown that it can 

build new capacity quickly in response to demand. Studies done by industry have several flaws, 

including a poor reflection of the actual rule requirements, inadequate inclusion of proven technologies, 

and unsupported speculation with regard to other policy, like climate policy. Changes to the national 

ambient air quality standards for ozone are not a subject of this rulemaking.

Comment 28: Commenter 18023 states that the estimated costs do not include billions of lost economic 

productivity that may be incurred due to load shedding to manage the bulk power system.

Response to Comment 28: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the 

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices.In addition, the EPA has analyzed resource adequacy issues and 

finds that there is ample existing spare capacity to serve load, and industry has also shown that it can 

build new capacity quickly in response to demand.

Comment 29: Commenter 17682 requests the EPA consider the added cost impacts for generation of 

electricity from coal, the cumulative impacts of new wind turbines and solar panels and new electrical 

distribution lines.
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Response to Comment 29: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, like wind and solar, and does not show that the rule will lead to 

extensive substitution away from coal-fired generation. Industry has shown that it can install large 

amounts of pollution controls and often finds more cost-effective compliance options than the EPA can 

anticipate. In addition, the EPA has analyzed resource adequacy issues and finds that there is ample 

existing spare capacity to serve load, and industry has also shown that it can build new capacity quickly

in response to demand.

Comment 30: Commenters 17702 and 18033 quote the proposed rule estimate of a 3.7% price increase 

for electricity in 2015, 2.6% in 2020 and 1.9% in 2030. Commenter 17702 believes this increase will 

impact areas with dependence on coal and oil generation more than other regions, and the prices there 

will increase more. The commenter encourages the EPA to work with state and federal energy and 

environmental regulators to craft solutions that will enable utilities to comply with the proposed rule and 

other EPA rules to minimize cost impacts to consumers.

Response to Comment 30: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. Industry has shown that it can install large amounts of 

pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. 

In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare 

capacity to serve load, and industry has also shown that it can build new capacity quickly in response to 

demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public 

utility commissions and other regulatory authorities have extensive experience with regulatory

requirements and treatment of costs to consumers, and are prepared for responding to the cost of future 

pollution control equipment or other response measures. In addition, there are certain provisions for 

granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 31: Commenter 18033 considers the low estimate of early retirements to be one reason the 

EPA’s impacts are so much lower than other estimates. The commenter explains that the biases within 

the EPA’s model are incorrect because the model assumes that regions with excess supply will absorb 

the capacity lost by retirements, making retirement decisions a product of geography rather than 

economic factors.

Response to Comment 31: The EPA has conducted detailed updated economic analysis of the rule, and 

believes that the impact on potential retirements to be driven by both economic and geographic 

(locational) considerations, which the EPA modeling fully reflects. In addition, the EPA has analyzed 

resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry

has also shown that it can build new capacity quickly in response to demand. The EPA will work with 

relevant authorities to ensure a smooth transition with this rule. Public utility commissions and other 

regulatory authorities have extensive experience with regulatory requirements and treatment of costs to 

consumers, and are prepared for responding to the cost of future pollution control equipment or other 

response measures. In addition, there are certain provisions for granting utilities some additional time to 

comply, if conditions warrant (see preamble).

Comment 32: Commenter 18961 cites a study done by a consortium of electric companies that found, 

“Industry data counter concerns that it will cost the industry too much to comply with EPA’s proposed 

air regulations, that pollution controls cannot be installed soon enough, or that the EPA regulations will 

lead to the closure of otherwise economically healthy power plants.” The commenter reports that the 

study also notes that the proven technologies for controlling Hg and other air toxics are commercially 
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available, and adds that the coal-fired units that are most likely to be retired in the face of the new rule 

are smaller, 40- to-60-year old units that are already “economically challenged ̈ and nearing the end of 

their design life expectancies. (Ensuring a Clean, Modern Electric Generating Fleet while Maintaining 

Electric System Reliability, M.J. Bradley & Associates LLC and Analysis Group. August 2010.

http://www.mjbradley.com/documents/MJBAandAnalysisGroupReliabilityReportAugust2010.pdf)

Response to Comment 32: The EPA agrees with the commenter. The EPA has conducted detailed 

updated economic analysis of the rule, and believes that the impacts to be reasonable given the large 

benefits.

Comment 33: Commenter 17761 states that the impact analysis conducted by the EPA is inaccurate and 

not comprehensive and needs to be revised to account for true costs and benefits of the rule on regulated 

entities and the general public.

Response to Comment 33: The EPA has conducted as detailed and comprehensive an updated 

economic analysis of the rule as reasonably possible to reflect the true costs and benefits, and 

commenter does not substantiate the claims made.

Comment 34: Multiple commenters (16549, 17114, 17639, 17698, 17782, 18033) ask that the EPA 

delay indefinitely its proposed Utility MACT rule until further study can be undertaken on the potential 

costs and negative incomes to industry, jobs, and consumers. Commenters state that the current 

compliance deadline of 3 years does not meet the tests of reasonability or realism.

Response to Comment 34: The EPA does not have the flexibility to delay the rule, which is governed 

by a consent decree and the requirements of the CAA. However, it has conducted detailed economic 

impacts analysis on the regulated sector, and finds the impact of the rule on the regulated sector is small 

compared to the overall benefits, and the industry has an excellent track record of installing pollution 

controls without greatly impacting electricity prices. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the 

maximum 3-year period for sources to come into compliance. Sources may also seek a 1-year extension 

of the compliance period from their Title V permitting authority if the source needs that time to install 

controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule and 

address specific issues. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 35: Several commenters (17811, 18436, 18478) offer support for the EPA’s proposed rule, 

stating that many power plants currently utilize the technology required and the EPA is providing 

adequate flexibility in the requirements by allowing facility-wide averaging for all HAP emissions from 

existing units in the same subcategory, effectively providing for equivalent, less costly technology in 

achieving the proposed emission standards. Commenters 17811 and 18436 encourage the EPA to move 

forward with implementation, as the commenters feels it would be too costly to not regulate toxic air 

pollutants. The commenters provide information from the Jefferson County Health Dept. in Alabama 

that estimates 15 manufacturing businesses and roughly $5 billion in economic investments were lost in 

the Birmingham metro area due to non-attainment air quality status.

Response to Comment 35: We thank the commenters for these comments. The EPA notes that the rule 

does not require specific technology, but that the level of performance called for by the rule is currently
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being achieved by a number of sources using certain technologies. The agency will be flexible in 

allowing sources to comply with this rule consistent with the requirements of the CAA.

Comment 36: Commenter 17877 believes that finalization of the proposed rule will result in increased 

costs that non-profit cooperatives will need to pass on to consumers, which will negatively impact 

economic development and jobs.

Response to Comment 36: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, and is unlikely to lead to extensive substitution away from coalfired generation. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. The EPA will 

work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions 

and other regulatory authorities have extensive experience with regulatory requirements and treatment of 

costs to consumers, and are prepared for responding to the cost of future pollution control equipment or 

other response measures. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 37: Commenter 18025 reports that their plants are among the cleanest, most environmentally

responsible coal-fired plants in the nation due to the addition of more than $1 billion in control 

technologies and cleaner-burning generation. The commenter states that these installations were 

successfully coordinated with unit outages and position the facilities to comply with the proposed rule in 

advance of the deadlines.

Response to Comment 37: The EPA believes that coal units that have already installed pollution 

controls will be well situated to comply with this rule by taking relatively modest steps to ensure 

compliance. The EPA also believes that the pollution control installations can be managed by industry. 

Industry has shown that it can install large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate.

Comment 38: Commenter 18033 quotes legislative intent in The House Report on Section 112 that 

states: “In the determination of MACT for new and existing sources, consideration of cost should be 

based on an evaluation of the cost of various control options. The Committee expects MACT to be 

meaningful, so that MACT will require substantial reductions in emissions from uncontrolled levels. 

However, MACT is not intended to require unsafe control measure, or to drive sources to the brink of 

shutdown.” The commenter believes the EPA’s proposed rule runs counter to this intent. Commenter

18500 also reminds the EPA of Congress’s statement and states their belief that this is exactly what the 

proposed rule, in combination with other new or pending rules, will accomplish in addition to impairing 

electric reliability and increasing costs.

Response to Comment 38: The agency is not requiring the use of any unsafe control measure. 

Measures that could be applied by sources to meet the rule requirements are well-demonstrated and are 

already in use at a substantial number of utilities, as explained in the preamble to the rule. In addition, 

the agency has estimated that only about 3% of generating capacity subject to this rule nationwide may 

retire early by 2015 in response to the rule, and this result is the product of business decisions rather than 

a specific requirement of the rule. This analysis has been updated for the final rule.
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Comment 39: Commenter 18421 supports the EPA’s proposed rule and explains that new standards are 

always met with claims of infeasibility and impracticality. Yet, the commenter states that history shows 

the reverse to be true. The commenter outlines proven benefit-to-cost ratios of up to 23 to 1 for EPA 

regulations from 2000 through 2010 and economic growth and benefits from public health. The 

commenter also outlines cost-benefit ratios for regulations from 1970-1990 that show a net benefit in 

present value over the period were $22 trillion and the benefits outweighed the costs by 40 to 1.

Response to Comment 39: The EPA generally agrees with commenter’s stated views. Industry has 

shown that it can install large amounts of pollution controls and often finds more cost-effective 

compliance options than the EPA can anticipate. The rule will also result in benefits that are many times 

larger than the cost of compliance.

Comment 40: Commenter 18422 believes the proposed rule will negatively affect a significant portion 

of the industry and its customers since nearly half of electric generation is fueled by coal, making the 

proposed rule a threat to reliability and affordability. The Commenter requests that the EPA reconsider 

the regulating of acid gases as they are not required and will impose greater cost and difficulty.

Response to Comment 40: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the 

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices.

Comment 41: Commenter 18430 believes that job losses and cost burdens for consumers will outweigh 

any benefit from the proposed rule and asks that the EPA reconsider the rule in light of the public 

comment and withdraw the proposed rule until further impact studies can be done.

Response to Comment 41: The EPA does not have the flexibility to delay the rule, which is governed 

by a consent decree and the requirements of the CAA. However, it has conducted detailed economic 

impacts analysis on the regulated sector, and finds the impact of the rule on the regulated sector is small 

compared to the overall benefits, and the industry has an excellent track record of installing pollution 

controls without greatly impacting electricity prices. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the 

maximum 3-year period for sources to come into compliance. Sources may also seek a 1-year extension 

of the compliance period from their Title V permitting authority if the source needs that time to install 

controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule and 

address specific issues. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 42: Multiple commenters (17682, 17701, 17765, 17761, 17813, 18433, 17904, 17930, 18023, 

18484) express concern that the rule will result in rate increases for consumers. Commenter 18023 notes 

that less affordable electricity prices would have other indirect consequences, such as the loss of energyintensive manufacturing operations, the loss of U.S. manufacturing jobs, a decline in tax revenues, and 

risk to national security if military bases and key manufacturing and production operations do not have a 
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steady and reliable supply of electricity. Commenter 17765 states that utilities are already requesting 

residential rate increases of up to 19% (see http:/ /www.courier-journal.com/article/20110525/BUSIN

ESS/305250080/LG-E-seek-19-rateincrease) and points out that recent regulatory impact studies predict 

electricity prices will rise by as much as 25% in some regions of the country (see “Proposed CATR + 

MACT,” NERA Economic Consulting, Draft May 2011). Similarly, commenter 17904 cites research 

conducted by Bernstein that predicts costs in both the PJM and MISO RTOs are expected to go up 

significantly and remain volatile.

Commenter 18484 believes the proposed rule will cause irreparable harm to the economy and national 

security due to energy cost increases negatively affecting the ability to compete in the global market and 

increasing unemployment. The commenter believes increased energy costs will harm the development 

of mineral resources and the mining industry, resulting in fewer projects and jobs and increasing 

dependency on foreign resources. The commenter explains that coal currently provides around 50% of 

electricity in the U.S. and the nation has coal reserves to continue this for hundreds of years without 

even considering the massive coal reserves in Alaska. The commenter also says that coal resources have 

less environmental impact in many cases that alternative energy production since coal produces 100 to 

1000 watts per square meter of land, while solar produces 4 to 9 watts/square meter, wind produces 0.5 

to 1.5 w/sm and biomass produces 0.5 to 0.6 w/sm. The commenter states that the EPA needs to 

complete a cost-benefit analysis that reflects the cumulative impacts of using one compliance 

technology to control one pollutant on the ability of other technologies to control other pollutants and 

that reflects the cost for makeup energy for lost generation and the ultimate cost increases for 

consumers. The commenter asks the EPA to include the cost of the hundreds of thousands of new wind 

turbines, solar panels and electrical distribution lines and consider if citizens would prefer to subsidize 

uneconomic energy sources, such as wind, solar and bio-fuels or not implement the proposed rule. The 

commenter also explains that the proposed rule with cost the government more money for electricity as 

well, resulting in less money for basic services, including other environmental programs. The 

commenter requests that the EPA withdraw the proposal and develop a more balanced rule.

Response to Comment 42: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, and is unlikely to lead to extensive substitution away from coalfired generation. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. The EPA will 

work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions 

and other regulatory authorities have extensive experience with regulatory requirements and treatment of 

costs to consumers, and are prepared for responding to the cost of future pollution control equipment or 

other response measures. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble). 

Comment 43: Commenter 18489 believes the estimated compliance cost of $10.9 billion will impact 

the economy and jeopardize the recovery our nation needs.

Response to Comment 43: As discussed elsewhere in this document, the EPA has conducted detailed 

impact analysis of the rule, which does not show significant impacts to the economy, and the costs of the 

rule are greatly outweighed by the benefits.
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Comment 44: Commenter 18907 foresees negative effects for smaller businesses, including retail 

gasoline outlets.

Response to Comment 44: The EPA does not anticipate a notable impact on retail gasoline outlets as a 

result of this rule, and its detailed economic analyses, discussed elsewhere in this document, show the 

impacts to businesses and consumers to be relatively small.

2. State/regional impacts, low income.

Comment 45: Commenter 17731 expresses concern that the EPA’s overview of the price increases does 

not see the hardships that will be the reality of increased prices on low-income or fixed-income 

households or small businesses. The commenter reports increases of $90 million in capital costs, $11.4 

million in annual operating costs and $6.4 million in annual debt service costs to achieve compliance, 

which will lead to a 13% increase in rates for the proposed rule, and a 41% increase for all proposed and 

new regulation compliance costs. The commenter argues against the EPA’s view that energy efficiencies 

will offset rate increases, because low income customers will need to use less electricity due to 

economic necessity. The commenter also sees large price increases for customers if units are converted 

to natural gas, which is approximately 2.5 times more expensive than the coal that the commenter

currently uses to generate electricity.

Response to Comment 45: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, and is unlikely to lead to extensive substitution away from coalfired generation. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. The EPA will 

work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions 

and other regulatory authorities have extensive experience with regulatory requirements and treatment of 

costs to consumers, and are prepared for responding to the cost of future pollution control equipment or 

other response measures. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 46: Commenter 17743 expresses particular concern over the proposed rule’s impacts on the 

Oklahoma economy, such as the potential increase of electricity rates and resulting economic impacts on 

residents and businesses.

Response to Comment 46: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, and is unlikely to lead to extensive substitution away from coalfired generation. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. The EPA will 

work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions 

and other regulatory authorities have extensive experience with regulatory requirements and treatment of 

costs to consumers, and are prepared for responding to the cost of future pollution control equipment or 

other response measures. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).
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Comment 47: Commenter 17772 is a utility with a large percentage of coal-fired generation. As such, 

the commenter’s concern is the ability to meet customer’s needs for electricity if the proposed rule is 

finalized, since it will lead to unit closures.

Response to Comment 47: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies, and is unlikely to lead to extensive substitution away from coalfired generation. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. The EPA will 

work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions 

and other regulatory authorities have extensive experience with regulatory requirements and treatment of 

costs to consumers, and are prepared for responding to the cost of future pollution control equipment or 

other response measures. In addition, there are certain provisions for granting utilities some additional 

time to comply, if conditions warrant (see preamble).

Comment 48: Commenter 19213 states that the proposed rule could result in the retirement of one or 

more units and increased electricity rates in Illinois, driving out businesses.

Response to Comment 48: The agency has estimated that only about 3% of generating capacity subject 

to this rule nationwide may retire early by 2015 in response to the rule, according to the analysis 

completed for the proposed rule, and this result is the product of business decisions rather than a specific 

requirement of the rule. The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The EPA will work with relevant authorities to ensure a 

smooth transition with this rule. Public utility commissions and other regulatory authorities have 

extensive experience with regulatory requirements and treatment of costs to consumers, and are prepared 

for responding to the cost of future pollution control equipment or other response measures. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 49: Commenter 19214 believes the EPA should expand the quantity and quality of their 

review so that accurate, realistic and broadly-accepted expectations of the cost, development timeline 

and performance of emission control systems can be considered in the final rule.

Response to Comment 49: The EPA has revised the detailed impact analysis of the proposed rule for 

the final rule in a number of ways, and believes that the analysis presents an accurate and comprehensive 

evaluation of the rule’s impacts. The analysis includes the specific operating parameters and variability

of other technologies, and is unlikely to lead to extensive substitution away from coal-fired generation. 

In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare 

capacity to serve load, and industry has also shown that it can build new capacity quickly in response to 

demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public 

utility commissions and other regulatory authorities have extensive experience with regulatory

requirements and treatment of costs to consumers, and are prepared for responding to the cost of future 

pollution control equipment or other response measures. In addition, there are certain provisions for 

granting utilities some additional time to comply, if conditions warrant (see preamble).
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Comment 50: Commenter 17911 questions the accuracy of the RIA and states that the EPA skipped a 

number of procedural steps in their effort to meet the rule deadline. The commenter questions the EPA’s 

estimates as a result and calls into question the EPA’s estimates of the following:

1. Impact of Rule on the National Economy

2. Increase in Electric Rates (commenter expects costs to increase by several percentage points)

3. Financing costs for emission retrofits

4. Loss of external revenue streams from sale of CCR

5. Increased costs for disposal of CCR

6. Loss of revenue from increased parasitic load at power plants

7. Decrease in Disposable Income

8. Increase in Cost of Operation for Small Political Subdivisions

The commenter requests that EPA conduct a more robust study of the economic impact of this rule.

Response to Comment 50: The EPA has analyzed many of these impacts, which can be found in the 

RIA of the rule. The EPA has not analyzed the impact of other regulations, which will be conducted in 

accordance with the relevant requirements for each individual rulemaking (like CCR).

Comment 51: Commenter 17774 discusses plant closures in South Carolina which are expected to 

occur in response to the proposed rule. The commenter disagrees with the EPA’s prediction of job gains 

and believes job losses will be focused on coal-dependent regions like the southeast.

Response to Comment 51: The agency’s employment impact analysis for the proposed rule shows 

some increase in short-term (i.e., by 2015) employment associated with the installation and operation of 

pollution control equipment. The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule in the long-term, but overall 

expects the employment impact in the short-term and long-term to be relatively small in comparison to 

the affected sector and the overall economy. This is also consistent with the economic literature.

Comment 52: Commenters 18424 and 18425 believe the EPA has underestimated the impact of the 

proposed rule on EGUs burning bituminous coal and will severely impact the Indiana coal industry and 

Indiana jobs in general. The first commenter explains that Indiana produces bituminous coal and expects

severe job losses in coal, mining and transportation industries, which will have a multiplier effect 

causing more job losses throughout the state. The commenter quotes an ICC study showing Indiana job 

losses at more than 12,000 due to the loss of coal production. The commenter also notes that the cost of 

compliance will increase electricity costs and erode the competitive advantage enjoyed by Indiana in 

manufacturing, leading to a total loss of 50,000 jobs in the state.

Response to Comment 52: The EPA’s analysis of the rule shows that it is unlikely to lead to extensive 

substitution away from coal-fired generation. Industry has shown that it can install large amounts of 

pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. 

In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare 

capacity to serve load, and industry has also shown that it can build new capacity quickly in response to 

demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public 

utility commissions and other regulatory authorities have extensive experience with regulatory

requirements and treatment of costs to consumers, and are prepared for responding to the cost of future 

pollution control equipment or other response measures. In addition, there are certain provisions for 

granting utilities some additional time to comply, if conditions warrant (see preamble). The EPA has 
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conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy. This is also consistent with the economic

literature.

Comment 53: Commenter 16849 believes the proposed rule creates undue burden due to straying from 

the cohesive air quality program goals embracing multi-pollutant control strategies. The commenter also 

believes that midwest states will bear a disproportionate burden for compliance due to coal-fired 

generation utilization.

Response to Comment 53: The EPA analysis shows that industry can comply with the rule largely by

installing pollution controls, and coal will continue to remain an important part of the generation mix.

By addressing revisions to the NSPS and standards for emissions of mercury and other HAP, and by

accounting for the multi-pollutant co-benefits of the rules, the EPA has sought to coordinate 

requirements for the control of multiple pollutants and thus is being responsive to the goal of multipollutant control strategies.

Comment 54: Commenter 19041 expresses concern that the proposed rule will have effects on the 

ability of their cooperative to provide affordable and reliable service to consumers in Ohio. The 

commenter reports that the cooperative has already installed SCR on coal-fired units, and has or is 

installing scrubbers all for around $1.8 billion but is concerned that it will not be enough to comply with 

the proposed rule.

Response to Comment 54: Utilities that have already installed pollution controls are likely to be well 

positioned to comply with this rule with modest modifications.

Comment 55: Commenters 19653 and 19199 state a concern that the proposed rule will have an impact 

on the price of electricity in Indiana. The commenter sees the price of energy to be a major cost of doing 

business, and worries that increases in energy costs will negatively impact businesses. Commenter

19653 especially expresses concern about the construction industry because the electricity cost impacts 

on construction could limit availability of affordable housing in Indiana. Also, disruptions in service as a 

result of the compressed timeline could delay progress on new construction and remodeling.

Response to Comment 55: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 

away from coal-fired generation. Industry has shown that it can install large amounts of pollution 

controls and often finds more cost-effective compliance options than the EPA can anticipate. In addition, 

the EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to 

serve load, and industry has also shown that it can build new capacity quickly in response to demand. 

The EPA does not anticipate large impacts on the home construction industry, and is unable to see why

the rule would impact availability of affordable housing since electricity prices are projected to increase 

only modestly.

Comment 56: Commenter 17805 has concerns about the potential economic and reliability impacts of 

the proposed rule on customers in Montana and the Dakotas.

Response to Comment 56: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 
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and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 

away from coal-fired generation. Thus reliability issues are not expected to be significant. Industry has 

shown that it can install large amounts of pollution controls and often finds more cost-effective 

compliance options than the EPA can anticipate. In addition, the EPA has analyzed resource adequacy

issues and finds that there is ample existing spare capacity to serve load, and industry has also shown 

that it can build new capacity quickly in response to demand.

Comment 57: Commenter 18907 reports that a provider in the midwest has announced the shutdown of 

up to 25% of its coal-fired generating capacity, which will increase electricity rates. This price increase 

will impact businesses and create problems with remaining competitive for manufacturers.

Response to Comment 57: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 

away from coal-fired generation. Industry has shown that it can install large amounts of pollution 

controls and often finds more cost-effective compliance options than the EPA can anticipate. In addition, 

many announced coal retirements are due to reasons not related to EPA actions, such as low natural gas 

prices and lower electricity demand. These units are typically the oldest and least efficient units in the 

coal fleet.

Comment 58: Commenter 18933 states that textile production in North and South Carolina and Georgia 

will suffer from an estimated increase of 11.5%. This expense is likely to make the industry less 

competitive with foreign businesses.

Response to Comment 58: Retail electricity prices are projected to increase roughly 3.1% in 2015 

nationwide, based on the agency’s analysis contained in the RIA for the rule. This increase, while not 

trivial, is not expected to yield significant impacts to manufacturers. The EPA’s analysis indicates that 

coal-fired generation will maintain its large share of generation. In addition, industry has shown that it 

can install large amounts of pollution controls and often finds more cost-effective compliance options 

than the EPA can anticipate. The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 

away from coal-fired generation. Industry has shown that it can install large amounts of pollution 

controls and often finds more cost-effective compliance options than the EPA can anticipate.

Comment 59: Commenter 18502 expresses concerns about the impact the proposed rule will have on 

Puerto Rico when the costs of compliance are passed on to consumers. The commenter points out that 

the impacts of the proposed rule on the local economy will limit the economic recovery and increase 

electricity costs that are already twice those of the continental U.S. The commenter estimates that 70% 

of the electricity on the island is oil-fired generation and 70-75% of the consumers’ costs are for fuel, so 

the proposed rule will strongly impact the system reliability and costs, despite having little benefit to an 

island with trade winds that produce excellent air quality. The commenter asks that the EPA reconsider 

controlling emissions from oil-fired units since the HAP emissions are much lower than from coal-fired 

units and the compliance costs are much higher.

Response to Comment 59: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 
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away from coal-fired generation. In addition, separate standards are being finalized for territories (see 

preamble).

Comment 60: Commenter 18538 states that the Texas economy and service reliability will be impacted 

by the proposed new rule. The commenter believes the proposed rule will negatively impact residential 

customers and energy-intensive business and the jobs they create. The commenter points out that 

environmental regulations in Europe have sent manufacturing businesses elsewhere. Commenters 18538 

and 13526 state that because Texas generates more energy from coal than any other state (more than 

60% greater than the next highest state) and almost 10% of the total amount for the U.S., the state’s 

generation fleet will be disproportionately impacted and a large amount of retirements will occur, and 

the future of planned plants is in question. Commenters cite various studies and power plant closing 

announcements which show the likely retirement rate to be far beyond that estimated by the EPA. All of 

this makes reliability an issue in the state, with one study estimating a reserve margin of -8.6%. The 

commenter states that the EPA’s impacts analyses are flawed and asks that they be revised to consider 

the full impact of all the new and proposed rules.

Response to Comment 60: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis includes the specific operating parameters 

and variability of other technologies and coal types, and is unlikely to lead to extensive substitution 

away from coal-fired generation. Industry has shown that it can install large amounts of pollution 

controls and often finds more cost-effective compliance options than the EPA can anticipate. In addition, 

the EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to 

serve load, and industry has also shown that it can build new capacity quickly in response to demand. 

The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public utility

commissions and other regulatory authorities have extensive experience with regulatory requirements 

and treatment of costs to consumers, and are prepared for responding to the cost of future pollution 

control equipment or other response measures. In addition, there are certain provisions for granting 

utilities some additional time to comply, if conditions warrant (see preamble).

Comment 61: Commenter 18538 states that a competitive market will affect decisions about retrofitting 

or retirement of a plant. The commenter explains that a merchant generator selling into a competitive 

market, like that in ERCOT bears the cost and risk of the investment because there is no guarantee of 

recovering the costs to retrofit.

Response to Comment 61: The requirements of the CAA do not distinguish between energy markets, 

and participants in competitive markets understand the risks inherent in those markets, such as the 

potential costs associated with pollution controls. In addition, these markets are largely driven by the 

cost of the marginal producing electricity generating unit(s), which is most often natural gas. Industry

has shown that it can install large amounts of pollution controls and often finds more cost-effective 

compliance options than the EPA can anticipate, irrespective of whether it is located in cost of service or 

competitive markets.

Comment 62: Commenter 18538 considers the EPA’s predictions about energy efficiency mitigating 

impacts of the proposed rule and explains that Texas has a robust efficiency program, but estimates it 

will only offset 681 MW of demand in 2015 and 1,448 MW in 2020, a total of 1% in 2015 and 2% in 

2020.

Response to Comment 62: The EPA believes energy efficiency measures can be a complement to this 

rule, and can be an important tool in helping address emissions. The EPA has not included all the likely 
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additional energy efficiency measures that are likely to occur by 2015, but will continue to pursue 

energy efficiency improvements throughout the economy, along with other federal agencies, states and 

other groups. This will contribute to additional environmental and public health improvements while 

lowering the costs of realizing those improvements.

Comment 63: Commenters 17137 and 18021 believe that if the proposed rule is implemented with the 

current timeline and stringency, industry in the southeast, which relies on affordable, reliable electricity, 

will be weakened, jobs will be lost, and power consumers will be hurt. Commenters point out that the 

southeast is particularly vulnerable to the proposed rule because it relies heavily on manufacturing and 

provides hundreds of thousands of jobs and billions in economic impact as a result. Commenters state 

that the abundant, reliable and inexpensive electricity from native coal resources is a factor in the 

thriving skilled labor market and foreign manufacturing investment. Commenter 18021 points out that 

regulated utilities have no choice but to pass cost increases on to customers. The commenter also 

explains that in addition to capital costs, the addition of control technology reduces efficiency of the 

plants, increasing fuel costs. 

Response to Comment 63: The implementation date for this rule is set to be consistent with the 

requirements of the CAA for standards such as these. Retail electricity prices are projected to increase 

roughly 3.1% in 2015 nationwide, based on the agency’s analysis contained in the RIA for the rule. This 

increase, while not trivial, is not expected to yield significant impacts to manufacturers. The EPA’s 

analysis indicates that coal-fired generation will maintain its large share of generation. In addition, 

industry has shown that it can install large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate. 

Comment 64: Commenters 17712 and 17743 explain that cooperative EGUs will generally need to add 

controls to comply with the proposed rule, and others will need to shut down because they will be 

unable to comply in a cost-effective and timely manner.

Response to Comment 64: The EPA will work with relevant authorities to ensure a smooth transition 

with this rule. In addition, there are certain provisions for granting utilities some additional time to 

comply, if conditions warrant (see preamble). The EPA analysis also indicates that there will be 

relatively modest amounts of retirements and installation of pollution controls will be a cost-effective 

compliance measure. In addition, many coal facilities have already invested in pollution controls, and 

they are well positioned to comply with this rule with modest changes to operations.

Comment 65: Commenter 17718 considers the proposed rule to be hardest on states which rely heavily

on coal-fired plants and uses Kentucky as a state which is jeopardized by the proposed rule due to the 

loss of inexpensive electricity giving it a competitive advantage at attracting industry. Kentucky runs the 

risk of seeing lucrative local businesses such as auto plants leave the region if electricity prices increase 

due to the proposed rule.

Response to Comment 65: The EPA’s analysis indicates that coal-fired generation will maintain its 

large share of generation. In addition, industry has shown that it can install large amounts of pollution 

controls and often finds more cost-effective compliance options than the EPA can anticipate.

Comment 66: Commenter 17055 mentions that their initial assessment did not consider impacts the 

RICE regulations may have on the potential loss of small units relied upon by many municipalities. 

Elimination of these units could, the commenter believes, lead to local congestion and require 

transmission expansion and local programs to meet demand. The commenter believes that working with 
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the industry to institute these changes will help preserve reliable system operations and also allow for a 

more gradual integration of the costs of compliance that could significantly mitigate reliability issues 

and sudden increases in consumer electricity prices.

Response to Comment 66: The agency is currently reconsidering the Compression Ignition and Spark 

Ignition RICE NESHAP. The outcome of this reconsideration may affect the congestion and other issues 

the commenter points out.

Comment 67: Commenter 17821 explains the additional hardships for small cooperative utilities, which 

often share several small units in order to split the risk and increase reliability. The commenter believes 

the EPA has not fully recognized the impact of the proposed rule on these small entities. The commenter

does not believe that the work practice standards, subcategorization, health-based compliance options or 

emissions averaging will adequately reduce the burden to such organizations and their financial wellbeing will be strained by the proposed rule. The commenter believes more flexibility is needed, as well 

as more time, to minimize risk to small businesses.

Response to Comment 67: The EPA will work with relevant authorities to ensure a smooth transition 

with this rule. In addition, there are certain provisions for granting utilities some additional time to 

comply, if conditions warrant (see preamble). The EPA analysis also indicates that there will be 

relatively modest amounts of retirements and installation of pollution controls will be a cost-effective 

compliance measure. In addition, many coal facilities have already invested in pollution controls, and 

they are well positioned to comply with this rule with modest changes to operations.

Comment 68: Commenter 17745 expresses concern over the impacts on the Georgia state economy by

the proposed rule, especially the increased cost of electricity and the impacts on residents and 

businesses.

Response to Comment 68: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. Industry has shown that it can install large amounts of 

pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. 

The EPA will work with relevant authorities to ensure a smooth transition with this rule. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). Although certain regions will need to do more in order to comply, those same regions 

will also benefit from the emission reductions. Overall, coal use is not anticipated to be greatly impacted 

as coal-fired sources install pollution controls, with only modest amounts of retirements. Retail 

electricity prices are projected to increase slightly on average by 2015. Thus, there may be some 

negative impacts from this rule in these regions, but these same regions will also experience some of the 

benefits, such as reduced premature mortality from less exposure to PM2.5 emissions as shown in 

Appendix C of the RIA. In addition, the EPA has conducted an updated employment analysis which 

shows some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 69: Multiple commenters (16705, 17400, 17697, 17868, 18038, 18433) consider the EPA’s 

RIA to be flawed in suggesting that only 97 municipal utilities will face a compliance cost of $666.30 

million annually. Commenter 16705 states that these costs underestimate the impact on states such as 

Indiana, Ohio, Wisconsin, Michigan, Minnesota, Kentucky, Georgia, Alabama and Texas. Commenter 

17400 notes that these costs ignore Guam, where an additional $49 to $103 million is expected to be 

spent in capital costs with $1.2 to $2.6 million in annual costs. Commenter 17697 explains that the cost 

analysis does not include the cost of purchasing power during scheduled outages for retrofit, the costs of 
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fuel switching, or the inability to sell coal ash or coal combustion residuals to the cement industry. 

Footnotes pertaining to the coal ash include a reference and an estimate that fly ash would cost an extra 

$100 million over 20 years for disposal.

Response to Comment 69: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The EPA has also updated its UMRA analysis. Industry

has shown that it can install large amounts of pollution controls and often finds more cost-effective 

compliance options than the EPA can anticipate. The EPA will work with relevant authorities to ensure 

a smooth transition with this rule. In addition, there are certain provisions for granting utilities some 

additional time to comply, if conditions warrant (see preamble). There are also separate standards for 

U.S. territories. The EPA is addressing coal combustion residuals in a separate rulemaking.

Comment 70: Several commenters (17689, 17697, 17710, 18433) explain Guam’s dependence on a 

single fuel-oil electric utility plant to provide all of the island’s power. This situation leads the 

commenters to believe the island will be significantly impacted in energy costs and reliability as a result 

of the proposed rule. Commenters 17710 and 18433 state the rule’s burden is unacceptable and that the 

cost of energy is a more significant part of household and business expense than nationally. Commenter

17698 requests that acid gases not be regulated under the proposed rule, since it will increase costs and 

make compliance more difficult. Commenters 17697 and 18433 believe the electricity rates will 

increase, especially since 70% of the cost of Guam’s power production comes from fuel costs. The 

commenters believe this rate increase will increase unemployment and cause economic hardship for the 

already disproportionately high percentage of the island’s population currently unemployed or 

underemployed.

Response to Comment 70: The EPA is required to regulate acid gas HAP such as hydrochloric and 

hydrofluoric acids under this rule, and the rationale for doing so is set forth in the preamble. As to 

impacts to Guam, the agency will limit the impact of this rule on the power plant to that consistent with 

the CAA and note that in the final rule, we have established a subcategory for non-continental liquid oilfired EGUs that should address some of commenters’ concerns.

Comment 71: Commenter 17730 estimates that the proposed rule will cost hundreds of millions of 

dollars in initial capital costs for their region, which will be passed on to consumers in some of the top 

100 poorest counties in the country.

Response to Comment 71: The agency’s analysis of changes in the national average retail electricity 

price associated with this rule finds is projected to be 3.1% in 2015. If this increase in retail electricity 

price is a concern, then state and local agencies are best equipped to manage rate structures to mitigate 

any impacts associated with this increase. In addition, the increase in retail electricity price should be 

understood in light of the substantial benefits (including co-benefits).

Comment 72: Commenter 17791 requests that the EPA avoid compromising energy system reliability, 

seek ways to minimize cost impacts, ensure availability of electricity and natural gas, consider 

cumulative impacts of multiple rules and employ rigorous cost-benefit analyses. The commenter also 

suggests the EPA consider regional differences that will impact system reliability and costs, such as the 

increased impacts on regions relying heavily on coal and oil and encourages cooperation between the 

EPA and state and federal energy and environmental regulators.

Response to Comment 72: The agency has studied possible impacts on reliability as a result of this 

rule, and has determined that these impacts should not be significant. The agency has prepared a detailed 
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TSD to document this study, and this document is the docket for this rulemaking. The agency has 

considered impacts on a regional basis as part of its overall analyses done using the IPM; these results 

are documented in the RIA for the rule and in several TSDs. 

Comment 73: Commenter 18497 says the group’s six “footprint states” generated over 67% of their 

electricity from coal in 2009, varying from 36.5% in Virginia to 96.2% in West Virginia. The 

commenter says the variability of the impacts will be similar and should be considered by the EPA. 

Based on age alone, the commenter states that over 28% of the region’s summer generating capacity

(143 units) can be considered at risk for retirement due to the proposed rule.

Response to Comment 73: The EPA has conducted detailed impact analysis of the rule, which shows 

that coal will remain the largest source of electricity. The agency has estimated that only about 3% of 

generating capacity subject to this rule nationwide may retire early by 2015 in response to the rule, 

according to the analysis completed for the proposed rule. In addition, the EPA has analyzed resource 

adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has also 

shown that it can build new capacity quickly in response to demand and also manage the installation of 

pollution controls. The EPA will work with relevant authorities to ensure a smooth transition with this 

rule. Public utility commissions and other regulatory authorities have extensive experience with 

regulatory requirements and treatment of costs to consumers, and are prepared for responding to the cost 

of future pollution control equipment or other response measures. In addition, there are certain 

provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 74: Commenter 17829 explains that their power supplier estimated that if scrubbers are 

required for their plant, the cost could reach $1 billion. The commenter goes on to state that the resulting 

cost increase will most impact the elderly, poor and those who have lost jobs at a time when the Low 

Income Home Energy Assistance Program has been decreased significantly.

Response to Comment 74: The rule does not dictate any particular technology and the EPA has 

attempted to provide the maximum degree of flexibility to source owners within the limitations of the 

CAA. The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to 

retail electricity prices. The analysis indicates that coal will remain the largest source of electricity. 

Industry has shown that it can install large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate. In addition, the EPA has analyzed resource 

adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has also 

shown that it can build new capacity quickly in response to demand and also manage the installation of 

pollution controls. The EPA will work with relevant authorities to ensure a smooth transition with this

rule. Public utility commissions and other regulatory authorities have extensive experience with 

regulatory requirements and treatment of costs to consumers, and are prepared for responding to the cost 

of future pollution control equipment or other response measures. In addition, there are certain 

provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 75: Commenter 17884 quotes NMA statistics showing coal is responsible for $65.738 billion 

in annual economic activity, produces 1,798,800 jobs and $36.345 billion in annual labor income. The 

commenter reports that regions such as Appalachia, the midwest and Rocky Mountain west will be 

significantly affected by the rule, including increased unemployment.

Response to Comment 75: The agency’s analysis as found in the RIA shows that the overall impact of 

the rule to be relatively small, in the context of the entire power sector. Although certain regions will 

need to do more in order to comply, those same regions will also benefit from the emission reductions. 
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Overall, coal use is not anticipated to be greatly impacted as coal-fired sources install pollution controls, 

with only modest amounts of retirements. Retail electricity prices are projected to increase slightly on 

average by 2015. Thus, there may be some negative impacts from this rule in these regions, but these 

same regions will also experience some of the benefits, such as reduced premature mortality from less 

exposure to PM2.5 emissions as shown in Appendix C of the RIA. In addition, the EPA has conducted an 

updated employment analysis which shows some potential positive and negative employment changes 

from the rule, but overall expects the employment impact to be relatively small in comparison to the 

affected sector and the overall economy.

Comment 76: Commenters 17901 and 18023 state that communities near existing coal-fired generation 

units will be especially hard-hit if the plants are permanently retired. The communities will suffer from 

job loss and diminished tax revenue.

Response to Comment 76: Although it is possible that there may be some negative local economic 

impacts associated with this rule, impacts such as retail electricity price increases should be modest. 

Also, the estimated number of early retirements according to the agency that may result from this rule is 

4.7 GW in 2015, or about 2% of all U.S. coal-fired capacity in that year. Overall, coal use is not 

anticipated to be greatly impacted as coal-fired sources install pollution controls, with only modest 

amounts of retirements. These results are presented in the RIA for the rule. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy. Although certain regions will need to do 

more in order to comply, those same regions will also benefit from the emission reductions such as

through reduced premature mortality from less exposure to PM2.5 emissions as shown in Appendix C of 

the RIA.

Comment 77: Several commenters (18422, 18433, 18575) request that the EPA reconsider the 

regulating of acid gases as they are not required and will impose greater cost and difficulty. The 

commenters ask that the rule be reevaluated to be more realistic and cost-effective.

Response to Comment 77: The agency believes the regulation of acid gases that are HAP is both 

required and appropriate under this rule. The preamble to this rule provides the rationale for this 

position.

Comment 78: Commenter 18447 disagrees with the EPA’s assessment that the reductions can be 

achieved without significantly affecting availability or cost of electricity and with an increase in jobs. 

The commenter expects job losses from the proposed rule and explains that the City of Ames, Iowa has 

one base load plant and two diesel combustion turbine “peakers” and cannot shift power away from 

older units to newer plants. The commenter explains that while switching to natural gas may seem like 

the preferred compliance option, there is not enough of a natural gas supply to support the needed 

generation. Also, the city’s power plant provides disposal for all municipal solid waste for the city and a 

neighboring town and the units would not be able to burn the refuse-derived fuel if it converted to 

natural gas. Thus, a fuel switch would lead to a dilemma for disposal of solid waste.

Response to Comment 78: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis indicates that coal will remain the largest 

source of electricity. The EPA will work with relevant authorities to ensure a smooth transition with this 

rule and address specific issues. Public utility commissions and other regulatory authorities have 

extensive experience with regulatory requirements and treatment of costs to consumers, and are prepared 
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for responding to the cost of future pollution control equipment or other response measures. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 79: Commenter 17648 offers projections showing that 2015 electricity prices in most areas 

will be the same or lower than they were in 2010 as a result of the proposed rule. The commenter

retained NorthBridge Group to estimate the potential rate impact resulting from the proposed rule on its 

customers in both the ComEd and PECO service territories. NorthBridge concluded that, based on 

current market conditions, generation rates in 2015 will be less than 2010 levels on an inflation-adjusted 

basis. NorthBridge reports that this finding is in partly due to the decline in natural gas prices in recent 

years. Exelon’s customers will benefit from lower gas prices, and this price decline will mitigate any 

potential rate increases related to the Toxics Rule. The results of NorthBridge’s analysis are set forth in

Figure 1 (See 17648-A2_Figure 1_ComEd and PECO Generation Rates.docx).

Response to Comment 79: The Commenter’s statements are not inconsistent with the results of EPA’s

analysis, which indicates that impacts on retail electricity and natural gas prices of the rule will be 

reasonable in light of the large benefits.

Comment 80: Commenter 17676 offers suggestions of things consumers and regulators can do to 

mitigate the impact of increasing electricity costs.

1. The commenter discusses the establishment of centralized entities that provide revenue for power 

plants to provide power to the grid when necessary, called “capacity markets.” The commenter

suggests that capacity markets need more oversight to ensure newer, more advanced facilities take 

precedence over less efficient plants because Synapse Energy Economics states that capacity

markets keep electricity prices high and less efficient plants operating.

2. The commenter also suggests pushing FERC to be more proactive about market violations by

encouraging competitive regional markets with balanced rules, monitoring such markets for 

anticompetitive behavior and enforce market rules.

3. The commenter also suggests better energy efficiency programs for domestic and imported electric 

products and better building codes to decrease energy demand can save consumers money and limit 

the amount of pollution released by EGUs.

Response to Comment 80: We thank the commenter for these suggestions. The agency has worked 

with FERC and other Federal agencies to examine ways of mitigating potential negative consequences 

associated with this rule. The EPA believes that there are many approaches that can help mitigate price 

increases, and is a strong supporter of energy efficiency measures. The EPA will work with relevant 

authorities to ensure a smooth transition with this rule and address specific issues. Public utility

commissions and other regulatory authorities have extensive experience with regulatory requirements

and treatment of costs to consumers, and are prepared for responding to the cost of future pollution 

control equipment or other response measures.

Comment 81: Several commenters (17682, 17884, 18033, 18484, 18023) consider the proposed rule to 

be a tax on the American public, since utilities implementing upgrades will pass the costs on to the 

consumer. Commenter 17682 questions the preference of Americans to subsidize renewable energy

sources and put money into the proposed rule instead of other environmental programs with greater 

benefits. Commenters 17884 and 18484 explain that the tax-like price increase reduces income of 

energy consumers and depresses business development. The commenters used California as an example 

of a state that uses low rates of coal-based electricity and cite companies that have left the state as a 
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result of substituting higher-cost forms of electricity for coal. Commenter 18033 states that coal-derived 

energy will rapidly become more expensive, especially in the “rust belt” and southeast region, as can be 

seen by the rate increase already requested in Louisville. Commenter 18023 believes the “indirect 

taxation” limits the ability of the economy to absorb the cost of retrofitting and new capacity projects, 

lowers discretionary spending lead to job losses and lost tax revenues, given the restrictive timeframe for 

compliance.

Response to Comment 81: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis indicates that coal will remain the largest 

source of electricity. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand and also 

manage the installation of pollution controls. Although electricity consumers will likely see a small price 

increase, it should be noted that these consumers will also experience the improvement in air quality

from the reductions due to the rule, and the benefits of this improvement will greatly exceed costs. The 

price increases in electricity and natural gas should be considered in light of the substantial benefits 

offered by this rule. In addition, history has shown that the impact of EPA regulations is much lower 

than anticipated, and predictions of severe economic impact have been often repeated, but not realized.

Comment 82: Commenters 16705 and 18038 believe the proposed rule will have a significant impact on 

jobs in their community and increase the electric rate, driving out businesses.

Response to Comment 82: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis indicates that coal will remain the largest 

source of electricity. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy.

Comment 83: Commenters 16856 and 18038 believe the proposed rule will severely impact the 

economy of the coal-producing states and utilities that provide almost 50% of their electricity from coal. 

Commenters ask that the EPA bring jobs back to the U.S. and stop sending manufacturing jobs to 

countries where environmental impacts are not considered.

Response to Comment 83: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis indicates that coal will remain the largest 

source of electricity. Industry has shown that it can install large amounts of pollution controls and often 

finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy.

Comment 84: Commenter 17627 considers the EPA’s RIA document to be lacking in local economic 

impacts associated with reduced operations or plant closures.

Response to Comment 84: The EPA has conducted detailed impact analysis of the rule, which includes 

regional information and impacts, and more detail can be found in the corresponding IPM output files 
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for the final rule, which has detail for the 32 power regions across the country. In addition, the EPA has 

conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy.

Comment 85: Commenter 17701 mentions that the proposed rule will have different reliability and cost 

effects on different regions of the country due to differing resources, transmission and capacity, market 

structures, approaches to energy efficiency, transmission options, electricity demand projections and 

consumer concerns.

Response to Comment 85: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The analysis provides a rich characterization of regional 

issues, and reflects the differences in the power sector composition across those regions. The impact of 

the rule will vary across regions, and the EPA has presented some of those impacts in the RIA.

Comment 86: Commenter 18030 quotes the NERA study could cost Michigan 40,000 jobs and increase 

electricity prices by 20.5% in 2016 and likely lead to the closing of numerous Michigan plants. The 

commenter requests the implementation of the proposed rule be suspended.

Response to Comment 86: The EPA has designed a rule that is intended to offer flexibility, to the 

extent possible, while ensuring public health is protected in accordance with requirements outlined in 

the CAA. History has shown that industry adapts to regulations and finds more cost-effective 

compliance approaches that the EPA can anticipate or predict, thus lowering the actual cost of its rule 

relative to what the EPA initially projected. The EPA has conducted detailed economic impacts analysis 

on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the 

overall benefits, and the industry has an excellent track record of installing pollution controls without 

greatly impacting electricity prices. The report cited by the commenter is not transparent with regards to 

several key criteria, and it is thus impossible to fully assess the credibility of the results. It has often 

been claimed that regulations do harm to the economy and jobs, but the evidence is weak or nonexistent, 

while there is a large body of literature that shows overall, the impacts of regulations on jobs and the 

economy is very small.

Comment 87: Several commenters (17705, 17732, 18540) discuss the unique situation of the Navajo 

Generating Station (NGS), which plays a key role in water delivery to Native American communities, 

farmers and cities in Arizona and which provides critical energy to the region. The plant also provides 

good jobs to 540 skilled workers and provides economic support for several communities through tax 

payments and other jobs. The plant also helps the U.S. meet its federal trust responsibilities under the 

2004 Arizona Water Settlements Act, and provides power and funding for the Central Arizona Project 

(CAP). The commenter states that the IPM model defines the plant as uneconomic to maintain, but given 

the importance of the facility, the owners want to work with the EPA to retain the plant. The commenter

believes the NGS should not have to install a baghouse to comply with the proposed rule and asks that 

the EPA evaluate all impacts of closure on the Navajo Nation on a regional economic basis, rather than 

on a Nation-wide basis. Commenter 18017 agrees with these comments and expresses concern about the 

closing of NGS affecting many entities, if sufficient time isn’t given for compliance. The commenter

details the difficulties to this region of Arizona would have in finding alternative power sources for 

electricity use and to pump water. The commenter estimates pumping costs could go up 50-300% by

2017. Commenter 18540 explains that it receives its entire water supply through the CAP system and is 

concerned with the effect of the proposed rule on the viability of the CAP. The commenter stresses the 

fact that the U.S. government owes a trust responsibility to commenter and other Indian tribes, including 
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water rights. The commenter explains that it gave up its right to assert water claims held from “time 

immemorial” in return for specific provisions by the U.S. government of water from the CAP and 

Yuma-Mesa Division of the Gila project. The commenter explains the various water settlement 

legislation in place and urges the EPA to carefully consider the possible effects of its proposed 

rulemaking on the continuing viability of the CAP system and requests that the EPA consult with it and 

other tribes that may be affected by the proposed rule, pursuant to the Agency’s May 2011 Consultation 

Policies.

Comment 88: Commenters 17732 and 18017 report that the power plant associated with the Navajo 

Nation (FCPP) employs nearly 600 people, most of them Navajo Nation members. The commenter goes 

on to explain that the Navajo Mine provided $69 million into the Navajo Nation’s revenue in 2007 and 

employs 427 people, 87% of whom are Navajo tribal members. The Peabody Kayenta Mine employs 

another 400 workers, many of whom are Native American. Revenue from the power plants and mines 

that supply them make up 1/3 of the general operating budget of the Navajo Nation, which employs

another 7,316 people, 98% of whom are Navajo. The Hopi tribe estimates that revenues derived from 

the plants and mines make up 88% of their tribe’s operating budget. Details of this revenue and 

supporting numbers may be found at: http://www.navajobusiness.com/pdflCEDS/CED NN

Final_09_10.pdf.

Comment 89: Commenter 17732 describes the impact of EPA regulation shutting down the Mohave 

Generating Station, which led to the closing of the Black Mesa Mine. The commenter explains that 160 

people were put out of work at the mine, and Navajo Nation’s general revenue was decreased by 30%. 

The commenter states that if the proposed regulations lead to a shutdown of the remaining two power 

plants due to cost-prohibitive emission controls, the mines supplying them would also close. These 

closures would lead to revenue and job losses so extreme they would impugn the solvency of the Navajo 

Nation government. The commenter states that the EPA failed to analyze the impacts to the Navajo 

Nation as part of the impact analysis. The commenter points out that unemployment is over 50% among 

the Navajo people, and no skilled labor force or industry exists in the pollution control technology field 

among their population. Therefore, the new jobs expected to be created by the proposed rule would not 

help the Navajo Nation, but the closing of the coal and power industry would lead to the loss of 31,000 

jobs. This would force migration of many workers, a “social cost” not analyzed by the EPA.

Comment 90: Commenter 19214 requests that the Table 8.8 showing that NGS will be likely to shut 

down by 2015 be changed to show continued operation of this important coal-fired plant. The owners 

acknowledge that the rule will be challenging, but are committed to working with the EPA to keep this 

critical resource open.

Response to Comments 87 - 90: The EPA modeling and projections are intended to be a reflection of 

possible compliance using specific tools, assumptions, and methodologies that the agency believes to 

reflect the best and most current information related to the power sector. It is not intended to reflect 

actual compliance decisions, since those will be made individually be the affected industry based on 

what makes most sense using existing technologies or other, more cost-effective strategies. The EPA 

will work with relevant authorities to ensure a smooth transition with this rule and address specific 

issues as they arise. Public utility commissions and other authorities, such as tribes, will need to develop 

and implement compliance plans in order to address harmful emissions. In addition, there are certain 

provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).
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Comment 91: Commenters 17807 and 17901 expresses concern about economic impacts to residential 

and commercial customers, particularly minorities, the elderly and economically disadvantaged 

customers.

Response to Comment 91: The EPA has conducted detailed impact analysis of the rule, which shows 

reasonable impacts to retail electricity prices. The average impact on household energy expenditures 

(electricity and gas) is anticipated to be less than $3 per month.

Comment 92: Commenter 17813 questions the results of the IPM model because it shows a heat input 

of 25.353 TBtu for their facility, while average from 2006-2010 is 35.285 TBtu. Because of this 

discrepancy, the commenter questions the assumption that the plant will retire.

Response to Comment 92: The EPA modeling and projections are intended to be a reflection of 

possible compliance using specific tools, assumptions, and methodologies that the Agency believes to 

reflect the best and most current information related to the power sector. It is not intended to reflect 

actual compliance or retirement decisions, since those will be made individually be the affected industry

based on what makes most sense using existing technologies or other, more cost-effective strategies.

Comment 93: Commenter 17815 reports that in 2010, coal-fueled generation provided approximately

40% of electricity in the Electric Reliability Council of Texas region and provided over 33,000 

permanent jobs as well as $10 billion in annual expenditures. The commenter says that the average 

income for a lignite mining employee in Texas is 2.14 times the state average income for all industries 

and has a tax contribution of $1.012 billion.

Response to Comment 93: The EPA has conducted detailed impact analysis of the rule, which provides 

a rich characterization of regional issues, and reflects the differences in the power sector composition 

across those regions. The impact of the rule will vary across regions, and the EPA has presented some of 

those impacts in the RIA. Overall, coal-fired generation is not expected to change significantly since 

sources are anticipated to install pollution controls. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy

Comment 94: Commenter 17901 questions the benefits of the proposed rule in the face of job losses 

likely to hit coal-producing regions especially hard. Commenter 18500 agrees and points out that some 

regions will see almost no impact from the rules, such as the Pacific northwest while the midwest and 

other regions will face large cost increases.

Response to Comment 94: The EPA has conducted detailed impact analysis of the rule, which provides 

a rich characterization of regional issues, and reflects the differences in the power sector composition 

across those regions. The impact of the rule will vary across regions, and the EPA has presented some of 

those impacts in the RIA. Overall, coal-fired generation is not expected to change significantly since 

sources are anticipated to install pollution controls. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy.
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Comment 95: Commenter 18430 cites a Unions for Jobs and the Environment (UJAE) study that 

estimated job losses due to the proposed rule to be over 250,000, with more than 11,000 in Virginia. The 

commenter states that the importance of the coal industry to Virginia makes that state especially painful.

Response to Comment 95: The EPA has conducted detailed impact analysis of the rule, which provides 

a rich characterization of regional issues, and reflects the differences in the power sector composition 

across those regions. The impact of the rule will vary across regions, and the EPA has presented some of 

those impacts in the RIA. Overall, coal-fired generation is not expected to change significantly since 

sources are anticipated to install pollution controls. In addition, the EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy.

Comment 96: Commenter 18477 believes that non-continental oil-fired EGUs should have a separate 

regulatory impact analysis. The commenter explains that non-continental utilities have fewer economic 

resources available to address proposed rule requirements and as regulated utilities they must obtain 

approval for rate increases to offset costs. Since non-continental electricity prices are already higher than 

on the continental U.S. the economic consequences associated with compliance are also higher.

Commenter 17760 states that the EPA should conduct a separate RIA for non-continental oil-fired 

EGUs. According to the commenter, in March 2011, the EPA released the RIA of the Proposed Toxics 

Rule: Final Report. The commenter states that the RIA utilized an Integrated Planning Model (“IPM”) to 

predict the costs associated with the proposed rule, as well as its effect on the economy and public 

health. The commenter asserts that the RIA only addressed coal-fired EGUs; the EPA stated that it 

would address regulatory impacts related to liquid oil-fired units in the final rule. Of the 154 oil-fired 

EGUs identified in the proposed rule, 31 of the units are located on the islands of Oahu, Puerto Rico, 

and Guam. The commenter states that since the EPA intends to analyze regulatory impacts related to oilfired units as part of the final rulemaking, the EPA should address non-continental liquid oil-fired units 

separately in that analysis.

Response to Comment 96: The final rule contains provisions that are specific to non-continental EGUs. 

See preamble for further discussion of the treatment of these sources.

3. Retiring coal-fired EGUs, shutdowns.

Comment 97: Commenter 17403 says that capital that will be deployed by EGU owners to implement 

emissions control measures under the proposed rule should create well-paying jobs for skilled workers 

across the country. However, the commenter goes on to say that premature shutdown of existing coalfired EGUs will also result in an estimated 50,000 direct job losses in the coal, utility and rail industries 

with a total job loss including indirect jobs of 251,300. The commenter considers the costs and benefit 

analyses of the proposed rule to be incomplete and misleading and the proposed rule structured to avoid 

unnecessarily eliminating jobs.

Response to Comment 97: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet). In addition, the EPA has conducted an updated employment analysis 

which shows some potential positive and negative employment changes from the rule, but overall 

expects the employment impact to be relatively small in comparison to the affected sector and the 

overall economy. 
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Comment 98: Multiple commenters (17623, 17656, 17834, 17868, 17930, 18018, 18497, 18023) 

discussed predictions for the number of coal-fired EGUs that are likely to retire as a result of the 

proposed rule and Transport rule. Several commenters (17623, 17868, 18497, 18023) cite and provide 

references to seven studies predicting retirements of 5 to 65 GW in 2015, where six of the seven predict 

retirements of 35 GW or more. Commenter 17656 estimates that the proposed rule, when viewed in 

conjunction with the entire body of new regulatory initiatives on the utility fleet, will impact roughly 

400,000 MW of oil- or coal-fired generation, or 40% of the current available capacity in the U.S. This 

commenter quotes NERC which predicts the rules could jeopardize 30 to 70 GW of generating capacity

by 2015. Commenter 17834 predicts the early closure of many facilities as a result of the proposed rule 

and reports that these EGUs play a central role in a region’s economy since they are a source of jobs and 

contribute to the tax base. Commenter 17868 believes that the EPA has grossly underestimated the 

number of coal-fired generation retirements at only 9.9 GW, which is only 3% of all coal-fired capacity

by the year 2015. The commenter believes that the EPA chose to view the proposed EGU NESHAP in 

isolation and not in the CSPAR (the replacement of the Regional Transport Rule). Many published 

studies project retirements above 40 GW, when viewed in combination and under certain circumstances.

Commenter 18023 also quotes the NERC report and discusses the resulting problems from the predicted 

shut downs, which include adverse impacts of displacing coal-fired generation with other forms that do 

not provide the same kinds of grid support functionality, increased interconnection of variable energy

sources such as solar and wind. The problem of grid operators being unable to know the locations and 

parameters of generator locations in enough time to facilitate transmission facilities is also mentioned, 

and Commenter 18023 requests a thorough reliability analysis given the compliance framework and 

timeline of the proposed rule.

Response to Comment 98: The agency prepared a reliability analysis for the proposed rule and has 

revised that analysis for the final rule. The agency is working with FERC regarding the reliability

impacts of this rule. The EPA estimates 4.7 GW of capacity will retire early as a result of this rule. We 

have not prepared a cumulative impacts analysis for the various power sector rules that have been 

finalized or are in process of being finalized because the agency does not believe such an analysis would 

be as accurate and transparent as analyses for each of these individual rules. The EPA has outlined the 

various flexibilities associated with the rule, and the approaches to reliability issues in the preamble.

Comment 99: Commenter 17648 discusses the economic factors behind EGU retirements. These factors 

include the cost of alternative generation using natural gas, the cost of implementing demand response 

measures that can be bid into capacity markets, and the cost of continuing to generate power from an 

existing unit. The commenter states that regardless of the costs associated with the Toxics Rule and 

other EPA electric power industry regulations, some power plants were already economically 

unsustainable. The commenter quotes M.J. Bradley, who points out, “Of the 122 coal units in PJM with 

capacity less than or equal to 200 MW, 35 failed to recover their avoidable costs and another 52 were 

close to not recovering those costs. Therefore, in PJM . . . in addition to approximately 10 GW of coal 

generation that has or will be retired during the seven years from 2004 to 2011, another 11 GW faces a 

troubling economic outlook.” The commenter provides confirmation of this by the most recent PJM 

capacity auction, where approximately 6.9 fewer GW of coal-fired capacity cleared the auction (1.85 

fewer GW were offered) as compared with the prior year’s auction, and an additional 4.836 GW of new 

demand response (energy efficiency) resources cleared the auction. Thus, the commenter states, some 

claims linking retirements to the Toxics Rule are overstated and misleading. The commenter gives the 

example of the American Electric Power attempt to link its planned plant closures to the Toxics Rule, 

but those plants already are slated to either close or to upgrade controls to comply with existing laws. 

The commenter goes on to quote three independent studies that support the finding that over 50% of the 
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fleet is equipped with scrubbers and the number will increase to nearly 2/3 by 2015. (Footnotes in 

comment provide references to the studies and further quotes.)

Response to Comment 99: As discussed elsewhere in this document and in the preamble to this rule,

the EPA believes there will be modest levels of coal retirements, and many units slated for retirement 

are being taken offline for other reasons aside from requirements to reduce emissions.

Comment 100: Commenters 17812 and 17736 believe the proposed rule will adversely affect the costeffective operation of industry energy operations and quote the U.S. Chamber of Commerce testimony

before Congress: “American Electric Power Co. made headlines last month when it disclosed that EPA’s 

“train wreck: of coal regulations – Coal Ash, Utility MACT, the Transport Rule and Cooling Water 

Intake Structures – would force the utility to retire 6,000 megawatts of coal-fired generating capacity 

and spend another $6 billion to $8 billion reworking the rest of its fleet.” AEP would close three power 

plants in West Virginia, one in Ohio and one in Virginia, and would retire several boilers at coal plants 

in Indiana, Kentucky, Ohio, Texas and Virginia.

AEP is not alone. Six other power plants have announced early retirement due to excessive regulation: 

Portland Gas & Electric’s Boardman coal-fired power plant in Oregon; Exelon Corporation’s Oyster 

Creek Nuclear Generating Station in New Jersey; TransAlta Corporation’s Centralia coal-fired power 

plant in Washington; and, just this week, three Georgia Power plants in the next 2 years. In each case, 

the utility was forced to choose between installing several hundred million dollars’ worth of pollution 

controls to comply with the EPA regulations, or simply shut down early. In all cases, the utility chose 

early retirement.”

Commenter 17812 also expresses concern that increasing energy costs will reduce the ability of U.S. 

industry to compete in the global marketplace, expand in the U.S., create jobs and increase contribution 

to the GDP. The commenter quoted the 2010 EIA outlook which showed a 9.1% decline in industrial 

electricity demand, the lowest since 1987.

Response to Comment 100: As discussed elsewhere in this document and in the preamble to this rule, 

the EPA believes there will be modest levels of coal retirements, and many units slated for retirement 

are being taken offline for other reasons aside from requirements to reduce emissions.

Comment 101: Several commenters (17682, 17813, 17904, 17930) mention the proposed rule’s impact 

on mining. Commenter 17682 mentions increasing energy costs for the U.S. mining industry resulting in 

fewer projects and associated jobs, as well as increasing dependence on foreign mineral resources. 

Commenters 17904 and 17930 see mining impacts being disproportionally large for lignite mines, which 

are dependent on their co-located lignite-fired power plants. Commenters state that if the plant closes, 

there is no market for the lignite and the mine will also close, displacing plant workers. These impacts 

are largest in Texas, the largest coal consuming state and fifth largest coal producing state, as well as a 

deregulated electricity market. Commenter 17904 points out that the Texas coal market provided a 

buffer against natural gas price volatility and in particular believes the proposed rule does not take into 

account the emission reductions already achieved by industry in general and their company in particular. 

Commenter 17813 states that impacts will be magnified in Texas, since it is the largest coal consuming 

state and mines lignite. Commenter 17813 also states it is unclear the extent to which the EPA includes 

the impacts on the mining industry that will result from this rule.

Response to Comment 101: The agency presents impacts on the coal mining sector from this rule in the 

RIA. Given the modest increase in coal and other energy costs associated with the rule, the agency does 
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not expect widespread impacts on coal mining. The agency’s modeling accounts for all emission 

controls and programs installed and/or implemented up through December 2010. The EPA analysis 

indicates that there will be a small amount of coal retirements (2% of the coal fleet). In addition, the 

EPA has conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy.

Comment 102: Commenter 18500 states that the EPA has justified the regulation of EGUs based, in 

part, on the fact that such regulation will make the market for electricity more level and less skewed 

toward polluting units. Although there is no legal basis to justify regulation on market parity, the EPA 

must recognize that by changing market dynamics in single clearing price markets, every incremental 

increase in price applies to all electricity sold in that market, not just to the impacted unit. Given that 

half of the American population lives in Regional Transmission Organizations (RTOs) where 

incremental cost increases apply to all energy costs, this will be a significant factor. The EPA has failed 

to account for the impact these rules will have on the total cost of energy across RTO markets where 

every incremental increase in price applies to all electricity sold in that market, not just to the impacted 

unit, while at the same time asserting beneficial market impacts.

Commenter 17868 asks that the EPA address the unproductive costs of compliance that occur due to 

RTO market structures, since the rule is expected to lead to plant closures of plants dispatched to meet 

demand. As a result, power generated by plants not facing greater compliance costs will still be sold at a 

price reflecting the costs to other plants. This occurs because the highest offer accepted in an hour sets 

the price for all megawatt-hours consumed, a single coal or natural gas plant can affect the prices paid 

for by all the electricity generated by nuclear, hydropower, wind, and all other plants within that hour. 

The commenter believes this market structure will lead to costs beyond that of compliance being passed 

on to consumers and gives the following example: “in the most recent Reliability Pricing Model (or 

RPM) auction, held in May 2011 to procure capacity for the June 2014 through May 2015 time period, a 

number of plants added to their supply offers the costs associated with installation of emission control 

technologies to meet environmental regulations. PJM estimated that these higher costs were responsible 

for at least half of the 350% price increase between the past two auctions in the western region of PJM, 

from $27.73 per MW/day to $125.99 per MW/day. Although the number of units or MWs that included 

these compliance costs is not yet available, PJM’s graphical representation shows that of the roughly

150,000 MW that cleared the auction and will receive this capacity price, about 120,000 MW offered to 

sell capacity at a zero or close to zero price. (Zero price offers are typically submitted by existing base 

load plants who are price takers in the auction.) Therefore the half of the $98 price increase attributable 

to environmental upgrades will be paid to all 120,000 MWs of capacity that did not include 

environmental compliance costs in their offers, equal to an unproductive cost of at least $2.1 billion for 

just one year...These factual PJM auction results from May 2011 demonstrate that the U.S. EPA’s 

assertion that the electricity consumer will see no more than a 3.6% increase in the cost of electricity 

does not match recent actual market performance. The U. S. Census reports that currently there are 

307,006,550 people in the U.S. and approximately 51 million of them live in the PJM Market. This 

means that approximately 15% of the U.S. population is affected by PJM Market” The commenter

provides figures showing how coal plant closures will impact different locations. (EPA-HQ-OAR-2009-

0234-17868-A2)

Response to Comment 102: The EPA provides regional estimates of the projected retail electricity

price impacts of the rule, and the impacts vary across regions for a variety of reasons (market structure 

being one of them). In addition, the auction results cited are not a reflection of retail price impacts, 

which will be dampened since the cost of generation is just one of several components of retail prices. 
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The auction also resulted in significant new capacity and additional demand-side resources, which show 

that there are multiple avenues for how utilities can respond to the requirements of this rule. The auction 

also indicates that there will be adequate reserve margin. The most important point that the commenter 

ignores is the baseline. The EPA assesses the impacts of its rules not in relation to what is happening 

today or from the 2013/2014 PJM auction, but in relation to what would have happened in the absence 

of this rule in the same year (in 2015 for MATS). The commenter is unable to fully ascertain, based on 

the analysis presented, the incremental effect of the rule alone and is lumping in other important 

industry trends and dynamics that will impact future prices. The EPA has updated its analysis of price 

impacts of MATS, which are presented in the RIA on a regional and nationwide basis.

Comment 103: Commenter 18497 explains that the EPA’s retirement estimate is very low and cites 

several studies of regional retirements. The commenter reports that in the East North Central U.S. 

Census Region alone (includes the states of Indiana, Illinois, Michigan, Ohio, and Wisconsin), ICF 

identified 25 GW of at-risk capacity- more than in all other census regions combined and over two times 

the next most impacted region (East South Central - 11 GW). The Brattle Group analysis estimated 50-

65 GW of coal-unit retirements nationwide by 2020 based on the need to install scrubbers and SCR 

controls. Of that total, 12-15 GW were located in the Midwest Independent Transmission System 

Operator (MISO) regional transmission organization (RTO), and 8-15 GW were located in the PJM 

Interconnection (PJM). The commenter references the DOE deputy assistant secretary for clean coal, 

James F. Wood who states, “Number one, electric rates are going to go up. Number two, whether or not 

construction jobs in the green industry are created, I think there’s [sic] virtually no manufacturing jobs 

that are likely to be created from the replacement of coal. Three ... transmission grid stability is likely to 

emerge as a major issue, both because of the shutdowns and because of the intermittency of 

renewables.” He also pointed out the sizable impact shutting down one power plant could have on the 

local community. The commenter also quotes the Credit Suisse analyses showing around 60 GW of coal 

closed in 2013-2017 and 100 GW requiring large investments to comply at a cost of $70-100 billion to 

cover compliance or replacement expenses. The commenter also quoted the Berstein report which 

projected 54 GW of coal retirements and a 1.2 Tcf increase in annual natural gas demand, leading to 

increased prices as much as $92/MW a day.

Response to Comment 103: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) as a result of this rule. Most studies use flawed assumptions and do not 

fully reflect the rule, including some important areas of flexibility. The analyses also conflate other 

issues, like natural gas prices and low electricity demand, and do not isolate the effect of this rule 

separately. The EPA believes there will be modest levels of coal retirements, and many units slated for 

retirement are being taken offline for other reasons aside from requirements to reduce emissions. The 

impact of the rule will vary across regions, and the EPA has presented some of those impacts in the RIA. 

Overall, coal-fired generation is not expected to change significantly since sources are anticipated to 

install pollution controls. The EPA will work with relevant authorities to ensure a smooth transition with 

this rule and address specific issues. Public utility commissions and other regulatory authorities have 

extensive experience with regulatory requirements and treatment of costs to consumers, and are prepared 

for responding to the cost of future pollution control equipment or other response measures. In addition, 

the EPA has conducted an updated employment analysis which shows some potential positive and 

negative employment changes from the rule, but overall expects the employment impact to be relatively

small in comparison to the affected sector and the overall economy.

Comment 104: Commenter 16469 states that the coal units more likely to retire due to the proposed rule 

are over 40 years old, under 400 MW and are cycling or “load-following” units for which the costs 
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associated with additional controls would be too high for the infrequently run units to recoup. The 

commenter expects combined cycle natural gas units to pick up the share of generation for these units.

Response to Comment 104: The EPA agrees with the commenter.

Comment 105: Commenter 17881 explains the process by which the regulated utility created a Strategic 

Plan with the state and the EPA which commits them to a $1.6 billion upgrade through the year 2018. 

The commenter reports that they now find themselves in a position where they will need to retire a 

significant percentage of their coal-fired fleet in response to the proposed rule.

Response to Comment 105: Industry has shown that it can install large amounts of pollution controls 

and often finds more cost-effective compliance options than the EPA can anticipate. In addition, the 

EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve 

load, and industry has also shown that it can build new capacity quickly in response to demand. The 

EPA will work with relevant authorities to ensure a smooth transition with this rule. In addition, there 

are certain provisions for granting utilities some additional time to comply, if conditions warrant (see 

preamble).

Comment 106: Commenter 16849 reports that they plan to convert a Riverton, Kansas plant to use 

natural gas, rather than retiring it, as predicted in the “IPM Parsed Results Policy Case.”

Response to Comment 106: The EPA modeling and projections are intended to be a reflection of 

possible compliance using specific tools, assumptions, and methodologies that the agency believes to 

reflect the best and most current information related to the power sector. It is not intended to reflect 

actual compliance decisions, since those will be made individually by the affected industry based on 

what makes the most sense to them using existing technologies or other, more cost-effective strategies. 

Comment 107: Commenter 17403 believes the EPA has not adequately assessed the costs associated 

with the retirement of smaller units, just as job losses and employment shifts as workers are retrained 

and re-employed elsewhere.

Response to Comment 107: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 108: Commenters 17901 and 19742 believe the proposed rule and other federal rulemakings 

will force the premature shutdown of many coal-fired power units, resulting in the loss of thousands of 

jobs in utilities, coal, manufacturing and transportation. Commenter 17901 notes that states such as Ohio 

that rely on eastern bituminous coal will be especially hard-hit.

Response to Comment 108: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) resulting from this rule and coal-fired generation will not change 

significantly. The EPA questions whether any units will be retired “prematurely,” noting that any 

retirements likely to result from the rule will be of the oldest units that owners find least economically

viable to control. In addition, the EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.
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Comment 109: Commenter 17931 disagrees with the EPA’s conclusion that few coal-fired units will 

retire in response to the proposed rule because they state that DSI use will not provide the expected 

compliance.

Response to Comment 109: There are many compliance options, and each affected source will choose 

the most effective strategy to meet the requirements of the rule. The EPA is not prescribing particular 

technologies, and industry has a successful track record of responding to air reduction programs through 

innovation, often a cost much less than what the EPA originally anticipated.

Comment 110: Commenter 16850 notes that significant controls would be necessary at many of 

Florida’s coal- and oil-fired generating units, and some units would be at risk of retirement. 

Commenter 16850 states that the EPA’s final rules should avoid compromising electric system 

reliability and allow the maximum compliance flexibility for electric utilities provided for under the 

Clean Air Act.

Response to Comment 110: As stated above, there are many compliance options, and each affected 

source will choose the most effective strategy to meet the requirements of the rule. The agency prepared 

a reliability analysis for the proposed rule and has revised that analysis for the final rule. The agency is 

working with FERC regarding the reliability impacts of this rule. The EPA has outlined the various 

flexibilities associated with the rule, and the approaches to reliability issues in the preamble. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 111: Commenter 18016 predicts an 8% decrease in coal production in Alabama as a result of 

the proposed rule, exacerbating economic problems there. Another concern to the commenter is the cost 

increases and capacity shortfalls resulting from the expedited shutdown of tens of thousands of 

megawatts of existing coal-fired generating capacity.

Response to Comment 111: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) and coal-fired generation will not change significantly. The agency has 

also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence 

that will help serve load. In addition, the EPA has conducted an updated employment analysis which 

shows some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

In addition, there are certain provisions for granting utilities some additional time to comply, if 

conditions warrant (see preamble).

Comment 112: Commenter 18424 states that according to a study by UJAE, more than 60% of coal 

shipments in Indiana would not be able to comply with that limit when burned in units controlled by 

scrubbers operating at 95% SO2 removal efficiency. If sources cannot comply with the proposed limits 

using bituminous coals, they will not use those fuels or they will retire the units.

Response to Comment 112: The EPA disagrees with the comment. Since scrubbers effectively capture 

MATS acid gases more efficiently than SO2, units equipped with this control device operating at 95% 

SO2 removal efficiency are expected to suffice.83 For those scrubbers operating below 95% SO2 capture, 

 

83 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” by

Lipinski, Leonard, Richardson; published by URS; April 5, 2011
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controls upgrades are available to improve performance.84 Potential impacts to coal supply are discussed 

in the preamble for the final rule and in the RIA.

Comment 113: Commenter 17852 asserts that the proposed rule can and should promote the orderly 

retirement of old, high-emitting power plants. It is widely recognized that the current fleet of coal-fired 

power plants includes many old, uncontrolled, inefficient units that lack up-to-date and effective 

controls for hazardous emissions. Many of these units are slated to retire. In fact, over 20 GW of coalfired generation have been recently announced for retirement. However, current regulatory provisions do 

not always sufficiently promote utility planning for these retirements, causing some in the utility sector 

to delay action and then raise concerns regarding perceived threats to electric system reliability that 

would not otherwise exist if more advance planning had been done. In the proposed rule, the EPA 

recognized that “Although most RTOs/ISOs only require 90-day notifications for retirements, 

construction schedules for all but the simplest retrofits will be longer, so sources should be able to notify 

their RTOs of their retirements earlier.” To provide an incentive for early planning, the EPA said that it 

“encourages state environmental regulators to consider the extent to which a utility engages in early 

planning when making a decision regarding granting a 4th year for compliance” with the Utility MACT. 

The commenter supports the EPA’s approach of encouraging utilities to engage in early planning and to 

timely announce the retirements of the oldest and highest-emitting power plants in the fleet. 

Notifications of only 90 days are clearly inadequate, and waiting so long maximizes the chance that 

reliability issues may occur, rather than minimizing it.

Response to Comment 113: The purpose of today’s rule is to establish standards to reduce emissions of 

harmful pollutants in compliance with the requirements of the CAA, not to retire any particular power 

plants. The EPA continues to encourage utilities to engage in early planning when considering how to 

respond to the new regulations – whether to comply or to retire the EGU – and appreciates the 

commenter’s support.

4. Flexible regulations.

Comment 114: Several commenters (17004, 17022, 17026, 17028) consider the purchase of electricity

to be a major cost of doing business and question the wisdom of imposing a higher cost on businesses 

through regulatory inflexibility or needlessly short deadlines. These commenters, along with commenter

17887, urge the EPA to consider developing energy policies that will allow businesses to expand and 

generate jobs by deferring or mitigating price increases through adopting more flexible regulations.

Response to Comment 114: The agency recognizes that electricity cost can be an important cost of 

doing business for many manufacturers. As such, it has attempted to provide the greatest degree of 

flexibility permitted by law. However, the agency is under a court-ordered deadline reflected in a 

Consent Decree that requires that a MACT standard be issued along with a revision to the current NSPS. 

Implementation deadlines in the final rule are in response to the underlying requirements of the CAA, 

and any flexibility that the agency can offer must be consistent with the CAA.

Comment 115: Commenter 17692 expresses concern that the proposed rule will increase electricity 

costs in Louisiana, where businesses depend on adequate and affordable electricity and domestic 

productivity could be depressed. The commenter believes the impacts of the proposed rule could be 

much less if the EPA were less strident and more flexible in the rule requirements.

 

84 Ibid.
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Response to Comment 115: The agency’s analysis finds that the national average retail electricity price 

increase is expected to be 3.1% in 2015. This increase should be understood in the light of the extensive 

benefits from HAP and non-HAP emission reductions expected from this rule. The EPA has attempted 

to provide the greatest degree of flexibility permitted by law.

Comment 116: Several commenters (17707, 17824, 18419) state that Alabama uses coal to supply

nearly 60% of electricity needs and employs 1500 workers to run the coal-fired power plants. 

Commenters worry the proposed rule will jeopardize efforts to increase economic growth and job 

opportunities in the state. The commenter urges the EPA to adopt more flexible standards and timelines 

to achieve affordable utility bills, stable jobs and reliable power. Commenters 17824 and 18419 state 

that Alabama Power has spent $2.6 billion to install technologies to reduce emissions from coal-fired 

units and succeeded in dropping NOX and SO2 emissions by 65% since 1996. Commenters consider the 

proposed rule to be unreasonable and unfounded, with the cost vastly outweighing the benefits.

Response to Comment 116: The agency’s analysis shows that the national average retail electricity 

price is projected to increase by 3.1% in 2015. The EPA has attempted to provide the greatest degree of 

flexibility permitted by law. The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) and coal-fired generation will not change significantly. The agency has 

also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence 

that will help serve load. In addition, the EPA has conducted an updated employment analysis which 

shows some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

In addition, there are certain provisions for granting utilities some additional time to comply, if 

conditions warrant (see preamble).

Comment 117: Commenter 17648 observes that “the positive economic impacts of the proposed Toxics 

Rule strongly militate in favor of its adoption. Contrary to the unfounded assertions by critics of the 

EPA and the rule, the EPA has conducted a technically sound and conservative benefit-cost analysis 

showing that the proposed rule’s benefits are at least five times as high as its costs. With sound, albeit 

unduly conservative, econometric modeling, the EPA has also determined that the Toxics Rule will 

promote economic growth and create jobs in both the long and short term.” This commenter and 

commenter 18432 cite the EPA impact analyses by Dr. Charles Cicchetti which confirms this finding 

and state that the analysis underestimates the Rule’s net benefits and positive impacts on the nation’s 

economy. By considering some benefits not monetized in the EPA analysis, Dr. Cicchetti concludes that 

the proposed rule will create $52.5 to $139.5 billion in net benefits annually, create 115,200 jobs, 

generate annual health savings of $4.513 billion, annual increases in GDP of $7.17 billion and $2.689 

billion in additional annual tax revenues, and spur innovation and modernization of EGUs. The 

commenter states that the study findings show no need to delay implementation of the rule or needlessly

duplicate economic analyses already completed.

Comment 118: Commenter 17648 reports that multiple researchers confirmed that the EPA’s estimates 

of economic stimulus are conservative and that the proposed rule will stimulate job growth. The 

commenter quotes Dr. Josh Bivens of the Economic Policy Institute, who also found that EPA’s 

conclusions were conservative. Dr. Bivens concluded, “The EPA RIA on the proposed toxics rule makes 

a compelling case that the rule passes any reasonable cost-benefit analysis with flying colors—the 

monetized benefits of longer lives, better health, and greater productivity dwarf the projected costs of 

compliance. . . . Whether regulation in general and the toxics rule in particular costs jobs is an empirical 

question this paper attempts to answer. In particular, this paper examines the possible channels through 

which the proposed toxics rule could affect employment in the United States and finds that claims that 
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this regulation destroys jobs are flat wrong: The jobs-impact of the rule will be modest, but it will be 

positive.” His report details the following major findings:

1. The proposed rule would have a modest positive net impact on overall employment, likely leading to 

the creation of 28,000 to 158,000 jobs between now and 2015.

2. The employment effect of the [Toxics Rule] on the utility industry itself could range from 17,000 

jobs lost to 35,000 jobs gained.

3. The proposed rule would create between 81,000 and 101,000 jobs in the pollution abatement and 

control industry (which includes suppliers such as steelmakers).

4. Between 31,000 and 46,000 jobs would be lost due to higher energy prices leading to reductions in 

output.

5. Assuming a re-spending multiplier of 0.5, and since the net impact of the above impacts is positive, 

another 9,000 to 53,000 jobs would be created through re-spending.

Commenters 17648 and 18961 also provide information from The University of Massachusetts Political 

Economy Research Institute, which prepared a February 2011 study of the jobs impacts of the proposed 

rule and the Transport rule. Based on estimates that the power sector will invest almost $200 billion total 

in capital improvements between 2010 and 2015 in these 36 states, the researchers found that the total 

employment created by these capital investments is estimated at 1.46 million jobs, or about 290,000 jobs 

on average in each of those years.

Response to Comments 117 - 118: The EPA has conducted an updated employment analysis using the 

approach applied for the proposed rule which shows some potential positive and negative employment 

changes from the rule, but overall expects the employment impact to be relatively small in comparison 

to the affected sector and the overall economy. It should be noted that the agency’s employment impact 

analysis is focused on short-term estimates of impacts from installation and operation of new pollution 

control equipment, and long-term estimates of impacts for the regulated industry (electric power 

generation). Our rationale for the analysis and the analysis itself are in the RIA for the rule.

Comment 119: Commenter 18419 asks the EPA to perform a true economic analysis, evaluate the 

proposed rule with other new and pending regulations and provide more flexible standards and 

reasonable compliance guidelines.

Response to Comment 119: The EPA has attempted to provide the greatest degree of flexibility in the 

rule that is permitted by law.The agency’s economic analysis is consistent with the guidelines provided 

by OMB for rules such as this one that are economically significant under EO 12866, an Executive 

Order issued by OMB in 1993. The agency did not prepare a cumulative impact analysis to accompany

the rule for the following reasons: 1) the various EO requirements that the agency must comply with 

require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the 

impacts specific to a particular rule in order to judge the merits of the regulation; 3) estimates specific to 

a particular rule are more transparent than those from a cumulative impact analysis. A cumulative 

impact analysis lumps several regulations together and can potentially mask a high-cost/low-benefit 

regulation among other rules that may have large net benefits. By analyzing each regulation separately, 

the EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of 

this particular regulation. 

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 
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apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

5. Job analysis: temporary versus permanent jobs.

Comment 120: Commenters 17811 and 18436 believe that installation of new pollution controls would 

be a job-growth opportunity in Alabama because money spent on controls for power plants creates highquality jobs in steel, cement and other materials, as well as in the assembling of the equipment as well as 

installing and operating it. Commenter 18436 shares the Alabama Fisheries Association estimate that the 

water-based recreation industry brings in over $1 billion per year to the state’s economy though the state 

ranks third for imperiled fish with 61 bodies of water cited for Hg contamination. The commenter

believes the HAP accumulating in the waterways threaten the industry with permanent job-losses and 

lost revenue.

Response to Comment 120: The EPA finds commenters’ economic predictions and statements of 

benefits to be reasonable. The EPA has conducted an updated employment analysis which shows some 

potential positive and negative employment changes from the rule, but overall expects the employment 

impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 121: Commenters 17834 and 18033 disagree with the EPA speculation that job losses will be 

offset by increasing jobs in air pollution technology production. Commenters believe the proposed rule 

will decrease job creation and sees no assurance or conclusive data that jobs will be created. 

Commenters go on to request that the EPA withdraw the proposed rule, citing an unstable regulatory 

climate and unclear economic impacts. Commenter 18033 quotes economist David Montgomery’s 

testimony before Congress in which he said that “Claims that regulations that raise the cost of doing 

business will create new jobs are, at best, a sideshow. Such claims only distract attention from the 

difficult tradeoffs that must be made between costs and benefits. “Green jobs” is not a subject that 

leading economists have usually taken seriously enough in professional journals. Based on the 

foregoing, it is difficult for EPA to legitimately claim that the proposed rule’s benefits analysis is 

accurate.”

Response to Comment 121: The EPA does not have the flexibility to withdraw or delay the rule, which 

is governed by a consent decree and the requirements of the CAA. The EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 
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rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy. All of these analyses are found in the RIAs for the respective rules.

Comment 122: Commenter 17930 disagrees with the EPA’s prediction of an annual cost of $10.9 

billion by 2015 and estimates it to be up to $100 billion annually. The commenter also disagrees with 

the EPA prediction of new jobs created, because the commenter believes far more plants will shut down 

than the EPA predicts, resulting in higher job losses. The commenter points out that while jobs running 

power plants are permanent, the jobs predicted to be created by the proposed rule are short term 

construction jobs, and will all occur in the same short timeframe for compliance. Further, the commenter

states that the EPA estimate does not include the opportunity cost of lost construction jobs due to new 

power plants that will not be constructed due to the proposed rules.

Response to Comment 122: The EPA has conducted extensive analysis of the rule, which can be found 

in the RIA. The cost analysis by the agency is based on a peer-reviewed power sector model that has 

been used in multiple rulemakings affecting the electric power sector over the past 15 years. The EPA 

has also conducted an updated employment analysis which shows some potential positive and negative 

employment changes from the rule, but overall expects the employment impact to be relatively small in 

comparison to the affected sector and the overall economy. Overall impact on retail electricity prices 

nationwide is also anticipated to be modest in light of the significant benefits of the rule. The EPA 

cannot evaluate the basis for commenter’s claim of higher impacts, but on the basis of its own detailed 

analysis does not find it to be reasonable.

Comment 123: Commenter 17761 questions the EPA estimate that the proposed rule will create jobs. 

The commenter points out that coal-fired plant closures will lead to the loss of more jobs than the 

creation of gas-fired units will create because coal-fired plants employ 75-100 people versus 25-30 for a 

gas plant of equivalent size.

Response to Comment 123: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

The commenter points to only one potential change in employment, that of a transition from coal to 

natural gas-fired generation, but does not address other changes, such as jobs created by increases in 

production of pollution control equipment.

Comment 124: Commenter 17903 agrees with the EPA’s job creation estimations for the proposed rule 

and reports that 20,000 of the new jobs are expected to be in Iowa. The commenter also mentions that 

utility boards must approve rate increases, and these may not be given at all or will help to control the 

rate increases claimed by industry.

Response to Comment 124: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

The EPA will work with relevant authorities to ensure a smooth transition with this rule and address 

specific issues. Public utility commissions and other regulatory authorities have extensive experience 

with regulatory requirements and treatment of costs to consumers, and are prepared for responding to the 

cost of future pollution control equipment or other response measures.

Comment 125: Commenter 19121 says that the EPA appears to have overstated the job creation 

estimates due to economic growth under the proposed rule.
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Response to Comment 125: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 126: Commenters 16469 and 18500 estimate the potential job losses associated with the 

closure of coal units could amount to more than 50,000 direct jobs in the coal, utility and rail industries, 

with a total job loss including indirect jobs of 251,300. Commenters note that the EPA’s analysis did not 

estimate the effects of adverse employment or effects of higher electric rates. Commenter 16469 

provides a table (see EPA-HQ-OAR-2009-0234-16469-A1_Table page 15) summarizing estimated 

direct job losses in the utility, coal and rail sectors by region based on the 2005 electric generation of 

affected units. Indirect job losses are estimated using Department of Commerce RIMS II multiplier data 

for the electric, gas and water utility industries, specific to each state and do not account for short-term 

or permanent job gains from control unit construction and operation. The commenter provides a 

preliminary assessment of coal “units at risk” on which these related potential job losses are based. The 

assessment is contained in Attachment 4 (see EPA-HQ-OAR-2009-0234-16469-A1), based on data 

sorted from the 2007 DOE/NETL Coal Plant Data Base, updated for information on recent scrubber 

retrofits and retirements. The units included in the screening are more than 40 years old and between 25 

MW and 400 MW, without installed or planned scrubbers. The 2005 generation from these units 

provided a substantial share of total electric generation in several regions (using a 2009 state generation 

baseline): 18% in the East North Central region, 14% in the West North Central, and 12% in the South 

Atlantic. In several states, these units supplied 20% or more of total generation.

Response to Comment 126: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) and coal-fired generation will not change significantly. The agency has 

also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence 

that will help serve load. The EPA has also conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

Overall impact on retail electricity prices nationwide is also anticipated to be modest in light of the 

significant benefits of the rule.

Comment 127: Commenters 17254 and 17409 quote IBEW president Edwin Hill and United Mine 

Workers of America who both state that as many as 50,000 workers in the utility, mining and railroad 

industries could lose their jobs in response to the proposed rule. Commenters disagree with the EPA’s 

estimate of short and long-term job growth, believing that the permanent job losses are underestimated 

and quotes the HIS Global Insight estimate that for every billion dollars spend on compliance with the 

proposed rule, 16,000 jobs will be at risk and the U.S. GDP will be reduced by as much as $1.2 billion. 

Commenters ask that the EPA’s analysis account for the loss of tax and support for local schools due to 

job losses.

Response to Comment 127: The EPA analysis indicates that there will be a small amount of coal 

retirements (2% of the coal fleet) and coal-fired generation will not change significantly. The agency has 

also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence 

that will help serve load. The EPA has also conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy. 

Overall impact on retail electricity prices nationwide is also anticipated to be modest in light of the 

significant benefits of the rule.
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Comment 128: Commenter 17409 quotes estimates by ICF International that employment income is 

estimated to drop in response to the proposed rule by about 2 or 2.5 million full-time workers due to 

retail electricity price increases.

Response to Comment 128: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

The EPA cannot evaluate the basis for ICF International’s projections, but believes that its own analysis 

is as accurate, transparent, and well-supported.

Comment 129: Commenter 17839 states that the transition to clean, renewable energy will create many

more jobs than may be lost due to the proposed rule and questions if jobs will actually be lost at all.

Response to Comment 129: The EPA agrees that this can be one source of new employment resulting 

from today’s rule. It has conducted an updated employment analysis which shows some potential 

positive and negative employment changes from the rule, but overall expects the employment impact to 

be relatively small in comparison to the affected sector and the overall economy.

Comment 130: Commenter 17767 reports that their organization could lose 30 jobs as a result of 

complying with the proposed rule, and the reduced need for coal could put those employed by coal 

mines or trucking companies out of work as well.

Response to Comment 130: The EPA analysis indicates that coal-fired generation will not change 

significantly. The EPA has conducted an updated employment analysis which shows some potential 

positive and negative employment changes from the rule, but overall expects the employment impact to 

be relatively small in comparison to the affected sector and the overall economy.

Comment 131: Multiple commenters (17811, 18421, 18436) agree with the EPA’s projections that the 

proposed rule will lead to the creation of 31,000 short-term construction jobs and 9,000 long-term utility

jobs. The commenter also quotes the World Resources Institute, which announced that compared to 

overall spending in the economy, spending on environmental protection and clean-up employs more 

than twice as many workers in construction and 25% more in manufacturing.

Response to Comment 131: The EPA generally agrees with the thrust of commenters’ assertions and 

those of the World Resources Institute. The EPA has conducted an updated employment analysis which 

shows some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 132: Commenter 17813 disagrees with the EPA’s estimate of created jobs because the 

commenter expects retirements to be much higher than predicted, costing more jobs. The commenter

argues that the jobs the EPA categorizes as new cannot be compared to the permanent jobs lost, because 

they will be temporary. The commenter also believes the EPA’s assessment does not take into account 

the lost opportunity of construction jobs that would have been created by constructing new power plants 

that will not be built as a result of the proposed rule.

Response to Comment 132: The EPA disagrees and notes that its analysis indicates that there will be a 

small amount of coal retirements (2% of the coal fleet) and coal-fired generation will not change 

significantly. The EPA thus believes there will be modest levels of coal retirements resulting from the 

rule, and many units slated for retirement are being taken offline for other reasons aside from 
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requirements to reduce emissions. Overall, coal-fired generation is not expected to change significantly

since sources are anticipated to install pollution controls. The EPA has conducted an updated 

employment analysis which shows some potential positive and negative employment changes from the 

rule, but overall expects the employment impact to be relatively small in comparison to the affected 

sector and the overall economy.

6. Natural gas.

Comment 133: Numerous commenters (17403, 17639, 17640, 17797, 17799, 17806, 17829, 17919, 

18488, 18023) point out that the compliance dates underestimate the time needed to comply with the 

requirements and will lead to more coal-fired plant retirements and an increased demand for natural gas, 

which will lead to fluctuations in natural gas prices. Commenter 17806 specifically states that the 

compressed timeframe will make it virtually impossible to achieve compliance and significantly increase 

the cost of power in most regions as well as threaten reliability. Commenter 17919 agrees with the other 

commenters and cites the NERA Economic Consulting study done in May 2011 that projected average 

U.S. retail electricity prices in 2016 to increase by 12%, with regional increases up to 24%, with a 13% 

reduction in coal-fired generation and a 10% decline in electric sector coal demand in 2016. Also, 

Illinois Power Agency estimates that by 2017 energy bills could jump 65% from current levels. 

Commenter 18023 refers to the EEI report showing that over 150 GWs of coal units, approximately half 

of the U.S. coal fleet, is at risk of being unavailable in 2015 due to insufficient time to achieve 

compliance. This commenter points out that the timeframe strains the supply of equipment and related 

resources, which increases costs that are passed on to consumers. A footnote offers and estimated 

electricity price increase of up to 25% in the Southeast.

Response to Comment 133: The agency has prepared analyses of the costs, benefits, and employment 

impacts associated with the rule and included them in the RIA for the rule. The projected impact on 

national retail electricity prices is anticipated to be relatively small, and no region of the country is 

expected to experience a double-digit increase in retail electricity prices as a result of this rule. Although 

economically vulnerable families could experience some increase in electricity price in 2015, this 

increase should be understood in the context of the substantial health benefits from Hg, HAP, and 

reductions of other pollutants that will result. Industry has shown that it can install large amounts of 

pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. 

In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare 

capacity to serve load, and industry has also shown that it can build new capacity quickly in response to 

demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. In 

addition, there are certain provisions for granting utilities some additional time to comply, if conditions 

warrant (see preamble). Natural gas supplies and reserves have increased significantly in recent years, 

and prices have remained fairly stable since their peak in the early 2000s.

Comment 134: Commenter 17852 states that natural gas prices are not more volatile than for other 

comparable commodities. Though not strictly part of the EPA’s “beyond the floor” analysis, the EPA’s 

RIA also creates a misimpression by stating that “The natural gas market in the United States has 

historically experienced significant price volatility from year to year, between seasons within a year, and 

can even undergo major price swings during short-lived weather events.” Simply put, natural gas prices 

today are not inherently more volatile than other comparable commodities, and the U.S. - given the 

abundance of natural gas - is likely to experience significantly less volatility than in the past. The 

commenter and the Bipartisan Policy Center have jointly commissioned an entire report that 

demonstrates why natural gas price volatility occurred in the prior decades (including due to the federal 

government discouraging production), and why these concerns are less likely to occur in the foreseeable 
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future. These reasons include: an enhanced resource base due to shale gas, improved drilling technology, 

improved storage and delivery infrastructure, and the elimination of government price control that 

artificially constrained production. Furthermore, coal prices have experienced similar volatility in the 

past, and have been widely reported to be facing upward price pressure due to the export of coal to meet 

Asian demand.

Response to Comment 134: The EPA’s analysis and conclusions concerning natural gas were not 

intended to suggest abnormal volatility relative to other commodities, but only to acknowledge the 

volatility that has been observed historically. The reasons given by commenters for expecting less 

natural gas price volatility in the future are not unreasonable, however, nor are observations about 

increasing coal demand elsewhere.

Comment 135: Commenter 17725 states that natural gas use is only an option in places where 

infrastructure exists to supply sufficient natural gas to the EGU and other local needs and reports that 

year-round reliable gas delivery is rare due to requirements to meet the other needs. The commenter says 

that gas interruptions are prevalent in the winter, but can happen year-round, and the costs of 

establishing a natural gas line to a power plant can be tens of millions of dollars or more, and moving a 

plant to a gas source can take many years. The commenter describes the options for a Norwalk Harbor 

plant, and explains that the modifications are costly and difficult even before considering the 

modifications needed to alter the boiler and fuel supply system to allow natural gas combustion.

Response to Comment 135: The EPA’s analysis of the impacts to the power sector can be found in the 

RIA of the rule. The agency has analyzed resource adequacy issues and finds that there is ample existing 

spare capacity to serve load, and industry has also shown that it can build new capacity quickly in 

response to demand. For example, the power sector brought online over 140 GW of gas capacity from 

2001 to 2003. The EPA will work with relevant authorities to ensure a smooth transition with this rule. 

In addition, there are certain provisions for granting utilities some additional time to comply, if 

conditions warrant (see preamble). Natural gas supplies and reserves have increased significantly in 

recent years, and prices have remained fairly stable since their peak in the early 2000s.

Comment 136: Commenter 17640 explains that a Midwest steel company estimates that a 1 cent per 

kWh increase in electricity cost would add $10 million annually to company costs.

Response to Comment 136: The EPA has designed a rule with as much flexibility as possible and in 

accordance with the requirements outlined in the CAA for HAP, and does not expect significant impacts 

on electricity prices generally. The EPA believes energy efficiency measures can be a complement to 

this rule, and can be an important tool in helping address emissions. The EPA has not included all the 

likely additional energy efficiency measures that are likely to occur by 2015, but will continue to pursue 

energy efficiency improvements throughout the economy, along with other Federal agencies, states and 

other groups. This will contribute to additional environmental and public health improvements while 

lowering the costs of realizing those improvements.

Comment 137: Multiple commenters (17403, 17812, 17868, 18500, 19211) disagree with the EPA 

estimate for natural gas price changes. Commenter 17812 expects the proposed rule to lead to an 

increase in natural gas prices as utility companies transition to burning natural gas instead of installing 

emission controls. The commenters quote NERA estimates that natural gas prices will increase by 17% 

in 2016, much higher than the EPA estimate of 0.6% to 1.3% increase. This translates to a natural gas 

expenditure increase by residential, commercial and industrial sectors by $8.2 billion per year, or $85 

billion (present value) for 2011-2030. Commenter 17868 agrees that prices will increase more than the 
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EPA estimates and asks that the EPA use a minimum set of natural gas prices such as the provided graph 

of average national monthly gas prices provided (page 35 of EPA-HQ-OAR-2009-17868-A2). 

Commenter 19211 sees the projected increase in natural gas prices as a reason manufacturers may lose 

confidence in the U.S. as a favorable place to do business.

Response to Comment 137: The EPA has provided an assessment of the economic impacts of the rule 

on the power sector, which can be found in the RIA of the rule. The agency has fully documented its 

assumptions and framework for modeling natural gas in IPM for both the proposed and final MATS. 

This information can be found in Chapter 10 of the IPM documentation 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter10.pdf). The documentation 

provides a thorough overview of the natural gas module, describes the very detailed process-engineering 

model and data sources used to characterize North American conventional, unconventional, and frontier 

natural gas resources and reserves and to derive all the cost components incurred in bringing natural gas 

from the ground to the pipeline. Also documented are the resource constraints, liquefied natural gas 

(LNG), demand side issues, the natural gas pipeline network and capacity, procedures used to capture 

pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key 

gas market parameters. IPM modeling of natural gas prices uses both short- and long-term price signals 

to balance supply of and demand in competitive markets for the fuel across the modeled time horizon. 

As such, it should be understood that the pattern of IPM natural gas price projections over time is not a 

forecast of natural gas prices incurred by end-use consumers at any particular point in time. The natural 

gas market in the U.S. has historically experienced significant price volatility from year to year, between 

seasons within a year, and even sees major price swings during short-lived weather events (such as cold 

snaps leading to short-run spikes in heating demand). These short-term price signals are fundamental for 

allowing the market to successfully align immediate supply and demand needs; however, end-use 

consumers are typically shielded from experiencing these rapid fluctuations in natural gas prices by 

retail rate regulation and by hedging through longer-term fuel supply contracts. IPM assumes these 

longer-term price arrangements take place “outside of the model” and on top of the “real-time” shorterterm price variation necessary to align supply and demand. Therefore, the model’s natural gas price 

projections should not be mistaken for traditionally experienced consumer price impacts related to 

natural gas, but a reflection of expected average price changes over the time period 2015 to 2030.

Comment 138: Commenter 17868 discusses the factors that could lead to higher natural gas prices not 

currently reflected in the EPA impact projections, including industrial load and demand not rebounding 

to 2008 levels and the influence of liquefied natural gas exports. The commenter asks that the EPA 

address these factors:

1. Higher natural gas demand for use in vehicles (a la The Pickens Plan) or some amount of 

transportation electrification.

2. Constraints either on shale resources allowed to be extracted due to regional opposition or reflect 

drilling restrictions or a cost adder for environmental remediation.

3. Starting oil prices “adapted from AEO 2009,” of about $62/bbl for 2011 are well below current oil 

prices.

4. No documentation of any indication that the gas market module of IPM reflects the drilling lease 

inventory buildup that may be causing some producers to drill at less economic prices in exchange 

for cash flow and retention of their lease options.

5. Unclear what the production per well or depletion assumptions are or whether they have been 

updated (i.e., lowered) for the shift to more shale production.

6. Figure 10-7 from U. S. EPA’s proposed rule provides the resource cost curves but no documentation 

of how they were derived or how the quantity able to be produced economically at prices below $14 
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per MMBtu was determined. Page 10-13 of U. S. EPA’s proposed rule indicates that the 

undiscovered gas resource is “assumed” to grow at 0.2% per year for conventional gas and 0.75% 

for undiscovered gas. Nothing provides the basis for testing that assumption’s validity. The 

discussion admits that technology drives the ability to produce undiscovered resources but does not 

test the technology assumption and no curves are provided at all for the existing discovered resource 

base.

7. The model covers North America only, so it must be fed an exogenous assumption on LNG imports 

(or exports) and cannot predict or capture changes in world-wide development and trading of natural 

gas.

Response to Comment 138: The EPA has provided an assessment of the economic impacts of the rule 

on the power sector, which can be found in the RIA of the rule. The agency has fully documented its 

assumptions and framework for modeling natural gas in IPM for both the proposed and final MATS. 

This information can be found in Chapter 10 of the IPM documentation 

(http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/v410/Chapter10.pdf). The documentation 

provides a thorough overview of the natural gas module, describes the very detailed process-engineering 

model and data sources used to characterize North American conventional, unconventional, and frontier 

natural gas resources and reserves and to derive all the cost components incurred in bringing natural gas 

from the ground to the pipeline. Also documented are the resource constraints, liquefied natural gas 

(LNG), demand side issues, the natural gas pipeline network and capacity, procedures used to capture 

pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key 

gas market parameters. IPM modeling of natural gas prices uses both short- and long-term price signals 

to balance supply of and demand in competitive markets for the fuel across the modeled time horizon. 

As such, it should be understood that the pattern of IPM natural gas price projections over time is not a 

forecast of natural gas prices incurred by end-use consumers at any particular point in time. The natural 

gas market in the U.S. has historically experienced significant price volatility from year to year, between 

seasons within a year, and even sees major price swings during short-lived weather events (such as cold 

snaps leading to short-run spikes in heating demand). These short-term price signals are fundamental for 

allowing the market to successfully align immediate supply and demand needs; however, end-use 

consumers are typically shielded from experiencing these rapid fluctuations in natural gas prices by 

retail rate regulation and by hedging through longer-term fuel supply contracts. IPM assumes these 

longer-term price arrangements take place “outside of the model” and on top of the “real-time” shorterterm price variation necessary to align supply and demand. Therefore, the model’s natural gas price 

projections should not be mistaken for traditionally experienced consumer price impacts related to 

natural gas, but a reflection of expected average price changes over the time period 2015 to 2030.

Comment 139: Commenter 17868 asks that the EPA consider the infrastructure (pipeline and storage) 

issues and other concerns found in the APPA study “Implications of Greater Reliance on Natural Gas for 

Electricity Generation” found in Appendix M. [EPA-HQ-OAR-2009-0234-17868-A2]

Response to Comment 139: The EPA is familiar with the study and has considered it. The EPA’s IPM 

modeling includes natural gas pipeline requirements for coal-to-gas (CTG) conversions as described in 

Documentation Supplement for EPA Base Case v4.10_PTox − Updates for Proposed Toxics Rule ( 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf, Section 5.3.2).

Comment 140: Commenter 17627 quotes the Babcock & Wilcox White Paper MS-14 “Natural Gas 

Conversions of Existing Coal-Fired Boilers” 2010 and recommends the EPA project capital costs based 

on the B&W costs.
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Response to Comment 140: The EPA is familiar with the study and has considered it. The EPA’s IPM 

modeling includes a coal-to-gas (CTG) conversion option as described in Documentation Supplement 

for EPA Base Case v4.10_PTox − Updates for Proposed Toxics Rule ( 

http://www.epa.gov/airmarkets/progsregs/epa-ipm/docs/suppdoc.pdf, Section 5.3.1). In that 

documentation, Table 5-11 Cost and Performance Assumptions for Coal-to-Gas Retrofits, provides 

details of the assumed cost of boiler modifications for the CTG option. EPA’s assumed $250/kW boiler 

modification cost for a 75 MW unit is conservatively derived from the $50 to $75/kW costs estimated by

B&W for somewhat larger units using their “Option 1,” as described in the cited B&W paper 

(http://www.babcock.com/library/pdf/MS-14.pdf). Thus EPA’s CTG option and B&W’s CTG Option 1, 

both involve only modifications to the existing boiler; they do not involve higher cost approaches such 

as the addition of a gas turbine (as in B&W Option 2).

Comment 141: Commenter 17879 explains that much of the manufacturing industry cannot pass along 

increased input costs because it decreases competitiveness. The paper industry in particular is in decline, 

the commenter reports, and increased natural gas and electricity costs could exacerbate the nation’s 

weak economic situation. The commenter worries that the widespread conversion from coal or oil to 

natural gas by power plants will lead to an increase in natural gas consumption and costs.

Response to Comment 141: The EPA has designed a rule with as much flexibility as possible and in 

accordance with the requirements outlined in the CAA for HAP. As discussed elsewhere in this 

document, the EPA’s analysis shows only modest conversion to natural gas and that coal will continue 

to play a major role in the nation’s energy economy. Additionally, the EPA believes energy efficiency

measures can be a complement to this rule, and can be an important tool in helping address emissions. 

The EPA has not included all the likely additional energy efficiency measures that are likely to occur by

2015, but will continue to pursue energy efficiency improvements throughout the economy, along with 

other Federal agencies, states and other groups. This will contribute to additional environmental and 

public health improvements while lowering the costs of realizing those improvements.

Comment 142: Commenter 17711 discusses the unique concerns of paper mills that produce some of 

their own electricity, but also purchase some. The commenter is concerned that the proposed rule will 

increase costs and lead to some plants switching to natural gas, thus increasing the cost of natural gas, 

putting jobs at risk.

Response to Comment 142: The EPA has designed a rule with as much flexibility as possible and in 

accordance with the requirements outlined in the CAA for HAP. As discussed elsewhere in this 

document, the EPA’s analysis shows only modest conversion to natural gas and that coal will continue 

to play a major role in the nation’s energy economy. Additionally, the EPA believes energy efficiency

measures can be a complement to this rule, and can be an important tool in helping address emissions. 

The EPA has not included all the likely additional energy efficiency measures that are likely to occur by

2015, but will continue to pursue energy efficiency improvements throughout the economy, along with 

other Federal agencies, states and other groups. This will contribute to additional environmental and 

public health improvements while lowering the costs of realizing those improvements.

Comment 143: Commenter 17853 discusses the cost effectiveness for coal-to-gas with respect to 

increasing capacity for existing zero HAP base load EGUs, including natural gas. The commenter

provides Figure 1, which shows raw commodity prices, which shows natural gas to trend higher than 

coal, but since natural gas is 1.67 times more energy efficient, natural gas is comparable to coal in 

commodity prices. (See Insert EPA-HQ-OAR-2009-0234- 17853-A2_Figure1and2Page3.doc.)
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Response to Comment 143: . The EPA has provided an assessment of the economic impacts of the rule 

on the power sector, which can be found in the RIA of the rule. The EPA generally agrees with 

commenter’s assessment, noting that it has designed a rule with as much flexibility as possible and in 

accordance with the requirements outlined in the CAA for HAP. Source owners will be able to ascertain 

the viability of coal to case conversion relative to other options for reducing HAP emissions.

Comment 144: Commenters 18480 and 18481 express concern that the cities of Beatrice and South 

Sioux City, Nebraska will be unable to meet the compliance deadline. Both receive their electricity from 

the Nebraska Public Power District, and the mix is 50% coal, 40% nuclear and the remainder wind, 

natural gas and hydro power. The coal plants use low-sulfur coal and have baghouses that have reduced 

Hg emissions by 50%. An estimate of compliance costs show a preliminary cost of $1 billion, which 

will lead to a rate increase. The commenters request that the EPA reconsider the proposed rule’s 

aggressive emissions limits and deadlines, in light of the economic effects.

Response to Comment 144: To the extent that sources have already installed significant emission 

controls, the EPA anticipates that the additional costs of complying with this rule will be much less. As 

discussed elsewhere in this document, electricity prices are not expected to increase significantly as a 

result of this rule. Nonetheless, the EPA will work with relevant authorities to ensure a smooth transition 

with this rule and address specific issues. Public utility commissions and other regulatory authorities 

have extensive experience with regulatory requirements and treatment of costs to consumers, and are 

prepared for responding to the cost of future pollution control equipment or other response measures. In 

addition, there are certain provisions for granting utilities some additional time to comply, if conditions 

warrant (see preamble).

Comment 145: Commenter 18486 expresses concern that the combined effect of the new rule will 

increase the use of natural gas for electric generation and increase natural gas prices, decreasing 

availability for other uses. The commenter reports that natural gas is used in the production of ammonia 

for fertilizer and for heating and other purposed in the agricultural industry. The commenter states that 

other agricultural sectors, such as dairy, are electricity intensive so they will be impacted by the cost 

increases for electricity and natural gas. The commenter asks the EPA to consider reports by Brattle 

Group, ICF, Credit Suisse, CRA, FBR, Wood McKenzie and Bernstein Research on the ways the 

proposed rule will lessen the use of coal and increase natural gas use.

Response to Comment 145: The EPA’s analysis of the impacts to the power sector can be found in the 

RIA of the rule. The analysis indicates that only a small number of coal plants will retire, and coal-fired 

generation will continue to be the largest source of electricity. The agency has analyzed resource 

adequacy issues and finds that there is ample existing spare capacity to serve load after retirements are 

factored in, and industry has also shown that it can build new capacity quickly in response to demand. 

The EPA will work with relevant authorities to ensure a smooth transition with this rule. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). Natural gas supplies and reserves have increased significantly in recent years, and prices 

have remained fairly stable since their peak in the early 2000s. The EPA anticipates this trend will 

continue although there may be some modest price effects on natural gas markets due to this rule.

7. Compliance timeline and general timeline.

Comment 146: Commenter 17806 considers the compliance time limits imposed by the proposed rule 

to be impossible to achieve in light of the other final or pending rules. The commenter believes the short 

timeline for these rules will increase the cost of power in most regions and threaten reliability.
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Response to Comment 146: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 147: Commenter 19199 believes the utilities will need more time to comply with the 

proposed rule in order to acquire the materials and labor needed to construct and install the equipment 

without creating unnecessary cost increases and an unreliable electricity supply. The commenter

believes the EPA should extend the time to allow flexibility in implementation of the proposed rule.

Response to Comment 147: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 148: Commenter 19213 says that the proposed rule does not allow adequate time to comply. 

The commenter states that the timeline brings a risk of needing to increase electricity rates significantly

and negatively impact the economy and federal budget.

Response to Comment 148: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 149: Commenter 19213 states that small utilities will have a difficult time getting vendors 

and contractors to commit to projects, since large utilities will be seeking larger quantities of equipment.

Response to Comment 149: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 150: Commenter 17834 states that the proposed rule will require costs be passed on to 

consumers, meaning state public utility commissions will be flooded with requests for rate increases 

from utilities trying to recover expenditures. The short deadline will also result in a large number of 

extension requests made to state permitting authorities, further burdening them.

Response to Comment 150: The implementation of this rule will be 3 years after its promulgation, or 

the end of 2014. Public utility commissions have extensive experience with regulatory requirements and 

treatment of costs to consumers, and are prepared for responding to the cost of future pollution control 

equipment or other response measures. In addition, there are certain provisions for granting utilities

some additional time to comply, if conditions warrant (see preamble). Thus, there will be some time 

before the impacts of this rule such as any increase in retail electricity prices become a concern. It also 

should be noted that increases in retail electricity prices will be 3.1% on average in 2015, with a range 

regionally from 1.3 to 6.3%. See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 151: Commenters 17743 and 17761 express concern that the short compliance deadline will 

require many facilities to be taken offline at that same time to make upgrades, leading to reliability

issues.
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Response to Comment 151: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 152: Commenter 18538 states that the compliance timeline in the proposed rule does not 

include time to plan and permit new facilities. The commenter believes the EPA assumes owners will be 

able to determine which plants will retire on the first day of the proposed rule’s implementation period. 

However, the commenter explains that permitting, planning and construction can run longer than 3 years 

and delays in construction are common. Transmission upgrades can also take longer than 3 years. Since 

many of the new plants in Texas will be in the same areas, permitting could also take longer.

Response to Comment 152: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 153: Commenters 17881 and 18033 expresses concern that even with a blanket 1-year 

extension, the proposed rule still poses risk to the reliability of the nation’s electricity grid and to 

national security. The commenter asks the EPA to work with industry to lay the groundwork for the 

Presidential exemptions, as allowed by the CAA.

Response to Comment 153: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 154: Commenter 15002 states that the proposed rule should regulate emissions to the average 

emissions achieved by the top performing 12% of sources since this provides a satisfactory balance 

between emission controls, the monetized value of the associated health benefits and the projected 

costs. The commenter also urges the EPA to adopt a review schedule for Hg and HAP emissions, such 

as a 5-year review cycle as defined under the CAA NAAQS review process.

Response to Comment 154: The rule will impose HAP emissions limits consistent with the agency’s 

interpretation of MACT as set forth in the CAA (section 112). Although the EPA has conducted a 

detailed analysis of the costs and benefits of the rule, the setting of a MACT floor is not based on the 

costs and benefits of control. Setting standards beyond the MACT floor does consider costs and benefits 

as elements to consider. The review cycle for standards such as this one is not longer than 8 years as set 

forth in CAA section 112.

Comment 155: Commenter 17654 reports that they will need to install add-on pollution controls to 

meet the proposed emission standards as well as implement other physical or operational changes. The 

commenter expresses concern about the number of pre-construction steps that would be required, as well 

as the new construction activities and the challenges of scheduling sequence relative to interconnections 

and other tie-in considerations involved in compliance.

Response to Comment 155: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 156: Several commenters (17681, 17886, 18441) have concerns about the tight timeframe 

imposed by the proposed rule. Commenters 17681 and 17886 argue against the EPA’s suggestion that 
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utilities should commit to capital projects before a final rule is completed. The commenters point out 

that it is unwise to invest in emission strategies that may not be adequate to comply with the final rule. 

The commenters state that many companies have had to stop their investments for strategies based on 

prior rules because they are likely to be insufficient for the proposed rule. Rate-regulated states may not 

be able to recover capital commitments made before the rule is final. Commenters 17886 and 18441 

states that early decisions are not appropriate for a MACT rule as they may be for Clean Air Interstate 

Rules, since the CAIR is a cap and trade program that allows flexibility, and the proposed rule requires 

units to meet limits to be shut down. Commenters believe utility decisions on unit retirement versus 

additional control installations must factor into all anticipated and existing regulations.

Response to Comment 156: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 157: Commenter 19114 has determined that the proposed rule does not provide enough time 

to permit, engineer, procure and construct the retrofits their fleet will need to meet the 2014 deadline.

Response to Comment 157: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). 

Comment 158: Commenter 17911 explains the different approaches used to obtain funding by a private, 

stock or cooperative company as opposed to a municipality. A private company comes to an agreement 

with an entity with funds to lend. Municipalities, on the other hand need approval from the voting public 

to issue revenue bonds or general obligation bonds to begin the process of financing projects, often by a 

super majority. Additionally, the commenter states municipalities are bound by publicly adopted budgets 

that cannot be amended, so it may take up to 18 months to get approval to spend money for projects like 

those necessitated by the proposed rule. The commenter also explains that municipal bonds have been 

hit by threatened bankruptcies of municipalities, which makes it increasingly difficult to fund projects 

and many municipalities have seen a reduction in their revenue streams, including sales tax and water, 

wastewater or electricity utility bills. A downgrade in the U.S. credit rating may also change municipal 

borrowing ratings, making money increasingly difficult to borrow. Municipalities are legally prohibited 

from skipping or speeding up regulatory or legal processes. All of these factors make it difficult for 

municipal utilities to move forward quickly with construction of new controls or generation.

Response to Comment 158: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). In addition, the deductibility of federal tax on capital investment by municipalities may

make investment in pollution control somewhat less expensive relative to private, stock or cooperative 

companies, who do not have this tax advantage for debt.

Comment 159: Commenter 18447 explains that they will not be able to plan, design, permit, bid and 

build a new transmission line in 3 years. The commenter states that they have been working to build a 

new transmission line without success since 2005. The commenter says that the initial cost estimate was 

$18.2 million, but has now surpassed $29 million and will not be completed until 2012. The commenter

explains that when the city power plant is down, without this transmission line the power in the city will 

go out any time the demand is greater than 63 MW. The commenter also says that committing resources 

toward rule compliance before it is finalized is not an option as resources are only available when the 

need is known.
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Response to Comment 159: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). 

Comment 160: Commenters 17808 and 18421 do not believe that labor availability will constrain 

control installation in the required timeframe and cites ICAC response that it will not for these reasons:

1. Power sector has demonstrated ability to install large number of systems in short time period.

2. Majority of coal plans have installed control systems already.

3. Fewer resource and labor-intensive control options being used for compliance.

4. End users have utilized cost reducing and implementation efficiency strategies for efficient 

deployment of technologies.

Response to Comment 160: The EPA thanks the commenter for their comments. These comments are 

generally consistent with the conclusions of the agency’s analyses on feasibility of control installations 

for this rule as found in the TSD on this subject in the docket for this rulemaking.

Comment 161: Commenter 18498 considers the compliance schedule to create a regulatory

environment where reserve capacities will decrease and consumer costs will increase. The commenter

cites studies showing the proposed rules and others will cause 10 to 70 GW of coal retirement between 

2015 and 2020. The commenter explains that replacement capacity cannot be operational prior to the 

compliance timelines for retirement or retrofits of existing facilities. This results in an inefficient and 

costly approach that could be addressed by extending the compliance deadlines to allow sufficient time 

to plan for transition to other technologies in a manner that is cost effective and assures grid reliability. 

The commenter requests the compliance deadlines to be increased to at least 5 years with extensions 

allowed for 2 additional years.

Response to Comment 161: See preamble and TSD on feasibility for further discussion. The EPA has 

analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, 

and industry has also shown that it can build new capacity quickly in response to demand. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). As discussed further in the preamble, compliance timeframes are prescribed by the 

CAA.

Comment 162: Commenters 17812 and 18038 suggest that market realities of installing control 

equipment will increase the cost of the equipment due to the timeframe for compliance. Commenter

18038 is especially concerned that the short timeline and resulting increases in costs will be a hardship 

for those already having difficulty in the current economy.

Response to Comment 162: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 163: Commenter 18435 states that a wide range of technical and economically feasible 

practices and technologies are available currently to meet the emission limits and are in use around the 

country.

Response to Comment 163: The EPA agrees with the comment. Our report on feasibility of controls to 

meet the requirements of this rule can be found in a TSD in the docket for this rulemaking.
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Comment 164: Commenter 17403 disagrees with the employment impacts estimated by the EPA and 

the estimated number of units expected to retire. The commenter states that a longer timeline would 

allow the EPA to preserve employment opportunities while protecting the environment.

Response to Comment 164: The EPA has conducted an updated employment analysis which shows 

some potential positive and negative employment changes from the rule, but overall expects the 

employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 165: Several commenters (17409, 17736, 18441) express concern over the 36-month 

compliance timeframe and urge the EPA to provide an extension of at least 1 year to avoid more plant 

retirements and lost jobs than necessary. Commenters 17736 and 18441 go on to request a clear 

explanation of the requirements to qualify for an extension and commenter 17736 requests automatic 

qualification for replacement source provisions, regardless of location while commenter 18441 does not 

request a blanket delay.

Response to Comment 165: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble).

Comment 166: Commenter 17627 discusses the length of time it takes to adhere to permitting 

requirements and the time needed to design, engineer, fabricate and install equipment. The commenter

explains that all these resources will be limited as multiple facilities try to utilize them during the short 

timeframe and several commenters (17881, 17911, 18933, 19212) agree with this assessment. 

Commenter 19212 reports that the compressed timeline will inflate costs to twice that of a more 

reasonable implementation period of 6 to 8 years, which is wasteful of rate payers money. The 

commenter suggests petitioning Congress for additional time to ensure a reasonable outcome.

Response to Comment 166: See preamble and TSD on feasibility for further discussion. In addition, 

there are certain provisions for granting utilities some additional time to comply, if conditions warrant 

(see preamble). As discussed further in the preamble, compliance timeframes are prescribed by the 

CAA.

Comment 167: Commenter 18025 explains that between 2008 and 2010, approximately 60 GW of coal 

capacity was retrofitted with scrubber controls and the industry completed between 50 and 60 scrubber 

retrofits in each of the years 2009 and 2010, which shows the industry can complete large numbers of 

retrofits in a short time period. Commenter 18025, along with commenter 18025, encourage the EPA to 

finalize the rule on the planned schedule to avoid market uncertainty.

Response to Comment 167: We agree with the commenter. Extensions up to 1 year for the timing of 

implementation at individual source are available through the CAA.

Comment 168: Commenter 18477 estimates that compliance with the proposed rule will require new 

controls on 10 of Hawaiian Electric’s 14 steam boilers, and the controls cannot be completed until 2018 

without jeopardizing system reliability. This would increase costs for consumers by 5% in 2014, and 

trend up to 10% for 2018 and later years. The commenter notes that the remaining boilers would be 

retired, and the cost of replacement generation was not included in the estimates.

Response to Comment 168: See preamble for discussion of requirements for non-continental sources.
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Comment 169: Commenter 18538 believes the EPA has underestimated the time needed to plan, permit 

and construct sufficient new generation and transmission to compensate for the retirements caused by 

the proposed rule.

Response to Comment 169: The claims of retirements in recent studies of the impact of EPA rules are 

addressed in the preamble for the final rule.

Comment 170: Commenter 19121 states that the rule’s timeline combined with over-regulated HAP 

place a threat to grid reliability.

Response to Comment 170: The claims of retirements in recent studies of the impact of EPA rules are 

addressed in the preamble for the final rule. As discussed in this document, the preamble, and other 

supporting materials, the EPA disagrees that HAP are “over-regulated” by the rule.

8. Large burden, little environmental gain.

Comment 171: Several commenters (17681, 17731, 17761) state that the EPA has no data relating to 

benefits from reducing non-Hg HAP, so the costs of the proposed rule exceed the HAP benefits by

29,000 times. Commenter 17761 states that the impact analysis was largely focused on Hg with little 

support for other HAP reductions and failed to provide account of true costs and benefits.

Response to Comment 171: The benefits of this rule include the reductions in non-HAP emissions such 

as SO2 and PM2.5 that will take place based on the EPA’s modeling. These reductions are credible and 

are considerable in size. The estimates of these benefits reflect extensive analysis that has been reviewed 

by the EPA’s SAB, and reflects the latest scientific understanding on the subject. These benefits 

outweigh the total annual costs of the rule by at least six-fold. More information on the estimates and the 

methodology for their preparation can be found in the RIA for the rule. In addition, we are not able to 

monetize the benefits from reductions of non-Hg HAP that will take place, but it is clear that benefits 

will occur from reductions of these HAP.

Comment 172: Several commenters (17765, 17840, 17931, 18018) state that the rule is one of the most 

expensive in the history of the CAA and is a huge regulatory burden for little environmental gain. 

Commenter 17840 states that a precise cost estimate for the proposed rule is not possible because of the 

number of interrelated rules to be considered. The commenter states that little to no incremental public 

health benefits will be realized in response to the proposed rule.

Comment 173: Commenter 17842 cites the EPA estimate that the rule will cost $10.9 billion and create 

social benefits of $42 to $140 billion annually and states that other analyses suggest costs will be more 

severe due to the cumulative impact of interrelated emission regulations.

Response to Comments 172 - 173: The EPA’s analysis of the impacts to the power sector can be found 

in the RIA of the rule. Industry has also shown that it can build new capacity quickly in response to 

demand. The EPA has not provided a cumulative impact analysis of various rulemakings for a variety of 

reasons, which are outlined in the preamble and elsewhere in this document.

Comment 174: Some commenters (17623, 17656, 17799, 17917, 17919, 18023) consider the proposed 

rule to be the most expensive clean air rule ever. They point out the estimated $10.9 billion annual cost 

in 2015 and approximate 1,200 existing coal-fired EGUs affected, both of which were estimated by the 

EPA. Several commenters (17656, 17681, 17917) believe the EPA’s estimates are incorrect and the true 
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cost will be far more due to cumulative effects of all proposed power sector rules, and indirect costs 

from job losses, reduced productivity and competitiveness resulting from electricity costs. Commenters 

ask the EPA to keep these high costs in mind when evaluating impacts of the proposed rule and consider 

the costs with respect to the benefits. Commenter 17681 in particular requests that the EPA explain how 

its approach utilized “the best available techniques to quantify anticipated present and future benefits 

and costs as accurately as possible.” and include analyses by EIA, EEI, NERC, NERA, Credit Suisse, 

ICF and Burns & McDonnell.

Response to Comment 174: The EPA’s analysis of the impacts to the power sector can be found in the 

RIA of the rule. The methodology applied in that analysis was subjected to extensive external peer 

review and this is documented in the RIA and supporting materials. In contrast, not all of the analyses 

cited by the commenters are completely transparent, and the lack of sufficient documentation of 

methodologies and assumptions prevents the EPA from subjecting them to critical review. Industry has

also shown that it can build new capacity quickly in response to demand. The EPA has not provided a 

cumulative impact analysis of various rulemakings for a variety of reasons, which are outlined in the 

preamble and elsewhere in this document. The EPA has conducted an updated employment analysis 

which shows some potential positive and negative employment changes from the rule, but overall 

expects the employment impact to be relatively small in comparison to the affected sector and the 

overall economy.

Comment 175: Commenter 17637 states that the emission reductions achieved by the proposed rule 

would be realized by other rules such as the NAAQS for PM, SO2 and SO3 and related transport 

rules. As such, the benefit of adding further control equipment and work practices will be minor.

Response to Comment 175: The emission reductions from these rules are based on the agency’s best 

estimates of how emissions of HAP and non-HAP pollutants are affected by the control options 

examined for this proposed rule. Future implementation of the NAAQS mentioned by the commenter 

are accounted for in the agency’s analysis of emissions estimates in later years. In addition, the RIA 

accounts for the impacts of other previously adopted rules. These reductions in emissions lead to 

substantial benefits associated with the rule as shown in the RIA for the rule.

Comment 176: Commenter 17386 reports that their municipal plant will incur significant costs while 

removing minimal HAPS from their two small (28 MW and 114 MW) units, which have limited 

operating time and combust only fuel oil and natural gas.

Response to Comment 176: Natural gas-firing is not impacted by this rule, and the EPA has included 

analysis for some modest improvements available to oil-fired units to achieve compliance, which can be 

found in the RIA.

Comment 177: Multiple commenters (17403, 17640, 17751, 17774, 17775, 17921, 18026, 18033, 

18488, 19114, 19211, 18023) quote the NERA study that looked at combined economic impacts of the 

proposed rule and the Transport rule and projected an $18 billion per year cost. The study also estimates 

an increase in electricity prices of 11.5 to 23% and an increase in natural gas prices as a result of the 

proposed rules as well. Commenters go on to say that manufacturers will not all be able to absorb the 

higher costs and quotes the NERA study’s prediction of 1.44 million job-years lost by 2020 if the 

proposed regulations are implemented. Commenters 17774 and 17775 agree with this and quote the 

estimate of 48 GW of coal-fired electric generating capacity (15% of the U.S. fleet) projected to retire in 

response to the proposed rule. Commenter 17921 states that not all potential health benefits of the 

proposed rule are monetized in the EPA impact analysis, so the total benefit of $50 billion per year is 
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likely to be a low estimate. However, the benefit still exceeds the costs predicted by the EPA or NERA, 

and the commenter believes the rule will benefit children’s health and carry a financial benefit as 

well. Commenter 18026 states that Ohio can’t afford the job losses or price increases. Commenter 19114 

points out that new natural gas units require 75% fewer people per megawatt of capacity than coal. 

Commenter 19211 states that some manufacturers will be unable to absorb the price increase and will 

have to close or decrease production.

Response to Comment 177: The agency’s analysis finds that the nationwide average increase in retail 

electricity price is 3.1% in 2015, and no region of the country will experience an increase in price of 

greater than 6.3%. Natural gas prices will increase as an outcome of the rule, but the increase will be no 

more than 1% on average from 2015 to 2030. We estimate 4.7 GW of coal-fired EGU capacity will 

retire early by 2015 and that short-term construction labor will experience an increase of 46,000 jobyears as an outcome of the rule. Also, in the long-term, there is an impact on labor on an annual basis 

ranging from a loss of 15,000 jobs to an increase of 30,000 jobs associated with the rule. Finally, the 

benefits of the rule are estimated to exceed the $9.6 billion annual cost of the rule in 2015 even though 

there are several benefit categories that could not be monetized, including the health and other effects 

associated with non-Hg HAP. All of these analytical results can be found in the RIA for the rule, and 

various TSDs for the rule also further document various results and the methodology for their 

estimation.

Comment 178: Commenter 17702 believes that by expanding the proposed rule beyond what is 

necessary to meet the remand and vacatur, the EPA created additional costs without improving air 

quality.

Response to Comment 178: The agency has prepared its rule consistent with the DC Circuit Court’s 

remand order. 

Comment 179: Some commenters (17800, 17806, 17884, 18014, 18018) consider the estimated costs of 

complying with the proposed rule ($10.9 billion in 2015) to outweigh the estimated benefits of 

controlling toxic emissions ($4 to $6 million) and therefore neither “appropriate” nor “necessary” as 

required.

Response to Comment 179: The benefits of this rule include the reductions in non-HAP emissions such 

as SO2 and PM2.5 that will take place based on the EPA’s modeling. These reductions are credible and 

are considerable in size. The estimates of these benefits reflect extensive analysis that has been reviewed 

by the EPA’s SAB and reflect the latest scientific understanding on the subject. These benefits outweigh 

the total annual costs of the rule by at least six-fold. More information on the estimates and the 

methodology for their preparation can be found in the RIA for the rule. In addition, we are not able to 

monetize the benefits from reductions of non-Hg HAP that will take place, but it is clear that benefits 

will occur from reductions of these HAP. Conclusions regarding the rationale that this rule is appropriate 

and necessary as defined in section 112(n) of the CAA can be reviewed in the preamble and the 

appropriate and necessary TSD for this rule.

Comment 180: Several commenters (17765, 17840, 18033) find the proposed rule to produce little to 

no public health or environmental benefit while imposing unnecessary costs or losses of employment. 

Commenters state that the pollutants are already regulated under the NAAQS program or other 

regulations.
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Response to Comment 180: The agency has estimated the benefits of this rule to be 5 to 13 times the 

size of the costs in its RIA. Thus, this rule will be beneficial given this comparison of benefits to costs. 

The reductions of pollutants regulated under the NAAQS are co-benefits from the HAP emissions limit 

requirements in the rule, and occur concomitantly with the HAP reductions.

Comment 181: Commenter 18421 cites the EPA’s estimate that the proposed rule will yield monetized 

net benefits of up to $130 billion every year, once the rule is in place. These benefits outweigh the costs 

by 5 to 13 times. The commenter explains that the estimates are conservative since not all benefits could 

be monetized, such as health and ecosystem benefits of reducing nitrogen and sulfur emissions and 

deposition and vegetation benefits from reducing ozone.

Response to Comment 181: The agency agrees with the commenter.

Comment 182: Commenter 18428 considers the proposed rule to be very costly while offering few 

benefits. The commenter points out that since the year 2000, their company has achieved a 62% 

reduction in Hg.

Response to Comment 182: The agency has estimated the benefits of this rule to be 5 to 13 times the 

size of the costs in its RIA. Thus, this rule will be beneficial given this comparison of benefits to costs. 

The benefits and costs from additional mercury reductions are included in these estimates. To the extent 

that companies have already installed significant emission controls, the costs of complying with this rule 

will be less.

Comment 183: Commenter 19041 considers the health benefits to be overstated and the costs 

underestimated. The commenter and commenter 19114 cite the AEP estimate of $6-8 billion in capital 

costs needed in addition to the $7.2 billion already spent since 1990, and a retirement of 6,000 MW of 

capacity to comply with the proposed rule. The commenters say that if one utility will need to do so 

much to comply, the EPA estimate must be low

Response to Comment 183: The agency has provided the most accurate estimates of benefits and costs 

possible using peer-reviewed models and comprehensive data. The RIA for this rule explains the basis 

for the benefits and costs and the uncertainties in the results. The agency also estimates that about 2% of 

coal-fired EGU capacity nationwide may retire early as a result of the rule, and this estimate is based on 

calculations from IPM, a peer-reviewed model. 

Comment 184: Commenter 18477 asks that the EPA consider the natural air quality that exists in 

Hawaii and other island locations. The commenter explains that trade winds give Hawaii and other 

islands some of the best air quality in the nation such that they meet all the NAAQS, so the proposed 

rule would have minimal impact on air quality despite high costs. The commenter urges the EPA to 

develop a separate RIA for non-continental oil-fired units.

Response to Comment 184: This rule is a NESHAP, not a rule to implement a NAAQS, and is imposed 

nationwide consistent with section 112 of the CAA. However, the EPA has adopted provisions for noncontinental units in the final rule and has provided an analysis for non-continental oil-fired units as part 

of the RIA for the final rule. 

9. State regulators.
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Comment 185: Commenters 16859 and 17174 request that the EPA consider the burden of the proposed 

rule and other recently promulgated rules on the resources of individual states. Commenters ask that the 

EPA develop a rule that reduces air pollution and provides efficient implementation and enforcement 

strategies for the delegated authorities. Commenter 16859 asks that the EPA consider ways to secure 

federal funding for states to cover costs associated with state implementation of the proposed rule and 

details the many obligations and costs for state agencies. The commenter explains that costs of 

implementation of the rule can be covered two ways. The first is through U. S. Congressional 

appropriations. The other is through increases in permit fees allowed for Title V activities in the CAA. 

The commenter says it may not be expedient to receive state legislative approval for permit fee increases 

and states that if the EPA estimates state administrative costs, along with state direct compliance costs, 

the estimates might assist both the EPA in justifying their request for appropriations and states in 

justifying permit fee increases. The commenter requests the EPA consider state administrative costs and 

make this information available as directed in UMRA, EO 12866 and EO 13132. The commenter urges 

the EPA to accurately assess the implementation costs on states, so the rule may be implemented 

properly and in a timely manner to avoid adverse health effects.

Commenters 16859 and 17400 explain that for each new EPA rule, states may incur slightly different 

implementation costs. These commenters note that cost categories vary from state to state depending on 

legislative and regulated community differences. One commenter asks that the EPA consider state costs 

for a wide-range of implementation start-up and recurring activities in the implementation cost 

estimation for this rule, while others discussed in the attachment included with the original comment. 

The attachment details several implementation costs that must be accurately assessed for the rule to be 

implemented properly and in a timely manner without adversely affecting human health. The commenter

also asks that the EPA seek federal funding for the states to cover the customary portion of the costs 

associated with state implementation and consider the availability of funding support in its planning for 

new rule adoption schedules and other implementation activities following the rule issuance.

Response to Comment 185: The agency has addressed the impacts on state and municipal agencies in 

compliance with UMRA and EO 12866 and 13132. Additionally, the EPA estimated the costs of 

implementation of the rule to states and has included this analysis in the RIA. The agency has updated 

this analysis for the final rule and included it in the RIA. The reductions in air pollution from the rule 

should be substantial and are well elaborated on in the RIA and in technical support documents found in 

the docket for this rulemaking. The agency will respond accordingly to requests for additional state and 

local agency funding if it is determined that such funding is needed for implementation of this rule.

Comment 186: Commenter 17629 explains that a settlement agreement on a rate case in Wyoming 

created a new layer of review by Public Service Commission to examine the Public Need and Necessity

for passing on environmental control costs to consumers. The commenter anticipates that the analytical 

burden associated with this rule and others recently proposed will increase and reliance on the EPA’s 

technical and economic analyses will not be sufficient. The commenter urges the EPA to take steps to 

change the Grant Agreements to reflect the additional burdens to states.

Response to Comment 186: The agency may consider changing Grant Agreements and help states in 

other ways if the analytical burden to them is substantial enough to warrant agency action.

Comment 187: Commenter 17620 discusses the increased workload of state and local air pollution

control agencies as a result of the proposed rule. The commenter explains that the EPA has proposed a 

number of alternate compliance options that will reduce compliance costs for industry, but increase the 

cost of administering the program. The commenter states that in delegated states, permitting authorities 
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will also conduct inspections and commence enforcement actions where sources are found to be in 

noncompliance, which is important because of the large amount of toxic air emissions that are involved, 

but cannot be undertaken without resources. The commenter points out that increased funding is 

unlikely to be available and urges federal grant funding be provided under sections 103 and 105 of the 

CAA during those years when the majority of implementation activities will occur.

Response to Comment 187: The agency will respond accordingly to requests for additional state and 

local agency funding if it is determined that such funding is needed for implementation of this rule.

Comment 188: Commenter 17620 states that the reductions in SO2 and PM2.5 required by the proposed 

rule will assist state and local air pollution control agencies to meet health-based air quality standards, 

reduce haze and improve visibility. The commenter points out that substantial reduction in emissions 

made by the very large sources under the proposed rule will lead to fewer pollution controls needed at 

smaller sources to meet health-based ambient air requirements. This is a far more cost-effective 

approach than controls at smaller facilities and is the lowest cost path to improved public health and a 

cleaner environment.

Response to Comment 188: The EPA thanks the commenter for the comments. The MATS is a 

standard to reduce HAP, but it will also include revisions to the NOX, SO2, and PM emissions limits for 

utilities. Much of the HAP requirements will lead to co-benefits such as PM2.5 and SO2 reductions that 

could be of aid to states working on implementation of various NAAQS and regional haze strategies.

Comment 189: Commenters 17743 and 17745 express particular concern over the proposed rule’s 

impacts on the burden on the permitting authorities in light of the other current and pending EPA air 

rules also adding to the expected workload. Commenters 17174 and 17834 ask the EPA to consider the 

burden of the proposed rule that is placed on state agencies and develop a rule that reduces air pollution 

but provides for efficient implementation and enforcement.

Response to Comment 189: The agency is careful to mitigate the impacts of this rule to permitting 

authorities to the extent possible. The agency will respond accordingly to requests for additional state 

and local agency funding if it is determined that such funding is needed for implementation of this rule.

10. Miscellaneous.

Comment 190: Commenter 18447 asks that the EPA consider the best interest of the U.S. in creating 

policies. The commenter asks if other countries are willing to hurt their economies to be a good global 

neighbor and states that history shows they will not.

Response to Comment 190: The agency has prepared this rule in response to the requirements of the 

CAA and a court mandated consent decree. The vast majority of benefits resulting from this rule will be 

experienced in the U.S., not outside of it. Additionally, through a variety of working groups and treaty

organizations, the EPA participates in international negotiations to address transboundary air pollution 

and to achieve a level playing field in the control of air pollution.

Comment 191: Commenter 17409 quotes a Stanford University study that says the U.S. could be run 

entirely on clean energy within 10 years, at reasonable cost. The commenter goes on to acknowledge 

other innovations in the power generation industry and points out that new regulations inspire new 

knowledge and industries find new ways to do things better, and more cheaply, making the U.S. more 

competitive in the global market.
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Response to Comment 191: We agree with the commenter that new regulations such as this rule could 

serve to spur innovation to make energy production cleaner, a trend already distinct in the electric power 

sector and that innovation has historically occurred at a more rapid pace than predicted.

Comment 192: Commenter 17855 discusses the difficulties for waste coal industry in complying with 

the proposed rule. The commenter explains that the waste coal industry is reclaiming abandoned mining 

sites to avoid discharging acid mine drainage, at no cost to the taxpayers. The commenter explains that 

waste coal power plants control NOX and SO2 and PM currently, but may be forced to install expensive 

new controls, which may make the plants economically unviable and lead to an end of mine remediation 

without public funding. The commenter explains that waste coal plants are small plants designed to use 

local waste coal and which do not have the ability to pass costs on to customers or switch to another fuel 

to meet proposed limits.

Response to Comment 192: As noted elsewhere in this document, coal refuse-fired EGUs are among 

the units making up the MACT floor pools for all of the HAP. Thus, we believe that such EGUs are 

capable of achieving the limits in the final rule and are not economically unviable as suggested by 

commenter. Should additional controls be required at certain facilities, such controls can be added just 

as at any other EGU. Facilities that have already achieved significant control of emissions are likely to 

face lower costs to comply with today’s rule.

Comment 193: Commenter 17867 explains the Boardman 2020 Plan as an innovative approach to 

achieving environmental goals by ending coal-fired generation at relatively young and efficient EGUs. 

The commenter cites to key features contributing to successful discussions among diverse stakeholders 

to produce an outcome that achieved a remarkable level of consensus for the future of the Boardman 

Plant and for the people and natural environment of Oregon:

1. A state-adopted agreement with broad and diverse stakeholder support;

2. An enforceable agreement to cease coal operations by a date certain;

3. A reasonable amount of time before the end of coal operations to address concerns regarding 

community impacts, including jobs at the facility, replacement of the energy resource that considers 

cost to customers, reliability and resource diversity, and consistency with CAA requirements;

4. Interim emission controls that appropriately address human health and environmental impacts for the 

remaining period of coal-fired operations; and

5. A robust resource planning process that considers low carbon replacement resources among the 

viable alternatives.

In the case of Boardman 2020, the commenter explains the combined strategy of early cessation of coal 

operations and interim controls will result in lower aggregate emissions of haze causing air pollutants 

than those projected under a much more expensive control package that would have otherwise been 

required to run the plant indefinitely.

Numerous commenters (13902, 14279, 14481, 14695, 14696, 15161, 15590, 15636, 15680, 15823, 

15824, 15883, 16406, 16681, 16683, 16825, 17021, 17153, 17194, 17298, 17307, 17308, 17847, 17867, 

17872, 17874, 17894, 17899, 17900, 18052, and 18485) urge the EPA to recognize and accommodate 

appropriate solutions like Oregon ‘s Boardman 2020 plan to allow the agreement to be fully achieved. 

The commenters believe that the final NESHAP rule for EGUs needs to clearly recognize this 

innovative Oregon approach and provide regulatory flexibility to accommodate the Boardman plan 

within the framework of the CAA. The Boardman 2020 Plan is discussed in further detail by

commenters 17867 and 18019.
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Response to Comment 193: We thank the commenters for their comments. The timing for 

implementation of this rule is set in the CAA. We will allow flexibility in compliance, both in method 

and timing, consistent with the CAA.

Comment 194: Commenter 18039 believes that power plants in Massachusetts and other states with 

reduced Hg limits have been placed at a competitive disadvantage and do not get the full benefit of their 

own reductions as a result of being downwind of states which do not impose similar rules. The 

commenter sees the proposed rule as going a long way to address this current inequity.

Response to Comment 194: We agree with the commenter that implementation of this national rule 

may level the playing field, as it were, regarding Hg controls across the country.

Comment 195: Commenter 18961 believes the rules will level the playing field by imposing universal 

standards for all coal-fired units, reducing uncertainties in the industry and easing long-term planning. 

The commenter points out that the standards can be met through existing technology within the 

compliance timeline. The commenter also believes that by retrofitting or retiring out-dated coal-fired 

power plants, the industry will improve the reputational risks and relations with local communities and 

regulators. The commenter shares results from a poll saying that 79% of Americans are in favor of the 

EPA placing stricter limits on Hg from power plants.

Response to Comment 195: The EPA agrees with the commenter.

Comment 196: Commenter 19042 cites the Executive Orders and policy directives from the Obama 

Administration that encourage federal agencies to increase sustainability, reduce emissions and conserve 

energy. The Administration claims this will reduce electricity costs by $1.7 to $2.1 billion from 2010 to 

2020. However, the commenter points out that the capital costs are not included in these estimates, and 

even if no capital costs were needed, the reduction would still be less than the increase due to the 

proposed rule. The commenter also points out that there has been significant interest in the proposed rule 

in Congress, and it may be appropriate for review under the provisions of the Congressional Review 

Act. The commenter states that the impacts analysis is flawed because:

1. it fails to account for the unfunded mandate to every department and agency of the federal 

government that either generates or purchases electricity;

2. our analysis of the RIA found no discussion of federal budget costs;

3. there are no estimates reported by the federal departments and agencies in their budget projections or 

in the budget justification materials provided to Congress; and

4. based on informal contacts with senior federal facility energy managers, we have found no evidence 

that interagency review of the Utility MACT standards considered federal compliance costs and 

budgetary priorities.

Response to Comment 196: Every major rule is subject to the CRA and this rule is no exception. 

UMRA is inapplicable to instrumentalities of the federal government and by its terms applies to federal 

actions that have impacts on state, local, tribal governments or private entities. The agency estimated the 

retail electricity price nationwide to increase on average by 3.7% in 2015 as a result of the rule. The 

agency does not expect this increase in price to lead to significant increases in federal government 

agency operating costs.

Comment 197: Commenter 19042 discusses the federal deficit of $1.6 trillion and the states’ deficit of 

$130 billion and points out that the proposed rule will affect the federal budget in two ways:
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1. direct compliance costs to electric generating units (EGUs) owned by federal agencies; and

2. pass-through compliance costs paid in the form of higher prices for electricity purchased by federal 

agencies.

Response to Comment 197: The agency estimated the increase in direct compliance costs at federallyowned EGUs, and that estimate for the proposed rule is available in the docket. This estimate has been 

revised for the final rule. The agency estimated the retail electricity price nationwide to increase on 

average by 3.7% in 2015 as a result of the rule. The agency does not expect this increase in price to lead 

to significant increases in federal government agency operating costs.

Comment 198: Commenter 19042 notes the EPA identified 96 state and local government entities with 

a combined total of 169 EGUs that will have to comply with the Utility MACT standards. For these 

potentially affected units, the EPA estimated the cost of compliance, setting that cost equal to the change 

in operating and capital expenditures, plus the change in fuel costs, plus the change in revenues resulting 

from the sale of electricity to consumers at presumably higher retail prices.

The results of the EPA UMRA analysis are depicted in Table 1 and Table 2 in the original letter. (See 

EPA-HQ-OAR-2009-0234-19042-A2, 19042_Table_1.doc and 19042_Table_2.doc.)

In the RIA, the EPA notes that its “[UMRA] analysis does not examine potential indirect economic 

impacts associated with the proposed [Utility MACT] rule, such as employment effects in industries 

providing fuel and pollution control equipment, or the potential effects of electricity price increases on 

industries and households.

Each agency’s annually updated SSPP is intended to prioritize agency sustainability activities based on 

lifecycle return on investment. OMB provides periodic evaluation of each agency¡¦s performance via a 

Sustainability and Energy Scorecard (SES). All scorecards are published on CEQ’s website.33 Agencies’

SSPPs show that OMB assigned a “green light” score to the proposed scope 1 and 2 GHG emissions 

targets set by the federal agencies with the largest electricity consumption. The commenter goes on to 

say that the Administration claims that achievement of the scope 1 and 2 GHG emissions targets will 

reduce federal spending. In particular, with respect to purchased electricity, in recent testimony before 

the U.S. Senate, CEQ Chair Nancy Sutley made the following statement:

“If annual greenhouse gas emissions decrease incrementally to produce a reduction equal to five % of 

calculated base year emissions, the Federal government will save an estimated $1.7 to $2.1 billion in 

avoided utility costs over the period 2010 to 2020.” However, the commenter points out that the 

Administration provided no justification for the proposed savings. More importantly, the Administration 

has provided no estimates of the upfront capital investment that will be required in order to deploy new 

clean energy and energy efficiency measures need to achieve the savings. The commenter points out that 

the cost of electricity purchases is a significant cost in the federal budget. As a result of the proposed 

Utility MACT standards, these costs will increase, obviating any potential savings claimed by the 

Obama Administration due to implementation of EO 13514: Federal Leadership in Environmental, 

Energy, and Economic Performance. The commenter states that their analysis shows that the SSPP 

reports and scorecards failed to report the base year electricity and associated GHG emissions data, so it 

is not possible to determine the percent reduction in GHG emissions associated with electricity

consumption. Thus, these assertions may have more of a political bent than an analytical basis. (See 

http://www.whitehouse.gov/administration/eop/ceq/sustainability/omb-scorecards.)
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Response to Comment 198: The agency estimated the retail electricity price nationwide to increase on 

average by 3.7% in 2015 as a result of the rule. The agency does not expect this increase in price to lead 

to significant increases in federal government agency operating costs. 

Comment 199: Commenter 19042 provides analyses of the estimated federal budget impacts, taking 

into account the variation by region. However, since publically available data is aggregated by agency, 

disaggregation by region was not possible, and the commenter suggests the government do this analysis. 

Instead, the commenter based estimates on federal activity within each state. The commenter used the 

EPA RIA price increase to estimate federal electricity costs incurred due to the proposed rule. The result 

was an increase of $166 million per year. The commenter recommends further analysis to estimate the 

magnitude of the unfunded mandate being imposed on states and local governments and the cumulative 

impact of pending EPA rulemakings.

Response to Comment 199: The agency has revised its UMRA analysis for the final rule. The agency

did not prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) the 

various EO requirements that the agency must comply with require us to estimate impacts specific to 

this rule; 2) decision makers and the public need to know the impacts specific to a particular rule in 

order to judge the merits of the regulation; 3) estimates specific to a particular rule are more transparent 

than those from a cumulative impact analysis. A cumulative impact analysis lumps several regulations 

together and can potentially mask a high-cost/low-benefit regulation among other rules that may have 

large net benefits. By analyzing each regulation separately, the EPA makes clear statements about what 

impacts, costs, and benefits will be generated as a result of this particular regulation.

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

Comment 200: Commenter 17690 believes the proposed rule could have unintended impacts on 

deregulated oil-fired units that rely on operating revenues and will be unable to have enough projected 

revenues to justify the cost of compliance. These units may be prematurely retired.
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Response to Comment 200: Our analysis of the impact of the rule on oil-fired units indicates that the 

costs per unit should be modest, and thus the probability of premature retirement for such units is low.

Comment 201: Commenter 17648 considers the EPA to have coordinated the various programs 

involving power plants to be effective and explains how the IPM modeling shows the benefits of 

implementation of the rules. The commenter reports investing nearly $5 billion in clean energy

generation and Smart Grid technology and from this experience considers the EPA’s modeling to be 

unduly conservative. The commenter agrees with the EPA’s modeling that shows the closure of older 

plants and replacement by gas-fired plants of various types and believes that expansion of nuclear and 

alternative energy sources will occur as well. The commenter also explains that the proposed rule and 

other new regulation will increase the efficiency of the fleet, further benefitting the economy. The 

commenter questions the report, “Methane and the Greenhouse-Gas Footprint of Natural Gas from Shale 

Formations” because it does not account for increased efficiency of gas-fired plants and used the wrong 

conversion factors from methane to carbon dioxide equivalents.

Response to Comment 201: We agree with the commenter that this rule could lead to an increase in the 

energy efficiency of the electric power boiler fleet.
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6J - Impacts/Costs: Social Costs

Commenters: 11107, 16207, 16824, 16850, 17254, 17408, 17409, 17620, 17709, 17713, 17727, 17766, 

17775, 17811, 17842, 17875, 17884, 18432, 18435, 18436, 18541, 18961, 19536/19537/19538

Comment 1: Multiple commenters (16207, 17408, 17620, 17811, 18961, 19536, 19537, 19538) 

describe the health benefits of the rule, including the $59 billion to $140 billion each year, or $5 to $13 

in health benefits for each dollar spent on compliance as opposed to the estimated $10.9 billion annual 

cost.

Response to Comment 1: The benefits of this rule as estimated by the agency are quite substantial 

relative to the costs. These benefits include those associated with the estimated Hg reductions as well as 

the reductions in other pollutants such as fine PM and SO2. The agency has prepared an extensive 

analysis of the benefits and costs of this rule which is found in the RIA.

Comment 2: Commenter 16824 considers the potential health benefits of the rule to be questionable 

because it will have no effect on the levels of Hg and other emissions that occur naturally. The 

commenter considers the rule to be adversely affecting efforts to stimulate the economy and job growth 

and causing electric rates to rise.

Response to Comment 2: The agency’s analyses of costs and benefits reflect the latest, peer-reviewed 

science that is available. The benefits analysis is based on peer-reviewed scientific literature, the review 

of EPA’s SAB, and also on the inputs of experts in setting values for benefits for categories such as 

premature mortality. The benefits estimates reflect the reductions in emissions estimated for this rule, 

and are incremental to a baseline that includes the impacts of regulatory programs up to December 2010. 

The agency’s cost analyses are also based on peer-reviewed studies and analyses. The RIA for the rule 

documents both analyses.

Comment 3: Commenter 16850 explains that Florida’s investor-owned electric utilities can petition to 

recover the costs associated with the proposed rule through a cost recovery clause subject to FPSC

review. The commenter provides monthly averages for the increase in residential customer costs for 

every $100 million in environmental compliance costs recovered. These costs range from $1.27 to 

$10.90 for a 1200 square foot residence. The commenter expresses concern for the Florida consumers, 

approximately 85% of whom rely on electricity for heating and cooling, and include a large portion of 

senior citizens on fixed incomes. 

Response to Comment 3: The agency estimates that the nationwide retail electricity price increase 

associated with the rule will be 3.1% in 2015, and there will be some variation in this price increase 

among different regions. No region of the country, however, is estimated to experience an increase in 

price of greater than 6.3%. In Florida, the increase in retail electricity price is estimated to be 2.2% in 

2015 for the power region that includes the State of FL. State and local rate setting agencies are best 

equipped to deal with the issues concerning higher electricity rates in their areas.

Comment 4: Commenters 16207 and 17620 discuss health benefits, such as the 6800 to 17000 people 

saved from premature death, 120,000 prevented asthma attacks, 850,000 employee sick days avoided 

and the thousands of short and long term jobs created by the rule.

Response to Comment 4: The EPA thanks the commenter for these comments. The benefits of this rule 

are substantial, both on their own and relative to the costs. The reduction in incidences and how they are 
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estimated can be found in the RIA for the rule. The employment impacts estimated by the agency for the 

rule reflect both construction labor associated with new control equipment likely to be needed to meet 

the rule requirements, and operation of these controls, and the reaction of the economy to this rule is also 

taken into account. The RIA for this rule contains the analysis methodology and results for employment

changes.

Comment 5: Commenters 17709 and 17727 express concern about the cost of implementing the 

proposed rule. The commenters cite an announcement by the American Electric Power company that 

rates would increase in response to the proposed rule and ask that the proposed rule be reconsidered and 

implemented with a compliance plan that will allow the utilities to continue operating their coal-fired 

plants without additional stipulations that will increase rates. Commenter 17709 states that the rule will 

exacerbate the slow recovery in the state of Michigan.

Response to Comment 5: The agency estimates that the nationwide retail electricity price increase 

associated with the rule will be 3.1% in 2015, and there will be some variation in this price increase 

among different regions. No region of the country, however, is estimated to experience an increase in 

price of greater than 6.3%. The agency is cognizant of the estimated price increases. State and local rate 

setting agencies are best equipped to deal with the issues concerning higher electricity rates in their 

areas.

Comment 6: Commenters 17713 and 17766 state that African Americans and Hispanics are worse off 

than Caucasians by economic measures and tend to be more vulnerable to economic downturns and job 

losses resulting from EPA regulations. Commenter 17766 explains that 71% of African Americans and 

80% of Hispanics live in an area that fails to meet one or more EPA air quality standard, compared to 

57% Caucasians. Also, the commenter notes that 68% of African Americans and 39% of Hispanics live 

within 30 miles of a coal-fired power plant. The commenter states that this close proximity to power 

plants means that they are more likely to be a risk to develop health issues than those who live in cleaner 

neighborhoods. The commenter goes on to add that because these same people are more likely to live in 

poverty, they are less able to move from heavily polluted areas.

Response to Comment 6: We understand the commenters’ concerns. The reductions in Hg will lead to 

improved health in populations in close proximity to coal-fired power plants, and the benefits from these 

reductions are discussed at length in the RIA for the rule. We show the benefits of Hg and HAP

emission reductions, along with the substantial benefits from reductions in emissions of PM, SO2, and 

other pollutants in our RIA. Populations that are the focus of EO 12898 (low-income, minority) will 

benefit from these reductions as shown in the RIA.

Comment 7: Commenter 17775 explains that for EPA benefit estimates to be accurate, up to 20% of 

annual deaths in large areas of the country were due to ambient PM2.5 exposures in 2005. The 

commenter states that these high assumptions are the result of an assumption change made by the EPA 

in 2009 to start calculating mortality risk in its risk assessments below the lowest measured levels, 

which has not been subjected to peer review. The commenter believes this change inflates the baseline 

of PM2.5-related deaths and points out the EPA estimate of deaths among those exposed to PM2.5 levels 

of 12ug/m3 went from almost 3% to nearly 13% as a result of the changed assumption. The commenter

calculates that the percentage would be even higher if the higher pollution levels of the past two decades 

were used. However, the commenter notes that no basis for this change is given. (Footnotes reference 

Attachment 13 and a June 2010 Qualitative Health Risk Assessment for particulate Matter.)
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Response to Comment 7: The EPA disagrees that the method the EPA uses to monetize PM2.5 benefits 

produces unreasonably large estimates. The EPA estimates health benefits below the lowest measured 

level (LML), as no evidence suggest a health effect threshold for PM2.5. These methods have withstood 

continuous regular reviews by the EPA’s SAB. Analyses conducted for the proposed rule demonstrated 

that the vast majority of PM2.5 health benefits occurred above the LML. Therefore, this methodological 

issue would not have a substantial impact on the overall benefits.

Comment 8: Commenters 17811 and 18436 state that without the proposed rule, “particulate matter 

emitted directly from coal-fired power plants was estimated to account for an average of $3.7 billion of 

public health damages each year.” The commenters go on to state that the OMB review found that from 

10/1/99 to 9/30/09 the cost of a PM rule was $7 billion while the estimated benefits range from $19 

billion to $167 billion annually. The commenters state that with few pollutants in the air, healthcare 

costs will go down. The commenters estimate that the country will save between $13 million and $100 

million through reduced premature deaths and healthcare due to illness associated with ozone exposure 

when the new ozone standards are finalized. The commenters believe that the cost savings of the 

proposed rule represents economics and fewer children suffering asthma attacks, fewer hospitalizations, 

less respiratory tract illnesses, improved lung capacity and function for children and healthier infants 

and newborns. (Footnotes referencing the cited studies may be found in excerpt 11 for commenter

18436.)

Response to Comment 8: The EPA agrees that the large health co-benefits of this rule resulting from 

PM2.5 reductions outweigh the costs.

Comment 9: Commenter 17842 states that the costs associated with the proposed rule will increase 

costs for North Dakota in the range of 2 to 4 dollars more a month. The commenter is concerned that the 

estimated costs and affects of the proposed rule do not adequately account for other pending regulations 

and their collective effect on the industry and economy.

Response to Comment 9: The agency estimates that the nationwide retail electricity price increase 

associated with the rule will be 3.1% in 2015, and there will be some variation in this price increase 

among different regions. No region of the country, however, is estimated to experience an increase in 

price of greater than 6.3%. The agency is cognizant of the estimated price increases. State and local rate 

setting agencies are best equipped to deal with the issues concerning higher electricity rates in their 

areas. As to analysis including the effects of pending regulations, the agency did not prepare a 

cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO 

requirements that the agency must comply with require us to estimate impacts specific to this rule; 2) 

decision makers and the public need to know the impacts specific to a particular rule in order to judge 

the merits of the regulation; and 3) estimates specific to a particular rule are more transparent than those 

from a cumulative impact analysis. A cumulative impact analysis lumps several regulations together and 

can potentially mask a high-cost/low benefit regulation among other rules that may have large net 

benefits. By analyzing each regulation separately, the EPA makes clear statements about what impacts, 

costs, and benefits will be generated as a result of this particular regulation. We fold in the impacts of 

final regulations and other actions into our baseline as appropriate in order calculate the impacts specific 

to a particular rule as accurately and transparently as possible.

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 
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to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, the EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and 

costs of regulations pursuant to the 1990 CAA Amendments. The study examines the cumulative impact 

of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in 

the report, the direct benefits from the 1990 CAA Amendments reach almost $2 trillion for the year 

2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full report is at 

http://www.epa.gov/air/sect812/prospective2.html.

The direct benefits of the 1990 CAA Amendments and associated programs significantly exceed their 

direct costs, which means economic welfare and quality of life for Americans were improved by passage 

of the 1990 Amendments. The wide margin by which benefits exceed costs combined with extensive 

uncertainty analysis suggest it is very unlikely this result would be reversed using any reasonable 

alternative assumptions or methods. This conclusion is likely to also be attributable to this rule as shown 

in the RIA.

Comment 10: Commenter 17875 states that rules based on peer-reviewed EPA science will prevent 

illnesses such as asthma attacks and other health and environmental impacts from burning coal, which 

costs this country upwards of $500 billion each year. Health problems are an especially large burden on 

uninsured families, the commenter points out, and the groups with the highest rates of asthma are also 

the least likely to be insured. The commenter adds that history shows that less air pollution means a 

more efficient workforce and economy, as the EPA estimates the country has gained $21.4 trillion in 

health and environmental benefits from clean air programs and saved 4.1 million lost work days and 31 

million restricted-activity days.

Response to Comment 10: We agree with the commenter on the potential for this rule to reduce 

incidences of asthma and thus reduce health costs to affected populations. The benefits of these 

reductions in asthma, along with other benefits, can be found in the RIA for the rule. In addition, we 

agree that reductions in air pollution can improve worker productivity and health as shown in the Second 

Clean Air Act Prospective Report released in March 2011 which assessed at the benefits and costs of 

regulations pursuant to the 1990 CAA Amendments. The study examines the cumulative impact of these 

regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in the report, 

the direct benefits from the 1990 CAA Amendments reach almost $2 trillion for the year 2020, a figure 

that dwarfs the direct costs of implementation ($65 billion). The full report is at 

http://www.epa.gov/air/sect812/prospective2.html.

Comment 11: Commenter 17884 urges the EPA to reconsider the proposed emission standards. The 

commenter believes the rule, and other recently promulgated rules will decrease the use of coal for 

electric generation, increase electricity costs by 12-24% in 2016, and cause a net loss of 1.4 million jobs 

by 2020. The commenter states that this will decrease disposable income that would have been spent on 

food, clothes, heat and air conditioning, and healthcare. (Commenter provided a bulleted list available in 

original letter of 8 sets of statistics about different sects of society’s income levels and percentage spent 

on energy costs.) The commenter points out that these increased energy costs endanger public health and 

welfare because of the correlation between wealth and health. The commenter cites multiple legal cases 

in which the decision stated the agency must consider safety impacts of regulations. (Whitman v. Am. 

Trucking Ass’ns, 531 U.S. 457, 496 (2001) (Breyer, concurring), “[p]reindustrial society was not a very

healthy society; hence a standard demanding the return of the Stone Age would not prove ‘requisite to 
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protect the public health.’” See also Am. Trucking Ass’ns v. EPA, 175 F.3d 1027,1052 (D.C. Cir. 1999) 

(EPA must consider whether reducing ozone could have negative health effects), rev’d on other grounds 

sub nom. Whitman v. Am. Trucking Ass’ns, 531 U.S. 457 (2001); CEI v. NHTSA, 956 F.2d 321, 327 

(D.C. Cir. 1992) (agency must consider safety impacts of increasing corporate average fuel economy 

standards), and refusing to consider the indirect and negative health and welfare impacts entailed by 

increased regulatory compliance costs. Cf. International Union v. OSHA, 938 F.2d 1310, 1326 (D.C. 

Cir. 1991) (Williams, J., concurring) (“regulation reduces incomes and thus may exact a cost in human 

lives”).] The commenter explains that increased living standards and disposable income mean people 

can better afford to eat well, heat and cool homes and access healthcare, however, unemployed workers 

and their families and people living on fixed incomes can least afford the consequences of higher energy

costs. The commenter cites Brenner (2002) statistics showing strong research in medical population 

statistics showing that the higher the social status of a person, the lower the probability of illness and 

mortality. A quoted study showed that “Assuming costs are distributed proportional to electricity 

consumption, households with income under $15,000 would incur around 43% of the deaths and 

households over $50,000 would incur 9% of deaths due to increased energy costs.” With unemployment 

rates at 9.2% and effective unemployment at nearly 20%, the commenter believes the EPA should 

pursue policies to reduce regulatory burden and create jobs and increased energy costs will lead to job 

losses and a decrease in general health and welfare. The commenter points out that the EPA’s 

“appropriate and necessary” analysis does not consider the harm to public health that the proposed rule 

represents, nor does the EPA address the potential health disbenefits. The commenter states that low 

cost, reliable energy allows people to live longer and better and human health is threatened by the

proposed rule.

Response to Comment 11: The agency’s proposed rule is meant to require reductions of HAP such as 

Hg, arsenic, and lead and other metals, among other HAP, that are shown to cause serious injury to 

exposed populations. We show the benefits of Hg and HAP emission reductions, along with the 

substantial benefits from reductions in emissions of PM, SO2, and other pollutants in our RIA. 

Populations that are the focus of EO 12898 will benefit from these reductions as shown in the RIA. In 

addition, the increase in electric rates to consumers as shown in the RIA will be 3.1% on average 

nationally by 2015, with some consumers in certain regions seeing increases of 6.3% while other 

consumers in different regions will see increases of only 1.3%. These increases in electric rates may not 

be minimal in some areas of the U.S., but they should be seen in light of the substantial benefits to 

health from the emission reductions that will take place across the country due to this rule.

The agency did not prepare a cumulative impact analysis for the rule for the following reasons: 1) the 

various EO requirements that the agency must comply with require us to estimate impacts specific to 

this rule; 2) decision makers and the public need to know the impacts specific to a particular rule in 

order to judge the merits of the regulation; and 3) estimates specific to a particular rule are more 

transparent than those from a cumulative impact analysis. A cumulative impact analysis lumps several 

regulations together and can potentially mask a high-cost/low benefit regulation among other rules that 

may have large net benefits. By analyzing each regulation separately, the EPA makes clear statements 

about what impacts, costs, and benefits will be generated as a result of this particular regulation.

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.
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Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

Comment 12: Commenter 11107 submits an op-ed which must be viewed at 

http://www.buffalonews.com/editorial-page/viewpoints/article429987.ece due to copywrite restrictions. 

The commenter states that money can be saved by improving air quality and cites (along with 

commenter 17408) the National Research Council report that says hidden costs of burning coal were $62 

to $156 million for each coal plant. These costs are largely due to SO2 emission. The commenter also 

cites a study which estimates emission-related damages from coal-fired power plants to be between 

$0.02 and $1.57 per kWh generated.

Response to Comment 12: The EPA thanks the commenter for the comments. The agency estimates 

substantial benefits from the reduction of HAP and other pollutants from power plants as a result of this 

rule, and these results are presented in the RIA for the rule. What the agency describes as “benefits” are 

similar to the health and other costs described by the commenter.

Comment 13: Commenter 17254 states that removal of air pollutants will improve air quality and public 

health of Georgia communities and cited 79,383 cases of asthma in Fulton County, GA, which earned a 

grade of F for the American Lung Association’s state of the air report. The commenter expects these 

numbers to increase costs to families, communities and tax payers without more air pollution regulation. 

The commenter cites Clean Air Task Force as claiming 1,224 deaths caused by local coal-fired power 

plants, along with 1,710 heart attacks, 1,770 asthma attacks and 752 cases of chronic bronchitis per year, 

at a cost of over $9 billion. The commenter also cited the National Academy of Sciences as saying that 

SO2, NOX and PM emissions from coal-fired power plants account for $62 billion in economic damages 

in 2005.

Response to Comment 13: The agency expects that the benefits of this rule to Fulton County, GA to be 

large, though we have not quantified the impact to this county specifically (it is included in our benefits 

analyses in our RIA, of course). The benefits from reductions of HAP and other pollutants due to this 

rule will be $37 to $90 billion using a 3% discount rate or $33 to $81 billion using a 7% discount rate 

(2007 dollars) in 2015, and this is substantial on its own and relative to the costs of the rule ($9.6 billion 

in 2015, in 2007 dollars).

Comment 14: Commenter 17408 discusses the Fisk and Crawford coal-fired power plants in Chicago. 

The commenter says the Fisk plant was built in 1903 and rebuilt in 1959. The newest turbines at the 

Crawford plant were installed in 1958 and 1961. The commenter says that pollution from these two 
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plants cost neighboring communities $127 million annually in health damages, according to the October 

2011 report by Environmental Law and Policy Center. The commenter went on to cite the Natural 

Resources Defense Council studies that have shown a high benefit to cost ration from environmental 

regulations, with saving in health costs alone surpassing the cost of pollution controls or switching to 

cleaner energy sources. The commenter acknowledges that some jobs will be lost, but also created with 

the proposed rule. The commenter cites Jonathan Levy’s Harvard report which states that 200 lives 

could be saved in the Chicago area if pollution were better controlled. The commenter believes that 

industry must invest in pollution control because it is a fair cost of doing business. The commenter

points out that healthcare costs are being unfairly transferred to people who may not have insurance and 

in the state of Iowa almost two-thirds of children live within 30 minutes of a coal-fired power plant.

Response to Comment 14: The EPA thanks the commenter for their comments. The agency expects 

substantial benefits to Chicago and Iowa residents as a result of this rule as HAP and other pollutants are 

reduced significantly. Estimates of pollution reduction and associated benefits can be found in the RIA

for the rule. In addition, there may be a small net gain in employment nationally associated with this rule 

as shown in the RIA.

Comment 15: Commenter 17409 questions the use of a 7% discount rate for overall benefits. The 

commenter sees a discount rate that high as meaning that future benefits lose half their value every 10 

years. Because the benefits in question are the health and wellbeing of children, the discount rate means 

the worth of children decreases by half every 10 years. The commenter suggests that when calculating 

for generational benefits, the EPA should use a 2.5% discount rate as used when dealing with climate 

change.

Response to Comment 15: The preferred discount rate for benefits estimation by the agency is 3%, 

not 7%. This is explained in the RIA for the rule, where the benefits analysis for this rule is presented. 

Estimates of benefits with a 7% discount rate are prepared in adherence to OMB Circular A-4, which we 

must follow in preparing the RIA for a rule such as this one, and that calls for presentation of costs and 

benefits discounted at both 3 and 7% rates. 

Comment 16: Commenter 17409 states that the cost of pollution is being borne by children and other 

vulnerable people and reports that 1 in 11 children has asthma, resulting in a $56 billion expenditure 

making it so that we can’t afford not to clean our air. The commenter goes on to discuss the B.L. 

England plant, which produces 29 pounds of Hg annually and is built on a bay. The commenter states 

that 1/70 of a teaspoon of mercury is enough to contaminate a 25 acre lake. The commenter also cites 

the February 2011 Harvard Medical Study showing public health costs related to coal are a $175 to $500 

billion annually.

Response to Comment 16: The EPA thanks the commenter for the comment. We agree that polluted air 

can impose detrimental health outcomes such as asthma or other ailments, and the reductions of HAP

and other pollutants associated with this rule will lead to improved public health and thus reduced health 

costs for asthma sufferers. In addition, reductions in Hg will also improve health and ecosystems, as the 

agency shows in the RIA for this rule.

Comment 17: Commenter 18432 supports the proposed standards as fair and equitable and believes 

communities will benefit from the reduction in air pollution no matter if the regulated facilities choose to 

add pollution controls, switch fuels or shut down and pursue renewable energy sources.
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Response to Comment 17: We agree with the commenter that the pollutant reductions from this rule 

will be fair and equitable to the extent we can require them, and do agree that the benefits of the rule will 

be large regardless of how the reductions are obtained. However, we are mindful of the need to 

minimize the economic impacts and costs of this rule along with the need to maximize benefits when 

permissible under the CAA.

Comment 18: Several commenters (18432, 18435, 18541) urge the EPA to proceed with finalizing the 

proposed rule without changing it, as it will prevent more Americans and especially children from 

premature death or chronic illness.

Response to Comment 18: The EPA thanks the commenter for their comments. We will review public 

comments on the proposed rule as required by law and then proceed to prepare the final rule in light of 

information supplied by such comments.

Comment 19: Multiple commenters (18541, 19536, 19537, 19538) say that the full cost of the regulated 

pollutants is not adequately reflected in electricity costs or the cost-benefit analyses. The commenters

state that the cost of the pollution emitted by EGUs is being unfairly placed on the public instead of the 

polluting source. The commenters considered the EPA analyses insufficient because they do not assess 

impacts on wildlife and ecosystems, as they should be under the Biological Assessment, ESA and CAA. 

The commenters urge that analysis be broadened to include valuation of these impacts, even if the 

studies are limited.

Response to Comment 19: The agency recognizes the need to include the effects on wildlife and 

ecosystems in the benefits analyses for our rules. We include these benefits to the extent that it is 

credibly possible according to our understanding of the relevant science in our analyses, and this is 

shown in the RIA for this rule.

Comment 20: Commenter 18961 cites a recent study by the United Nations Environment Program 

which estimated that a reduction by at least 50% of Hg emissions from current levels provides societal 

benefits more than double the implementation cost by the year 2020. The commenter reports that the 

estimate is based on the value of averting human neurotoxic damage, loss of earnings, loss of education 

and opportunity costs. The report showed that even a reduction of 30 to 50% would produce benefits 

beyond the costs.

Response to Comment 20: The EPA thanks the commenter for their comments on Hg benefits. Our 

current estimate of Hg benefits for this rule is $4 to 6 million using a 3% discount rate and $0.5 to $1 

million using a 7% discount rate (2007 dollars) annually in 2015 as shown in the RIA for the rule. We 

intend to refine our estimates of Hg benefits over time and given the availability of new studies. This 

rule as a whole will provide substantial benefits based on the expected reduction in reductions of HAP 

such as Hg and other pollutants.

Comment 21: Several commenters (19536, 19537, 19538) report that the Minnesota Pollution Control 

Agency and Legislative Commission on Minnesota Resources estimate the economic benefits of reduced 

Hg at $212 million based on 50% reduction. This study understates the total economic benefits, 

according to the commenter, because it does not take into account factors such as improved public 

health. Commenters also quote the Harvard School of Public Health estimate that health related 

economic impact of Hg pollution exceeds $5.5 billion and estimates the costs of lost productivity due to 

reduced IQs from Hg pollution at $1.625 billion, the costs of mental retardation due to Hg emission at 

$361 million and the cost of excess cardiovascular disease from Hg exposure at $3.54 billion. 
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Commenters state that a decline in angling of just 25% due to lake and stream fouling by Hg could cost 

Minnesota $706 million annually and jeopardize 25,955 jobs in the state. In Wisconsin, the costs of 

water fouling from Hg could cost $516 million annually and jeopardize 21,459 jobs. Commenters

believe the proposed rule will help improve regional haze and sulfate deposition, lessen acidification of 

lakes and streams and decrease concentrations of lung damage due to air pollution.

Response to Comment 21: The EPA thanks the commenters for the results of these studies, and agrees 

in general with the commenters’ conclusions on reduced regional haze, sulfate deposition and lake 

deacidification, and improved human health related to the reduction of HAP and other pollutants related 

to this rule. For more information on these types of impacts and how the agency’s benefits analysis 

considered them, refer to the RIA for the rule.
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6K - Impacts/Costs: Health Co-Benefits

Commenters: 12267, 14115, 15002, 16404, 16469, 16630, 16826, 16849, 17157, 17254, 17283, 17381, 

17408, 17409, 17620, 17621, 17623, 17637, 17638, 17639, 17648, 17676, 17681, 17689, 17702, 17707, 

17709, 17715, 17716, 17718, 17727, 17730, 17731, 17734, 17736, 17751, 17753, 17754, 17755, 17756, 

17757, 17761, 17765, 17766, 17775, 17799, 17800, 17805, 17811, 17813, 17816, 17843, 17848, 17852, 

17855, 17868, 17871, 17875, 17880, 17882, 17884, 17903, 17912, 17916, 17919, 17921, 17930, 17931, 

18018, 18022, 18027, 18029, 18033, 18034, 18037, 18039, 18421, 18425, 18428, 18432, 18435, 18436, 

18438, 18477, 18478, 18487, 18488, 18498, 18500, 18501, 18502, 18541, 18759, 18961, 18963, 19114, 

19121, 19145, 19580, 19536/19537/19538, 18932, 18023

1. Benefits of the proposed rule outweigh compliance costs.

Comment 1: Several commenters (15002, 17648, 17921, 18541) agree with the EPA that health 

benefits of the proposed rule far outweigh the costs incurred by industries to comply. Commenters 

15002 and 17468 suggest that the estimates of benefits are underestimated due to the lack of 

quantification of benefits due to expected reductions in ground-level ozone. Commenter 17648 argues 

that the EPA employed peer-reviewed and conservative methodology in preparing the benefit-cost 

analysis, and argues that even without the rule, the development of stable and lower-priced natural gas 

supplies will result in the closure of obsolete coal plants. Commenter 17648 further states that critics of 

the EPA’s benefit-cost analysis do not understand the principles of economic impact analysis. The 

commenter states that despite criticism, the inclusion of PM2.5 co-benefits as part of the monetized 

benefits are appropriate because HAP are part of the PM2.5 fraction. Commenter 15002 points out that 

recent data estimate that almost 120 Americans live in counties where NAAQS are not met, though the 

commenter considers these standards insufficient to protect health. Commenter 15002 further notes that 

PM2.5 reduction is projected to occur as the result of improved trapping of primary particulates and 

formation of secondary particulates created by condensation of oxides of sulfur and nitrogen with other 

chemicals or particles in the atmosphere. According to the commenter, these reductions are expected to 

result in a substantial reduction in several diseases, and improve overall mortality. Commenter 17648 

points out several benefits not quantified by the EPA, such as (1) young women who now avoid eating 

fish due to concerns of Hg; (2) reductions in synergistic and additive effects of the pollutants whose 

emissions will be reduced; (3) enhanced ecosystem services; (4) reduced acidification of ecosystems; (5) 

elimination or reduction of a variety of unquantified health impacts, including respiratory effects, 

resulting in increased hospital and emergency room visits, respiratory symptoms, airway hyperresponsiveness, airway inflammation and lung function; (6) reduction of impacts of heavy metals; and 

(7) secondary impacts such as economic benefits to downwind businesses. Commenter 17921 

recommends two studies regarding the benefits of reducing Hg emissions that could be used to better 

estimate health benefits of the rule: (1) Rice, G., & Hammitt, J. K. (2005). Economic valuation of human 

health benefits of controlling mercury emissions from U.S. coal-fired power plants; and(2) Trasande, L., 

Landrigan, P. J., & Schechter, C. (2005). Public health and economic consequences of methylmercury

toxicity to the developing brain. Environmental Health Perspectives. doi: 10.1289/ehp.7743.

Commenter 18541 argues that the benefits to wildlife were not fully accounted for, saying that the EPA 

should formally consult the U.S. Fish and Wildlife Service and the National Marine Fisheries Service to 

set the standards strictly enough to protect wildlife and ecosystem health. Commenter 17648 suggests 

that the agency overestimated the costs of compliance, partly due to technological innovation that is not 

considered. The commenter provides the example of the acid rain program, in which according to the 

RIA, the cost of implementing the program was 83% lower than original estimates.
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Response to Comment 1: This rule is expected to achieve important non-Hg HAP benefits. However, 

monetization of non-Hg HAP benefits is limited by currently available data and methods. In summary, 

monetization of the benefits of reductions in cancer incidences requires several important inputs, 

including central estimates of cancer risks, estimates of exposure to carcinogenic HAP, and estimates of 

the value of an avoided case of cancer (fatal and non-fatal). Due to methodology and data limitations, 

we did not attempt to monetize the health benefits of reductions in HAP in this analysis. Instead, we 

provide a qualitative analysis of the health effects associated with the HAP anticipated to be reduced by

these rules. The EPA disagrees that the health benefits of non-Hg HAP could never be measured. A well 

designed epidemiological study could measure these benefits. The EPA remains committed to 

improving methods for estimating HAP benefits by continuing to explore additional concepts of 

benefits, including changes in the distribution of risk. Quantitative estimates of these benefits are 

provided to the extent possible, and our limited ability to monetize these benefits does not indicate that 

they are non-existent or less important.

Our treatment of these benefits follows guidance set by OMB Circular A-4 (pp. 26-27, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Sound quantitative estimates of benefits and costs, where feasible, are preferable to qualitative 

descriptions of benefits and costs because they help decision makers understand the magnitudes of the 

effects of alternative actions. However, some important benefits and costs (e.g., privacy protection) may

be inherently too difficult to quantify or monetize given current data and methods. You should carry out 

a careful evaluation of non-quantified benefits and costs. Some authoritiesrefer to these non-monetized 

and non-quantified effects as “intangible.”“

It is also in line with EPA’s Guidelines for Preparing Economic Analyses (p. 11-3, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html).

“Benefits and costs that cannot be monetized should, if possible, be quantified (e.g., expected number of 

adverse health effects avoided). Benefits and costs that cannot be quantified should be presented 

qualitatively (e.g., directional impacts on relevant variables).”

2. Benefits of the proposed rule do not outweigh compliance costs.

Comment 2: Many commenters (14115, 16469, 17638, 17639, 17681, 17702, 17716, 17730, 17731, 

17751, 17753, 17754, 17756, 17757, 17761, 17765, 17799, 17800, 17813, 17855, 17868, 17884, 17919, 

17930, 17931, 18033, 18034, 18037, 18428, 18488, 18963, 19121, 19580, 18023) suggest that the 

benefits of the proposed rule do not outweigh the cost. Multiple commenters (14115, 16469, 17638, 

17681, 17702, 17716, 17730, 17731, 17751, 17754, 17757, 17761, 17765, 17800, 17813, 17855, 17868, 

17930, 18033, 18034, 18037, 18428, 18488, 18023) state that most of the benefits would be due to 

PM2.5 co-benefits, and that the Hg benefits would amount to $6 million or less, far below the estimated 

$10.9 billion annual costs. Commenter 18037 states that regulations focus on incrementally smaller 

emission reductions and with increased costs, and thus regulations are less and less justified. Several 

commenters (17639, 17799, 17912) state that the benefits of the proposed rule do not justify the costs 

since the predicted risks for air toxins are approaching or are less than 1 in 1 million and fine particulate 

matter is regulated under the ambient air quality standards of the CAA. Commenter 17799 argues that 

the analysis of chromium emissions was flawed, in that hexavalent chromium, a carcinogen, may be 

converted to less toxic forms by the time it reaches the target population; thus the corresponding 

increased cancer risk from 0.33 (lifetime cancer risk to average person) to 0.330001 “is so minimal that 

it could not be observed in any health effects study that might be conducted.” Similarly, commenter 
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18034 states that the cancer risks from nickel and hexavalent chromium emissions are within limits 

previously considered acceptable by the EPA. Commenter 17799 also points out that the “EPA states 

that non-cancer risks for the non-mercury HAP for coal units never exceeded a non-cancer hazard index 

of 0.5 whereas the level of concern would be 1.0...[the EPA’s definition of hazard index states that] 

exposures equal to or below [a hazard index] of 1.0...likely will not result in adverse non-cancer health 

effects over a lifetime of exposure and would ordinarily be considered acceptable.” Several commenters 

(17639, 17754, 17757) point out that the proposed rule duplicates existing regulations and will exhaust 

state and federal government resources.

Response to Comment 2: The EPA disagrees with commenters that the benefits of the rule do not 

exceed the costs. The benefits of this rule encompass the benefits of Hg reductions and co-benefits to 

health achieved via PM2.5 reductions. As the analyses presented in the RIA for the rule show, the 

benefits outweigh the costs by a large margin. Although the monetized benefits of reducing Hg 

emissions are not large, those benefits are also not equally distributed across the population. As the 

sensitivity analysis shows, some populations, including low-income African Americans and some 

Native American populations, may receive a disproportionate benefit, and the distributional aspects of 

the benefits may help to justify the costs of the rule. Furthermore the analysis depended on using a less 

sensitive endpoint (IQ) of neurological impacts of Hg exposure as noted by the SAB which leads to 

underestimation of the benefits. Additionally many other impacts of Hg emissions were not quantified 

including impacts on ecosystems and wildlife especially fish, birds both fish and insect eating, and 

mammals. Other HAP controlled by the MATS rule were likewise not quantified due to data, resource 

and methodological limitations. Even if we were able to fully monetize the public health benefits of

reducing exposure to Hg and other HAP, it is likely that the PM benefits would continue to dominate the 

total monetized benefits due to the size of the exposed population and the severity of the associated 

health effects. Despite our inability to provide monetized benefits of HAP emission reductions, the total 

monetized benefits exceed the estimated costs of the rule by a substantial margin, even when taking 

uncertainty into account.

Consideration of PM2.5 health co-benefits expected as a result of direct PM2.5 and SO2 emission 

reductions is directed by OMB Circular A-4 (p. 26, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Your analysis should look beyond the direct benefits and direct costs of your rulemaking and consider 

any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of 

the rule that is typically unrelated or secondary to the statutory purpose of the rulemaking (e.g., reduced 

refinery emissions due to more stringent fuel economy standards for light trucks) while a countervailing 

risk is an adverse economic, health, safety, or environmental consequence that occurs due to a rule and 

is not already accounted for in the direct cost of the rule (e.g., adverse safety impacts from more 

stringent fuel-economy standards for light trucks).”

It is also directed by the EPA’s Guidelines for Preparation of Economic Analyses (p. 11-2, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html):

“An economic analysis of regulatory or policy options should present all identifiable costs and benefits 

that are incremental to the regulation or policy under consideration. These should include directly 

intended effects and associated costs, as well as ancillary (or co-) benefits and costs.”

In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a 

regulatory action, to the extent feasible. We further note that if we were able to fully monetize all of the 
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benefit categories, the benefits would exceed the costs by an even greater amount than we currently

estimate.

3. Methods used to calculate benefits.

Comment 3: Several commenters (17623, 17639, 17799, 18428, 18963) suggest the EPA is 

overestimating the benefits of Hg emission reductions associated with the rule. Commenters 17623 and 

18963 state that recent estimates of emissions from coal-fired units show a substantial reduction in Hg 

from 2000 to present. Commenters 17639 and 17799 quote a risk science consulting firm statement that 

the health benefits attained by Hg reductions could “never be measured or observed in real life.”

Commenter 17799 argues further that the “public health benefits from HAP reductions are minimal,”

stating that the rule would have a negligible impact on mercury exposures in most of the U.S. because 

Hg exposures are dominated by non-U.S. sources. Commenter 18428 suggests that the improvement of 

500 IQ points across the entire U.S. population estimated in the benefits calculations is negligible and 

should not be considered. Similarly, commenter 17623 states that for Hg, some of the EPA’s health 

effects could not be monetized, such as IQ improvements. Commenter 17799 states that the EPA 

attempts to justify regulation of non-Hg HAP based on environmental benefits, which is “not a criterion 

Congress gave EPA as a basis for regulation under 112(n)(1)(A) and therefore is an irrelevant 

consideration.”

Response to Comment 3: The EPA disagrees with commenters that the benefits of Hg emission 

reductions associated with this rule were overestimated. In fact, the EPA believes that the estimates 

presented in the RIA are an underestimate because the EPA was not able to analyze the impacts using 

the most sensitive endpoints for human health. According to the SAB’s review of the TSD for this rule 

“The loss of IQ points is likely to underestimate the impact of reducing methyl mercury in water bodies. 

The reason is that IQ score has not been the most sensitive indicator of methylmercury’s neurotoxicity in 

the populations studied. As noted in the TSD, in the Faroe Island study the most sensitive indicators 

were in the domains of language (Boston Naming), attention (continuous performance) and memory

(California Verbal Learning Test), neuropsychological tests that are not subtests of IQ tests and are not 

highly correlated with global IQ. In the Seychelles study, the Psychomotor Development Index has been 

most sensitive measure and, while this is a component of the Bailey Scales of Infant Development, it is 

not highly correlated with cognitive measures.”

The EPA also would point out that the estimates only use self-caught freshwater fish, including saltwater 

fish consumption would increase the estimates. In addition many of the benefits of Hg reductions were 

not quantified including the many significant adverse impacts to wildlife and ecosystems.

Comment 4: Several commenters (17702, 17751, 18018, 18033, 18500) express concerns that the 

method the EPA used to monetize benefits produces unreasonably large estimates. Commenter 18033 

cites the EPA’s counting of mortality estimates for PM2.5 exposures below the lowest measured level 

(LML) as a major concern. Commenter 18033 points out that the EPA has never set a NAAQS at a level 

as low as the LML because the EPA believed that it was not required to protect public health; however, 

the commenter argues that using the LML in this rule drastically overestimates mortality associated with 

low levels of PM2.5.

For several commenters (17702, 18018, 18500), the specific concern is that using the value of statistical 

life (VSL) based on the public’s willingness to pay (WTP) results in a VSL of $8 million per person. 

The VSL is used regardless of the time a death is postponed, while the annual value for GDP per person 

is around $42,000. Commenters point out that even if the death is postponed for 10 years by the 
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proposed rule, the GDP value would be around 5% of the EPA VSL. Commenter 18018 discusses 

calculating the VSL to estimate the value of remaining life, so that a 2-year-old would have a higher 

VSL than an 80-year-old, since people with shorter life expectancy may be less willing to devote 

resources to reduce their risk of premature death. Commenter 17751 states that the mortality risk 

reduction is derived from a meta-analysis of 26 contingent valuation and labor market studies from 1982 

to 1991, but does not adequately discuss the need to improve WTP valuations or present limitations of 

the estimate. For example, commenter 17751 points out that the EPA does not cite studies critical of the 

meta-analysis or the fact that many labor market studies in the meta-analysis reflect wage differentials

which arise from differences between occupations in terms of risk of death in accidents. Commenter 

17751 questions the EPA’s lack of consideration of whether to apply values derived from contexts in 

which risk is immediate to environmental policy context in which risk involves long-term consideration. 

Commenter 17751 also points out the lack of consideration of the importance of selection bias in the 

meta-analysis. Commenter 17751 states that the EPA’s chosen value for mortality risk reduction is 

based on an average of findings, but the studies are not a random sample of studies but rather those 

selected by the analysis author to satisfy certain criteria not revealed. The commenter further states that 

in comparison to the EPA’s simple average of 26 studies that yielded a value of $6.2 million (2000 

dollars), one comparative study (Giles, et al.) found that correction for publication selection bias yielded 

a value of $2.74 million (2000 dollars). The commenter requests that the EPA include a discussion of 

alternative meta-analyses of WTP studies. The commenter recommends the following:

1. Bellavance, F., Dionne, G., Lebeau, M. 2009. The Value of a Statistical Life: A meta-analysis 

with a mixed effects regression model. Journal of Health Economics 28: 444-464.

2. Bowland, B.J., Beghin, J.C. 2001. Robust Estimates of the Value of a Statistical Life for 

Developing Countries. Journal of Policy Modeling 23: 385-396.

3. De Blaeij, A., Florax, R.J.G.M., Rietveld, P., Verhoef, E. 2003. The Value of Statistical Lifein 

Road Safety: A meta-analysis. Accident Analysis andPrevention35: 973-986.

4. Dionne, G., Michaud, P.C. 2002. Statistical analysis of value-of-life estimates using hedonic 

wage method. Working Paper 02-01. Risk Management Chair, HEC Montréal.

5. Kochi, I., Hubbell, B., Kramer, R. 2006. An Empirical Bayes Approach to Combining and 

Comparing Estimates of the Value of a Statistical Life for Environmental PolicyAnalysis. 

Environmental and Resource Economics 34:385-406

6. Lindhjem, H., Navrud, S., Braathen, N.A. 2010. Valuing Lives Saved From Environmental, 

Transport and Health Policies: A meta-analysis of stated preference studies. Working Party on 

National Environmental Policies, OECD, February.

7. Liu, J.T., Hammitt, J.K., Liu, J.L. 1997. Estimated Hedonic Wage Functions and Value of 

Statistical Life in a Developing Country. Economics Letters 57(3):353-358.

8. Miller, T.R. 2000. Variations Between Countries in Values of Statistical Life, Journal of 

Transport Economics and Policy 34(2): 169-188.

9. Giles, Doucouliagos and Stanley have statistically assessed the effect of selection bias on metaanalyses of the value of mortality risk reduction, and have found that correction for selection bias 

reduces the average value by 70 to 80 %.

Response to Comment 4: The EPA disagrees with commenters that the method the EPA uses to 

monetize PM2.5 benefits produces unreasonably large estimates. The EPA estimates health impacts of 

PM2.5 below the LML, as evidence suggests that there is no discernable threshold for long-term PM2.5

mortality (e.g., Roman et al. 2008, Schwartz et al. 2008, Krewski et al. 2009). The EPA methods for 

quantifying health benefits of emission reductions are based on the best available peer-reviewed science 

and methods that have withstood scrutiny from the EPA’s independent SAB, the National Academy of 

Sciences, and continuous interagency review. Note that NAAQS are set at a level deemed by the EPA 
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Administrator to be protective of public health within an adequate margin of safety, and are not set at a 

level of zero risk. Further, analyses conducted for the proposed rule demonstrated that while 30% occur 

above the LML (10 ug/m3) of the Laden et al. (2006) study, 86% of PM2.5 health benefits occurred 

above the LML (7.5 ug/m3) of the Pope et al. (2002) study. We note that a more recent extended reanalysis of the Pope et al. (2002) study found significant health impacts of PM2.5 down to a lower LML

(5.8 ug/m3; Krewski et al. 2009). Therefore, we believe estimation of health effects below the LMLs in 

the Laden et al. (2006) and Pope et al. (2002) study is justified. However, we do note that as we model 

mortality impacts among populations exposed to levels of PM2.5 that are successively lower than the 

LML of each study our confidence in the results diminishes. Therefore, we continue to include statistics 

in the final RIA (as was done in the RIA for the proposed rule) showing the percentage of health impacts 

occurring above these levels for readers to understand the effect of this methodological decision.

With respect to the method the EPA uses to monetize benefits, according to standard welfare economics, 

the economic value of a reduction in mortality risk is the maximum amount an individual would be 

willing to pay for it. The VSL is a representation of WTP values in that it captures the average rate at 

which people are willing to pay for very small changes in mortality risks (say, 1 in 10,000 per year). The 

VSL does not represent the value of avoiding or postponing certain death for any particular individual. 

By convention, estimates of these willingness-to-pay values are typically normalized by the change in 

risk. For example, if on average workers are willing to sacrifice $800 in additional annual pay for jobs 

that have a reduced fatality risk of 1 in 10,000 per year, then the estimated VSL would be $800 × 10,000 

= $8 million. The estimated annual WTP per exposed individual for the average risk reduction under this 

rule is well below the annual value for GDP per person of $42,000.

On calculating VSL to estimate the value of remaining life, the EPA has explored the issue of remaining 

life expectancy and its potential effect on WTP in the past and has, in fact, received guidance from the 

SAB on the matter. The SAB’s full response is available in their October 12, 2007 guidance to the EPA 

on valuing mortality risk reductions, pages D-10 and D-11. To summarize, the SAB points out that 

economic theory is ambiguous on how people’s willingness to pay to reduce mortality risks should 

change over their lifetime, leaving it, therefore, as an empirical matter. The judgment of the SAB, 

however, is that the empirical literature is not advanced enough to provide clear guidance on how age 

and health status affect willingness to pay to reduce mortality risks. The recommendation of the SAB is 

to use an age-independent valuation of mortality risk reductions. 

.http://yosemite.epa.gov/sab/sabproduct.nsf/02ad90b136fc21ef85256eba00436459/4128007E7876B8F0

852573760058A978/$File/sab-08-001.pdf

Regarding the limitations of WTP, the 26 studies underlying the EPA’s guidance for WTP for mortality

risk reductions come from Viscusi, 1992, which describes the selection criteria. Viscusi, 1992, is 

described as the source for these studies when the EPA originally used the set in The Benefits and Costs 

of the Clean Air Act: 1970 to 1990 (US EPA, 1997, page I-3). Most of the studies in this set of literature 

are based on wage differentials for workplace risks. Although these estimates cannot be taken as precise 

values for mortality risk reductions from environmental policies, their usefulness for informing 

environmental policy analysis has been recognized by the Environmental Economics Advisory 

Committee of EPA’s SAB (SAB-EEAC) (US EPA SAB 2000). The difficulties and limitations of these 

estimates for environmental policy are described in our Guidelines for Preparing Economic Analyses

(US EPA 2010).

The agency has examined multiple meta-analyses published in the economics literature since 

promulgating our guidance in the Guidelines for Preparing Economic Analyses in 2000. This effort 

includes a report from leading experts in statistical meta-analysis (USEPA 2006). The agency has 
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consulted with the SAB-EEAC on how to evaluate and apply meta-analyses, and how the agency should 

revise its own meta-analysis methodology. Although the SAB-EEAC did not recommend that the EPA 

adopt any of the existing meta-analyses, the Committee made several recommendations on how the 

agency should conduct its own analysis, including details on selection criteria, and how to incorporate 

results from different methods and in different contexts (US EPA SAB 2007, 2011). Based on these 

advisories the EPA is now reviewing the existing literature and developing methods to inform new 

guidance on valuing reductions in mortality risks in agency economic analyses. This effort will include 

considerations of many potential biases in the resulting estimates, including issues such as the 

publication bias concern described in the Giles, et al. study.

Comment 5: Several commenters (16469, 18500, 17621, 17283) suggest that the uncertainty analysis is 

insufficient. Commenter 17621 argues that “the only quantitative uncertainties presented are those for 

the particular dose-response estimates taken from the two studies cited by EPA. Other uncertainties are 

listed in several tables, with no attempt to quantify them.” Several commenters (16469, 17621, 17283, 

18500) suggest that the differential toxicity of PM species needs to be considered when calculating 

potential health benefits of emissions reductions to fully assess the impacts, and this issue should be 

considered in the uncertainty analyses.

Response to Comment 5: The EPA disagrees with these commenters that the uncertainty analysis is 

insufficient. We conduct several different types of analyses that examine the effects of the most 

important methodological choices on results. For example, we estimate mortality impacts using health 

effect estimates garnered from an EPA-sponsored expert elicitation (Roman et al. 2008). The experts in 

the elicitation produced a range of effect estimates that span from smaller than the effect estimate by 

Pope et al. (2002) and larger than the effect estimate by Laden et al. (2006). The expert elicitation is one 

method of characterizing uncertainty in PM-related mortality. Although we are unable to quantify the 

impact of all sources of uncertainty, we examine the effect of assuming a health effect threshold at the 

lowest measured level in the epidemiology studies. We also conduct sensitivity analyses examining 

different income elasticity assumptions. The uncertainties that are not quantifiable are listed in tables to 

acknowledge their possible influence on estimated benefits.

4. Criteria co-benefits should not be considered in analysis.

Comment 6: Many commenters (17702, 17716, 17751, 17753, 17754, 17765, 17775, 17799, 17813, 

17855, 17912, 17919, 18034, 18428, 18488, 18498, 18963, 19114, 18023) question the use of criteria 

co-benefits to justify HAP regulation. They suggest that the inclusion of co-benefits is contrary to the 

original intention of reducing Hg emissions, because the reductions of PM2.5 emissions can be expected 

to be achieved through other regulations. Commenter 17765 states that the little incremental health 

benefits from the proposed rule do not justify its economic impacts. Commenter 17716 estimates that 

without co-benefits, the “net benefits” of the proposed rule would be negative $42,000,000,000 to 

negative $130,000,000,000. Commenters 17716 and 17799 question the intent of the CAA or legislative 

history to have co-benefits from criteria pollutants regulated under a different CAA regulatory scheme 

serve as the driving force to curb HAP emissions through MACT regulation. Commenters 17754 and 

18034 acknowledge that benefits beyond those from Hg emissions reductions will be up to $130 billion 

annually, but again, since these benefits come from co-benefits from reducing PM2.5 emissions, consider 

the cost-benefit analysis supporting regulation of Hg emission to be flawed. Commenter 17775 attached 

a memo by Dr. Anne Smith providing technical comments on the RIA for the proposed rule and 

discussing the use of co-benefits. The commenter states that PM2.5 benefits are attributable to the control 

of HAP acid gases, yet public exposures to HAP acid gas emissions were found to be far below the 

reference concentration levels for those HAP, which the EPA defines as being without an appreciable 
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risk. Commenters 17912 and 17919 question the EPA’s legal justification for the proposed rule that 

argues non-Hg HAP must be regulated. Commenter 17719 points out that there is a separate program for 

the regulation of PM2.5, and the EPA does not address whether there is a less expensive way to achieve 

the same benefits attributed to the proposed rule, such as those included in the PM2.5 program. 

Commenter 17719 believes this is pertinent, since the EPA is mandated to find the most cost effective 

solution for regulatory priority.

Multiple commenters (18023, 16469, 17621, 17718, 17751, 17761, 17800, 17816, 17919, 17855, 18033, 

18963) find the EPA calculation of PM2.5 NAAQS benefits to be incorrect because the commenters say

the EPA is either double counting potential benefits of the NAAQS program in the calculation of 

benefits from the proposed rule, or relying on the supposition of health benefits from any PM reduction 

anywhere. Commenter 18023 considers this an unfounded supposition that both the EPA and the EPA 

science advisors have rejected as too uncertain to adopt when setting PM2.5 NAAQS. Commenter 18023 

points out that if these PM2.5 benefits are disregarded, the monetized benefits for the proposed rule drop 

to $0.576 billion, from CO2 reductions and HAP reductions. The commenter states that this change 

means the cost of the proposed rule would exceed the monetized HAP benefits by a factor of at least 

1,800.

Comment 7: Numerous commenters (16469, 16849, 17638, 17681, 17702, 17730, 17799, 17848, 

17919, 18018, 18033, 18500, 18023) estimate that 90-99% of the benefits the EPA attributes to the 

proposed rule actually come from PM2.5 reductions from reduced emissions of SO2, which is not a HAP, 

and did not indicate benefits from acid gas reductions. Commenters believe the same benefits would be 

delivered by other CAA rulemakings including PM, SO2 and ozone NAAQS and the Cross-State Air 

Pollution rule. Commenter 16849 points out the limitations of the proposed solutions due to the fact that 

multiple emission control equipment do not always work together harmoniously following a retrofit. 

Commenter 17702 believes that proposing air toxic limits more restrictive than those envisioned under 

CAMR would result in greater costs without commensurate benefits to the public. Commenter 17730 

believes the proposed rule should be based on the rule’s ability to reduce the emissions of HAP that 

provide a public health benefit after imposition of the CAA requirements and the associated public 

health and environmental benefits from those reductions. Commenter 17848 points out that the 

estimated health benefits from the proposed rule were compared with the estimated health benefits from 

the Transport Rule SO2 reductions and the number of avoided outcomes per 1,000 tons of SO2 reduction 

is nearly identical for 2014 and 2016. However, the commenter points out that ambient PM2.5 levels 

should decrease between those 2 years as a result of the Transport Rule reductions. Therefore the 

commenter says that since baseline emissions should be lower after Transport Rule implementation, a 

smaller quantity of SO2 reductions would be achieved by the proposed rule. Several commenters (18023, 

17638, 17681) state that over 80% of the estimated PM2.5 health benefits are assumed to occur in areas 

that meet the levels the EPA is currently considering for a new PM2.5 NAAQS, and thus should not be 

considered under this rule. Commenter 18500 cautions that the EPA’s monetizing benefits estimate due 

to CO2 reductions should be considered carefully because a of the questions associated with climate 

change.

Comment 8: Many commenters (16469, 17621, 17623, 17637, 17681, 17702, 17751, 17761, 17775, 

17800, 17855, 17884, 17919, 18033, 18963, 18023) note that the PM2.5 co-benefits to which many of the 

proposed rule’s benefits are attributed are mainly based on emission reductions in areas already 

achieving the annual PM2.5 NAAQS or are being addressed by other rules. As such, commenters 17623 

and 17855 ask that the EPA explain what additional PM benefits are derived from the proposed rule. 

Commenter 17681 considers the costs of the proposed rule to be very low and not outweighed by the 

“contrived” benefits. Commenters 17919 and 18023 state that the NAAQS set a level of PM2.5 that the 
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EPA found to be sufficient to public health and welfare with an adequate margin of safety and areas in 

attainment with this level are already safe from health risks. Some commenters (17855, 17621, 17637, 

17718, 17761, 18963) state that attainment of the NAAQS for PM2.5 is already being addressed on both 

the local and regional basis through SIPs and CSAPR. Commenter 18033 points out that the EPA “is 

preparing to propose a new [lower] PM2.5 NAAQS...[but] until it does so...it is inappropriate for EPA to 

adopt rules based on claimed benefits below the current NAAQS level.” Commenter 17621 requests that 

the EPA clearly articulate the individual benefits to all of its pending air rules to clarify the issue of 

double counting benefits.

Comment 9: Commenter 17876 states that the EPA’s attribution of 90% of the health benefits under 

this rulemaking to justify the further regulation of PM is problematic based on recent studies. See, e.g., 

Koop, Gary, Ross McKitrick and Lise Tole (201 0) “Air Pollution, Economic Activity and Respiratory

Illness: Evidence from Canadian Cities 1974-1994” Environmental Modeling and Software 2010, doi: 

10.1 016/j.envsoft.201 0.01.01 0; Gary Koop, Lise Tole, “Measuring the Health Effects of Air Pollution: 

to what extent can we really say that people are dying from bad air?” Journal of Environmental 

Economics and Management (2004), 30-54.

Comment 10: Commenter 18023 believes the EPA’s flawed cost-benefit analyses makes it difficult to 

assess the proposed rule under UMRA and EO 12866, which require the EPA to assess both the costs 

and benefits of the proposed rule. The commenter believes the EPA is double counting benefits 

associated with PM2.5 in its RIA, and therefore has failed to meet its obligations to promulgate a 

regulation that imposes the least burden on society.

Response to Comments 6 - 10: On inclusion of PM2.5 health co-benefits, the EPA disagrees with 

commenters that PM2.5 health co-benefits should be excluded in the estimation of benefits expected by

MATS. Accounting for ancillary benefits is standard practice in benefit-cost assessment since these 

benefits are a consequence of the rule, regardless of the rule’s intended purpose (as noted also by

commenter 17768). As such, the EPA estimates all of the anticipated costs and benefits associated with a 

regulatory action, to the extent feasible, for the purpose of determining the likely impacts, not to justify

an action. This rule is expected to achieve substantial PM2.5 health benefits resulting from primary PM 

and SO2 emission reductions, and these co-benefits are thus an important category to quantify.

Consideration of ancillary benefits in benefit-cost analysis is directed by OMB Circular A-4 (p. 26, 

available at: http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Your analysis should look beyond the direct benefits and direct costs of your rulemaking and consider 

any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of 

the rule that is typically unrelated or secondary to the statutory purpose of the rulemaking (e.g., reduced 

refinery emissions due to more stringent fuel economy standards for light trucks) while a countervailing 

risk is an adverse economic, health, safety, or environmental consequence that occurs due to a rule and 

is not already accounted for in the direct cost of the rule (e.g., adverse safety impacts from more 

stringent fuel-economy standards for light trucks).”

It is also directed by the EPA’s Guidelines for Preparation of Economic Analyses (p. 11-2, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html):

“An economic analysis of regulatory or policy options should present all identifiable costs and benefits 

that are incremental to the regulation or policy under consideration. These should include directly 

intended effects and associated costs, as well as ancillary (or co-) benefits and costs.”
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In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a 

regulatory action, to the extent feasible. We further note that we were unable to monetize other 

important benefits, including health benefits of ozone reductions, additional PM2.5 health benefits, and 

direct health benefits of reducing SO2. If we were able to fully monetize these benefits, the benefits 

would exceed the costs by an even greater amount than we currently estimate.

Regarding commenters’ assertion that the EPA is double-counting PM2.5 health benefits achieved by 

MATS with those achieved by other regulations and NAAQS, the EPA disagrees with these commenters 

that the quantified PM2.5 health benefits are double-counted with the health benefits achieved by other 

regulations. The EPA’s standard practice for its rules is to estimate, to the extent data and time allow, all 

benefits of the emissions reductions achieved by a rule beyond control requirements for other rules. If 

this rule was duplicative with other rules, then there would be no additional costs or benefits attributable 

to this rule.

When the EPA estimates the benefits for rules like MATS, we include other rules such as the CSAPR in 

the “baseline.” Any emission changes expected as a result of MATS are additional emission reductions 

beyond those regulations (e.g., CSAPR) that were considered to be part of the baseline. Therefore, the 

benefits from particle reductions are not double-counting – they are real health benefits from emissions

reductions achieved by MATS alone.

Further, the PM2.5 health benefits expected from this rule are not double-counted with benefits estimated 

in the NAAQS RIAs. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air 

quality standard nationwide based on an array of emission control strategies for different sources. In 

short, NAAQS RIAs hypothesize, but do not predict, the control strategies that states may choose to 

enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or 

benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the 

costs and benefits of other regulations that result in specific costs of control and emission reductions. 

However, some costs and benefits estimated in this RIA account for the same air quality improvements 

as estimated in the illustrative PM2.5 NAAQS RIA.

Regarding quantification of health benefits below the PM2.5 NAAQS, the EPA notes that in 

implementing these rules, emission controls may lead to reductions in ambient PM2.5 below the PM 

NAAQS in some areas. It is important to emphasize that NAAQS are not set at a level of zero risk. 

Instead, the NAAQS reflect the level determined by the Administrator to be protective of public health 

within an adequate margin of safety, taking into consideration effects on susceptible populations based 

on the scientific literature available at the time the standard is set. Although benefits occurring below the 

standard may be less certain than those occurring above the standard, the EPA considers them to be 

legitimate components of the total benefits estimate.

In response to the comment on climate benefits, we use best available scientific information and 

methods in monetizing the climate benefits of this rule and include a careful discussion of the associated 

uncertainties and limitations.

5. Health impacts are minimal and are not thoroughly investigated.

Comment 11: Some commenters (17621, 17689, 17775, 18033, 18963, 18023) argue that utility acid 

gas emissions (primarily HCl) cause insignificant harm. Commenter 18023 states that the conclusion 

that HCl could exacerbate ecosystem acidification is speculative and unsubstantiated. Commenters 

18033 and 18963 point out that the EPA never provided a finding of public health concern to regulate 
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non-Hg HAP, and provides no evidence that “more stringent control of acid gases would benefit 

ecosystems other than some vague referencing of the possibility.” Commenters 17775 and 18033 argue 

that the predominant HAP in the acid gas group, HCl, poses no significant potential for exceeding the 

chronic RfC value according to the EPA’s own calculations, even though the PM2.5 benefits in the RIA 

are solely attributable to the control of HAP acid gases. Commenters 17621 and 18033 argue further that 

because HCl is a very minor contributor to all acidification of water bodies, the EPA’s need for 

regulating acid gases from EGU’s is insignificant. Commenter 17621 points out that because of this, 

HCl emissions have “not been the focus of past U.S. assessments of acidification.”

Response to Comment 11: Based on recent peer-reviewed research including Evans et al. (2011), acid 

gases can significantly contribute to acidification. The paper presents experimental results that show 1) 

that HCl is highly mobile in the environment, transferring acidity easily through soils and water, 2) that 

HCl can transport longer distances than previously thought (given its presence in remote ecosystems, 

and 3) that it can be a larger driver of acidification previously thought. In 2009 the EPA published a 

comprehensive risk assessment of acidification effects of nitrogen and sulfur deposition and in 2011 

published a Policy Assessment based on the findings in the Risk Assessment (both documents are 

available at: http://www.epa.gov/ttn/naaqs/standards/no2so2sec/index.html). Given the extent and 

importance of the sensitive ecosystems evaluated in the review of nitrogen and sulfur deposition any 

substance that contributes to further acidification must be considered to be affecting the public welfare.

Comment 12: Several commenters (16469, 17621, 17715) take issue with the use of the two primary

health studies used in the benefits analysis (Pope et al., 2002; Laden et al., 2006). Commenter 17715 

argues that the studies take a simplistic approach to their calculations (grouping all PM components 

together) even though there is evidence that PM components do not all have equal health significance. 

Commenter 17621 argues that because the dose-response function for PM2.5 relied on two studies and 

not a full review of the published literature, it is flawed and only reflects a subset of the literature. 

Commenter 17621 also takes issue with the EPA’s choice of dose-response function from the Laden 

study; the commenter argues that the EPA should have used only the most recent mortality risks instead 

of the risk for a combined time period, because the more recent time period is more relevant to the 

present. Commenter 17621 points out that had the EPA used the most recent mortality risk, the benefit 

estimates would be much lower. Commenter 17621 disagrees with the EPA’s statement that some 

studies were excluded from analysis due to having study populations of a “selective nature,” because the 

commenter argues that this is true of all studies, including the Pope and Laden studies. Commenter 

17621 argues that the inclusion of other studies would be appropriate and could change the estimated 

benefits. Commenter 17621 argues further that the methodology used in these studies appears flawed, 

particularly in the methods used to estimate mortality benefits. They state that this could overestimate 

the benefits associated with changes in PM concentrations, and thus these studies should not be used 

until the flaws are remedied.

Response to Comment 12: The EPA disagrees that the methodology used to estimate PM2.5 health 

impacts is flawed. The EPA methods for quantifying health benefits of emission reductions are based on 

the best available peer-reviewed science and methods that have withstood scrutiny from the EPA’s 

independent SAB, the National Academy of Sciences, and continuous interagency review. We note that 

the evidence on differential toxicity of PM2.5 components and mixtures is currently inconclusive. We 

therefore follow the advice of the EPA’s Clean Air Science Advisory Committee (Hammitt et al. 2010, 

available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/fedrgstr_activites/2nd%20Prospective%20812%20Study!Op

enDocument&TableRow=2.3#2.), which concluded that “Although the possibility of differential toxicity

among PM2.5 components could be an important issue, the Council concludes that the state of the 
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knowledge does not permit a useful sensitivity analysis at this time” (p. 6). In response to commenter 

17621, we note that we use concentration-response factors from the broadest time periods available to 

take advantage of the available data most comprehensively. The choice of relative risk estimates from 

Pope et al. (2002) and Laden et al. (2006) is supported by the EPA Advisory Council on Clean Air 

Compliance Analysis (Hammitt et al. 2010, available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/9288428b8eeea4c885257242006935a3/59e06b6c5ca665978

52575e7006c5d09!OpenDocument&TableRow=2.3#2.):

“Overall, the HES finds the EPA analyses, data choices, and methodologies to be sound. 

The EPA bases its estimates of the mortality benefits of reducing fine particulate matter 

(PM2.5) on data analyzed from two large, long-running landmark studies on the health 

effects of air pollution, the Harvard Six Cities Study and the American Cancer Society 

(ACS) Cancer Prevention Study (CPS). The HES finds the selection of these cohort 

studies as the underlying basis for PM mortality benefit estimates to be a good choice” (p. 

1).

We further note that we also estimate mortality using functions derived by 12 experts in an EPAsponsored expert elicitation (Roman et al. 2008). The Pope et al. (2002) and Laden et al. (2006) studies 

were found to be near the 25th and 75th %iles of the mortality effect estimates garnered from the expert 

elicitation. Our use of the expert elicitation functions provides one estimate of the range of possible 

impacts.

Comment 13: Commenters 17707 and 17824 suggest that there is little evidence to support a link 

between air quality and asthma. Commenters cite the increased asthma rate from 3.1% of the population 

to 8.2% of the population between 1980-2009, despite the decrease in SO2 and NOX rates by 70%.

Commenter 17824 asserts that such evidence raises doubt as to the link between air quality and asthma.

Response to Comment 13: The commenters provide no references to support this argument. The EPA 

methods for quantifying health benefits of emission reductions are based on the best available peerreviewed science and methods that have withstood scrutiny from the EPA’s independent SAB, the 

National Academy of Sciences, and continuous interagency review. Note that the EPA estimates the 

reduction in asthma attacks, not the onset of asthma, for the calculation of health benefits.

Comment 14: Some commenters (17709, 17727, 17731, 17755, 17805, 18018, 18477) question the 

EPA’s assessment of health benefits resulting from the reduction in emissions of HAP and substances 

other than HAP, such as fine PM. Commenter 18477 points out that in the Utility RTC, the EPA 

estimated that nickel emissions from oil-fired utilities would result in additional 0.2 cancer cases per 

year. Commenter 18477 also states that “EPA acknowledged in the Utility RTC that there was 

significant uncertainty regarding the risks from oil-fired utilities” and that even their conservative 

calculations of risk show very low risk of cancers. Commenter 18477 also argues that the EPA has not 

investigated the effects of nickel and HAP thoroughly enough to determine health risks, and the 

commenter suggests that the EPA should re-evaluate the health risks. This commenter suggests that the 

EPA must specifically reconsider the nickel speciation data used to calculate the nickel health risks in 

the Utility RTC, and incorporate more data provided by the industry to improve the calculations. The 

commenter also conducted their own risk analysis for nickel emissions using an assumption of 5% of 

nickel emissions as carcinogenic, and calculated risk below the threshold for delisting a source from 

regulation under section 112. Several commenters (17731, 17755, 18018) suggest there is a lack of 

substantive HAP health risks linked to current EGU emissions outside of Hg-related benefits, and 

commenter 17805 adds that the mechanism of human exposure and risk are poorly understood. 
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Commenter 17731 states that because of the lack of HAP risks, the EPA was unable to quantify all of 

the health and environmental benefits of the proposed rule. Commenters 17727 and 17709 point out air 

quality modeling by the Midwest Ozone Group showing reductions to comply with the Clean Air 

Interstate Rule will allow nearly all areas of the U.S. to meet fine particulate standards, meaning that the 

assessment of the proposed rule includes benefits that will already be achieved by other rules. The 

commenter requests that the EPA reassess the benefits, so that those living on a fixed income will not be 

unnecessarily burdened.

Response to Comment 14: The EPA’s assessment of inhalation risks due to non-Hg HAP, by itself, is 

sufficient to support the determination that it is appropriate and necessary to regulate EGUs under 

section 112 of the CAA (see preamble for further details). The EPA disagrees with the commenters’

assertions that nickel emissions can be assumed to be only 5% as carcinogenic as nickel subsulfide (see 

preamble for further details). The EPA disagrees with the commenters’ assertion that the EPA’s inability

to quantify all of the health and environmental benefits of the proposed rule is due to a lack of associated 

HAP risks in the first place; rather, this is due to the lack of scientifically-accepted methodologies for 

estimating HAP-related benefits.

6. Health impacts are significant.

Comment 15: Numerous commenters (16404, 17254, 17408, 17409, 17766, 17811, 17852, 17871, 

18432, 18435, 18436, 18487, 18501, 19536/19537/19538, 18932) explain that the elderly, young, poor 

and minority groups as well as those in the southeast face increased risk of health effects from breathing 

HAP. Some commenters (18435, 18436, 19536, 19537, 19538) discuss the vulnerability of children to 

the adverse health effects of air pollution, even in the prenatal stages. The commenters further state that 

people with chronic diseases are also exceptionally susceptible. Commenter 17811 states that HAP 

cause damage to eyes, skin, breathing passages, kidneys, nervous system, particularly to sensitive 

groups. In particular, commenter 17811 discusses the serious harm poor air quality causes to children, 

such as their lung development and adverse birth outcomes. Commenter 17811 cites studies that say 

harmful exposures among minority populations may be more than twice as great as exposures to the 

average U.S. population. Commenter 17766 describes a coal-fired power plant in Milwaukee, Wisconsin 

that emits 5,000 tons of CO2, 1,500 tons of NOX, and almost 350,000 tons of particulates into the air 

annually; a third of asthmatics in Wisconsin live within a few miles of the plant, and most of those who 

do are minorities. Several commenters (17766, 19536, 19537, 19538) also point out that power plants 

tend to be near low income people who lack insurance and do not have paid sick leave, and thus air 

pollution will cause greater inconveniences for them. Commenter 17409 refers to studies that associate 

violence, mental retardation, and schizophrenia with higher levels of metals in the blood. Commenter 

17254 cites several studies showing the susceptibility of sensitive populations to poor air quality, 

including one study that revealed a “clear association between respiratory emergency department visits 

in Atlanta and sulfate rich fine PM, the kind of fine particles formed in the atmosphere as a result of 

gases emitted by coal fired power plants.” Commenter 17254 also cites a study showing that “children 

with autism were more vulnerable to environmental pollutants because they have lower levels...of the 

body’s natural defense for excreting environmental pollutants.” Commenter 18932 states that the 

southeast has one of the highest concentrations of coal-fired power plants in the nation, putting an undue 

health burden on the population.

Response to Comment 15: The EPA agrees that exposure to fine particulates and toxic air pollutants is 

associated with many adverse health effects and reducing exposure to these pollutants is associated with 

substantial public health benefits.
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Comment 16: Many commenters (16404, 16826, 17157, 17283, 17409, 17620, 17676, 17811, 17843, 

17875, 17916, 18022, 18027, 18029, 18039, 18421, 18425, 18432, 18435, 18436, 18477, 18478, 18487, 

18501, 18759, 19145, 18932) describe the Hg and non-Hg HAP that contribute to premature death, 

environmental contamination and exposure, and a host of diseases. Commenter 19145 cites the statistic 

that at least 1 in 12 women of childbearing age have enough Hg in their bodies to put a baby at risk for 

Hg poisoning. Commenter 18759 reports that 25 million Americans have asthma, of which 7.1 million 

are children. Commenters 18435 and 18425 state that SO2 and NOX are dangerous pollutants that will be 

significantly reduced by this rule. Commenter 18435 argues further that many of the constituents of 

PM2.5 are known to cause cardiovascular effects and respiratory harm. Commenter 18435 also presents 

the results of their calculation using the CALPUFF atmospheric dispersion model to estimate health 

benefits from the proposed rule; their calculations showed that use of the best available control 

technology would avert 70 deaths per year in a population of 33 million people. Commenter 18421 

points out the toxic effects of lead, particularly to children, and the potential carcinogenicity of organic 

HAP like dioxins and furans. Commenter 18039 describes the accumulation of Hg in the environment, 

and the resulting exposure this causes to the population.

Commenter 17916 states that the rule will also reduce emissions of harmful criteria pollutants. 

Commenter 17843 describes the link between nickel emissions with increased risk in daily mortality.

Commenter 17620 states that the “most recent EPA assessment of cancer risks from ambient HAP 

concentrations estimates that the entire US population at the time of the assessment had an increased 

cancer risk of greater than 10 in 1 million, while 13.8 million people have an increased cancer risk of 

greater than 100 in a million, as a result of breathing HAP at 2005 ambient levels over the course of 

their lifetime.” Commenter 18932 cites a study that concluded that metals and other toxic substances 

known to be emitted by coal-fired power plants created elevated risk levels for cancer and noncancerous health effects and are known to seriously injure human health. Many of the toxic metals from 

coal combustion are emitted as fine particulates, which bypass the body’s defenses and lodge in the

lungs leading to short and long-term health problems. Multiple commenters (17157, 17409, 17620, 

17826, 18029, 18487, 18759) state that the 400 coal-fired power plants across the country release over 

386,000 tons of HAP annually, and cleaning up these power plants can save over 17,000 lives annually. 

Commenter 17409 cites a study in Pennsylvania that estimates 1359 premature deaths are attributed to 

toxic emissions from power plants in 2010. This commenter (17409) also cites a Clean Air Task Force 

study that estimates the health impacts of the plant BL England at 32 heart attacks, 300 asthma attacks, 

and 19 deaths. Commenter 18487 states that due to the high toxicity of dioxins, these should be 

regulated in the final rule. Commenters 16404 and 18932 cite estimates of over 13,000 deaths, nearly

10,000 hospitalizations and more than 20,000 heart attacks per year nationwide at an economic cost of 

$100 billion. Some commenters (17283, 18932) do not fully agree with the decision to use PM2.5 as a 

surrogate for all non-Hg metal HAP, but they support the EPA’s finding that toxic components of fine 

particulate pollution from coal-fired power plants must be regulated under stringent MACT standards. 

Commenter 18932 discusses a study in Alabama that concluded that the levels of air toxics in the air had 

“elevated risk levels for cancer and non-cancerous health effects” and are “emitted in harmful quantities 

by coal-fired power plants in the region.” Commenter 18932 also details the amount of each of the 

following pollutants as well and the health issues associated with them: arsenic, antimony, beryllium, 

cadmium, chromium hexavalent compounds, cobalt, manganese, nickel, selenium sulfide, hydrogen 

cyanide, hydrogen chloride, hydrogen fluoride.

Several commenters (18421, 17921, 17811, 18436) argue that HAP cause acidification and degradation 

to the environment. Commenters point out that toxic metals contaminate and bioaccumulate in 

waterways and animal life, causing further exposures to local communities and harming recreational 

activities. Commenter 17921 points out that it is difficult to determine health effects of acid emissions, 
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though occupational exposures to HCl and HF have been shown to have health effects, and prospective 

studies show deleterious lung effects in children. Commenter 18421 states that coal-fired plants are 

responsible for approximately 76% of all acid gas emissions, which they argue can cause problems in 

the upper respiratory tract, especially harmful to children. Commenter 18421 also states that acid gas 

emissions contribute to acidification of ecosystems, and this causes harm to human health and the 

environment.

Several commenters (19536, 19537, 19538) explain that meeting the limits for toxic air emissions set by

the proposed rule provides reductions in secondary PM2.5, especially in SO2 and NOX. In addition, the 

commenter points out that fuel switching and retirements are also expected to reduce NOX emission and 

nitrate particles.

Response to Comment 16: The EPA agrees that the proposed rule will lead to reductions of criteria and 

HAP responsible for significant adverse health effects and that such reductions will produce substantial 

public health benefits.

The EPA agrees that Hg exposure in wildlife is responsible for various adverse health effects in many

species across the U.S. and recognizes that research is ongoing in this area. As discussed in the 

Appropriate and Necessary finding, the EPA agrees that there are potential environmental risks from 

exposures of ecosystems through Hg and non-Hg HAP deposition. The benefits to ecological health 

remain unquantified in the assessments for this rule due to data and methodological limitations. The 

EPA cited relevant articles from the special edition of Ecotoxicology mentioned by the commenter in 

the ecosystem effects section on Chapter 5 of the RIA for this rule. Ecotoxicology. 17:83-91, 2008.

The EPA agrees that acidification poses a significant risk of adverse effects to fish and wildlife in 

aquatic and terrestrial ecosystems. Please refer to EPA’s recent Risk and Exposure Assessment for 

Review of the Secondary National Ambient Air Quality Standards for Oxides of Nitrogen and Oxides of 

Sulfur-Main Content - Final Report available at 

http://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREASep2009MainContent.pdf for a 

comprehensive report on those effects including increased Hg methylation in acidified systems. Based 

on recent peer-reviewed research including Evans et al. (2011), acid gases can significantly contribute to 

acidification and the EPA agrees that those acid gases pose a risk for acidification of ecosystems. 

However due to data and methodological limitations the EPA was not able to quantify those risks and 

benefits.

Regarding health effects of acid emissions, the EPA agrees that the large percentage of acid gas 

emissions that can be attributed to EGUs may cause or contribute to chronic respiratory health problems. 

They are being subjected to emission limits in today’s final rule.

7. The proposed rule will harm public health.

Comment 17: Commenter 17919 suggests that the proposed rule will adversely impact public health by

increasing the cost of medical care, by “suppressing economic growth and the improved health it 

brings,” and by inefficiently using resources on expensive rulemakings instead of other public health 

measures. The commenter points out that the health sector is the second most energy intensive 

commercial sector, and increases in energy costs would translate to rapid increases in health care costs.

Response to Comment 17: The commenter’s assertion relies on the theory that the cost of the rule will 

result in lost income or employment that will, in turn, result in negative health effects that offset the 
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positive health effects of the rule. (This is referred to as a “health-health tradeoff.”) The EPA disagrees 

with this point and notes that there are a number of conceptual and empirical problems with any attempt 

to quantify the health-health tradeoffs of regulatory action to control air pollution. These analyses rely

on questionable applications of cross-sectional data and ignore key factors that may influence changes in 

population health risks. Additionally, marginal decreases in household income caused by the pass 

through costs of the regulation are unlikely to cause large changes in any single aspect of household 

spending, such as health care. These analyses also fail to consider that household income may increase if 

individuals are able to work (or work more) as a result of improved health, offsetting some or all of the 

pass through costs of the rule. For these reasons, the EPA’s science and economic peer review panels 

have consistently advised against attempting to quantify any health-health tradeoffs of regulation.

8. Support for the proposed rule.

Comment 18: Multiple commenters (12267, 17381, 17852, 17871, 17880, 17882, 17903, 17916, 18022, 

18432, 18435, 18438, 18478, 18501, 18961) support the proposed rule and agree with the regulations 

designed to address the source of pollution as strictly as necessary to protect human health. Commenters 

17882 and 18501 further add that coal-fired power plants are responsible for 99% of Hg emissions from 

the power sector in the U.S., justifying the rule. Commenter 17903 points out that some air toxics exist 

at high levels near coal-fired facilities, such as aldehydes and PAHs, that are not regulated by any

ambient monitoring requirements. Commenter 17916 points out that much of the Hg deposited in 

Ontario originates in U.S. coal-fired EGUs, that has many potential adverse health effects, thus they 

strongly support the rule. Commenters 18432 and 18435 further urge the EPA not to weaken the 

proposed rule.

Response to Comment 18: The EPA acknowledges generally supportive comments (including 

commenters 12267, 15002, 17381, 17648, 17852, 17871, 17880, 17882, 17903, 17916, 17921, 18022, 

18432, 18435, 18438, 18478, 18501, 18541, 18961, 19536, 19537, 19538, 18932) on the quantification 

of PM2.5 health co-benefits. The EPA agrees with these commenters that the large health co-benefits of 

this rule resulting from PM2.5 reductions far outweigh the costs and may underestimate the true benefits, 

as some health impacts (e.g., ozone health benefits, enhanced ecosystem services, increased fish 

consumption by women) were not able to be quantified.

9. Miscellaneous comments.

Comment 19: Commenter 16630 asks how averaging in combination with the credits affect the 

environment.

Response to Comment 19: In the proposed rule, the EPA planned to allow averaging of existing 

sources in the same subcategory at a common plant site for a given HAP. New and existing sources 

could not average and oil and coal could not average. This will not change for the final rule. The EPA 

has designed a rule that is intended to offer flexibility (including the averaging provisions), to the extent 

possible, while ensuring public health is protected in accordance with requirements outlined in the CAA.

Comment 20: Commenter 17734 submits information on technology developed by the commenter’s 

company that could be used to remove HAP from EGUs. The technology is a “non-carbon Hg sorbent 

that effectively captures Hg from coal-fired plants” from Novinda.

Response to Comment 20: The EPA thanks the commenter for this information but believes this 

comment is out of the scope of this rule.
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Comment 21: Commenter 17736 disagrees with the EPA’s claim that “it is reasonable to only consider 

emissions reductions achieved from requirements directly imposed on EGUs because EPA cannot 

predict with any certainty how EGUs would satisfy other required reductions.” The commenter argues 

that the EPA can use the EGU’s Title V permit to identify all CAA requirements and make regulations 

accordingly.

Response to Comment 21: Commenter appears to misunderstand the EPA’s approach to evaluating 

whether it is “necessary” to regulate EGUs. The EPA when projecting emission reductions evaluated the 

potential impact of future effective federal requirements to determine whether hazards to public health 

and the environment from HAP emissions from EGUs would remain after imposition of the 

requirements of the CAA. One such future effective rule was the Transport Rule and the EPA did 

estimate the HAP emissions reductions that would be attributable to that rule. The EPA did not attempt 

to estimate the potential reductions associated with revised NAAQS standards because states are 

primarily responsible for implementing programs that assure attainment and maintenance of the NAAQS 

and the EPA cannot predict with certainty how states would implement future effective NAAQS and 

even to the extent states required EGUs to obtain reductions in criteria pollutants there is no one 

required mechanism for doing so and the various options would result in varying levels of HAP 

emission reductions. 76 FR 24990. 

Commenter’s statement that the EPA should consider Title V permits to estimate HAP emission 

reductions relates more to the appropriate finding because Title V permits generally contain the 

requirements that are currently applicable to a source, though they may also include future effective 

requirements. Title V permits, therefore, are a better gauge of what sources are currently emitting and 

not particularly useful for developing HAP emission reductions in the future. In addition, EGU Title V

permits are unlikely to have specific HAP limits because EGUs are not subject to section 112 standards. 

For this reason, the EPA estimated current HAP emissions from EGUs based on their control 

configurations. The EPA maintains that it has developed a reasonable approach to determining both 

current and future HAP emissions from EGUs for all the reasons set forth in the proposed rule, and we 

did not err by declining to base the projections on EGU Title V permits. 

Comment 22: Commenter 17811 argues that the proposed rule is insufficient to reduce levels of HAP to

safe concentrations, based on modeling and monitoring data in Alabama.

Response to Comment 22: The EPA disagrees that today’s final rule, which is technology-based, must 

reduce levels of HAP from EGUs to safe concentrations. It is the requirement of the residual risk 

rulemaking, which must occur within 8 years of promulgation of the technology-based standards, to 

ensure that additional standards are promulgated for EGUs, if such are necessary to protect public health 

with an ample margin of safety. We have based the final rule on the performance (i.e., lowest emissions 

to the atmosphere, regardless of cause or intent) of the best performing sources in accordance with the 

statute.

Comment 23: Commenter 18502 argues that Puerto Rico currently is in compliance with all ambient air 

quality standards and thus further reductions in HAP emissions from the proposed rule will have no 

benefits to air quality on the island.

Response to Comment 23: Compliance with the NAAQS is not relevant to whether there would be 

benefits associated with this rule. The benefits are related to the emission reductions associated with 

applying controls. Both PM and ozone as well as many HAP have no threshold below which there are 
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no health effects. Therefore, reducing emissions will lead to health benefits, even though we don’t have 

the data to quantify these benefits at this time.

Comment 24: Commenter 17848 states that the numbers regarding monetized benefits in the proposed 

rule do not match the RIA. The rule states that total Hg-related benefits were calculated to be $450,000 

to $890,000 at a 7% discount rate while the RIA states that Hg-related benefits were calculated to be 

$5,000 to $9,000 at a 7% discount rate. The commenter requests that the EPA review the information 

and revise accordingly, and also suggests that the EPA use a single base year (2006$ or 2007$) when 

tabulating benefits.

Response to Comment 24: Any discrepancies in the proposal will be corrected in the final RIA. All 

costs and benefits are presented in 2007$ in the final RIA. 
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6L - Impacts/Costs: Mercury Benefits

Commenters: 12798, 15002, 15160, 16122, 16682, 17254, 17405, 17408, 17409, 17620, 17621, 17676, 

17679, 17681, 17682, 17683, 17716, 17731, 17732, 17751, 17754, 17761, 17766, 17789, 17811, 17843, 

17844, 17854, 17875, 17882, 17904, 17922, 17926, 18014, 18020, 18033, 18043, 18248, 18421, 18425, 

18432, 18435, 18436, 18443, 18484, 18487, 18498, 18500, 18541, 19210, 19214, 19506, 6640, 18932, 

18023

1. General impacts.

Comment 1: Commenter 17807 states that the EPA should incorporate the latest Hg toxicological data, 

reevaluate its conclusions, and determine whether the proposed rule is appropriate and necessary.

Response to Comment 1: The EPA disagrees that the data and methods used to determine the risks and 

benefits for the proposed rule are inadequate. The SAB in its review of the EPA’s Risk Assessment and 

supporting TSD finds that “the risk assessment provides an objective, reasonable, and credible 

determination of the potential for a public health hazard from mercury emitted from U.S. EGUs.” The 

SAB approved of the overall design and general approach and considered the spatial resolution of the 

modeling of Hg deposition to watersheds to be appropriate for the analysis. There was agreement that 

the approach used to identify watersheds to include in the assessment was reasonable. This approach 

was based upon the availability of fish tissue methylmercury data and census data on target populations 

with potential subsistence fishers. The SAB agreed that the EPA’s calculation of a hazard quotient for 

each watershed included in the assessment is appropriate as a principal means of expressing risk. 

The EPA Science Advisory Board Report available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985

2578cb006bcb04!OpenDocument

Comment 2: Commenter 18023 states the if the EPA had reported IQ loss estimates to only whole 

numbers or one significant figure, the differences between the scenarios in Table 5-6 would be zero 

indicating no benefit at all. According to the commenter, the EPA compounds this mistake by estimating 

a cost associated with accumulated IQ loss after recognizing that these benefits would be lower if lags 

were properly considered.

Response to Comment 2: The EPA disagrees with the commenter’s statement that the benefits 

calculated would be zero. The benefits calculated are averaged across the population and hence the small 

increments yield the benefits reported. In addition, the EPA recognizes that the IQ benefits presented are 

an underestimate of the benefits of reducing Hg emissions. According to the SAB’s review of the 

Mercury Risk TSD for this rule, “The loss of IQ points is likely to underestimate the impact of reducing 

methyl mercury in water bodies. The reason is that IQ score has not been the most sensitive indicator of 

methylmercury’s neurotoxicity in the populations studied. As noted in the Mercury Risk TSD, in the 

Faroe Island study the most sensitive indicators were in the domains of language (Boston Naming), 

attention (continuous performance) and memory (California Verbal Learning Test), neuropsychological 

tests that are not subtests of IQ tests and are not highly correlated with global IQ. In the Seychelles 

study, the Psychomotor Development Index has been most sensitive measure and, while this is a 

component of the Bailey Scales of Infant Development, it is not highly correlated with cognitive 

measures.”
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The EPA acknowledges that MMAPS does not account for a time lag in ecosystem response to 

reductions in Hg emissions. Ecosystems are highly variable in their response to reductions in Hg 

emissions. Due to limitations in data and methodology, EPA was not able to quantify the effect of lag 

times on benefits. 

Comment 3: Commenter 17621 states that with respect to the “hypothetical full scale IQ” this relatively

small incremental change in IQ (0.18 on a 100-point IQ scale) associated with a 1 ppm Hg increase in 

hair cannot itself be measured for an individual, but must be estimated for the total population (through a 

series of analytical and exposure assumptions) to derive estimates at the national level (e.g., 510.8 IQ 

points saved in RIA, Table 5-7). The individual effects estimates for the “average” IQ loss per exposed 

child were defined out to the fourth or fifth decimal place (see RIA, Tables 5-6 and 5-7) to indicate the 

potential (and relatively) small effects across the different exposure scenarios.

Response to Comment 3: Although the EPA disagrees that the IQ results are too small to be important, 

the EPA acknowledges that IQ is not the most sensitive neurodevelopmental endpoint affected by 

methylmercury exposure. The EPA analysis of potential IQ loss from methylmercury exposure is for 

population effects, as is done for any quantitative estimate of risk. For precision, it is appropriate to use 

a large number of significant figures in calculation, if this is supported by the data inputs. Upon 

completion of calculations, the estimate is rounded to the number of significant figures reflective of the 

least precise term. In the case of IQ, based on the effect estimates from the underlying epidemiological 

studies and the exposure estimates, the level of precision is to 2 significant digits to the right of the 

decimal place.

The EPA independent SAB recommended that the IQ analyses be retained but de-emphasized in the 

documentation underlying the final regulation (U.S. EPA-SAB, 2011). SAB concluded, “The Panel does 

not consider it appropriate for EPA to use IQ loss in the risk assessment and recommended that this 

aspect of the analysis be de-emphasized, moving it to an appendix where IQ loss is discussed along with 

other possible endpoints not included in the primary assessment. Although the Panel agreed that the 

concentration-response function for IQ loss used in the risk assessment is appropriate, and no better 

alternatives are available, IQ loss is not a sensitive response to methylmercury and its use likely

underestimates the impact of reducing methylmercury in water bodies.” (U.S. EPA-SAB, 2011) The 

EPA is following the SAB recommendation by deemphasizing the IQ analysis and placing that analysis 

in an appendix to the revised TSD. 

Comment 4: Many commenters (15002, 15160, 17408, 18425, 18421, 18432, 19210, 12798) support 

this rulemaking because it will reduce human health risks associated with exposure to Hg emissions 

from EGUs. Several commenters (19210, 15160, 18421) note that HAP, such as Hg, are linked to many

health problems, including cancer, heart disease, neurological damage, birth defects, asthma, and 

premature deaths. Commenter12798 states that the health of Americans and the economy will be greatly 

aided by these new regulations. The commenter quotes a Harvard study that found Hg emissions from 

coal-fired power plants may cost the country nearly $30 billion per year in health, environmental and 

economic impacts and suggested a cost of another $100 billion per year from particulate emissions and 

$200 billion from climate change emissions. The commenter considers these costs outweigh the 

potentially higher utility bills that could result from the proposed rule, and states that the utility sector 

has had adequate time to prepare. Commenter 18421 notes that data from several studies have shown 

links between methylmercury exposure, adult leukemia, and increased mortality rates (Salonen, J.T., K. 

Seppänen, T.A. Lakka, R. Salonen and G.A. Kaplan, Mercury accumulation and accelerated 

progression of carotid atherosclerosis: A population based prospective 4-year follow-up study in men in 

Eastern Finland, Atherosclerosis. 148, 265-273 (2000) and Yorifuji T, Tsuda T, Kawakami N, Age 
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standardized cancer mortality ratios in areas heavily exposed to methyl mercury, 88Int. Arch. Occup. 

Environ. Health. 679, 679-88 (2007).

Response to Comment 4: The EPA agrees that exposure to fine particulates and toxic air pollutants is 

associated with many adverse health effects and reducing exposure to these pollutants is associated with 

substantial public health benefits. The EPA also agrees that the benefits of the proposed rule outweigh 

the potential costs and that the proposed implementation schedule is reasonable.

Comment 5: Commenter 15002 expresses concern that even low levels of Hg exposure may be harmful 

because none of the studies of Hg toxicity have shown a threshold effect.

Response to Comment 5: The EPA agrees that there may be no threshold below which PM, Hg and 

other HAP have no effect and, in fact, the EPA uses a linear relationship in the concentration-response 

functions for those pollutants.

Comment 6: Commenter 19506 questions whether the benefits associated with the rule will actually be 

achieved. This commenter notes that the Hg emissions within Indiana have decreased by approximately 

20% over the past 14 years, but concentrations of Hg from wet deposition sampling have only decreased 

by 7% with no apparent change in Hg concentrations within fish tissue in Indiana over the past 22 years.

Response to Comment 6: The EPA disputes the commenter’s belief that this rule will not reduce Hg 

levels in fish. The data used in support of this RIA do not reflect the commenter’s assertion. The EPA 

notes that in some cases, Hg levels in fish can decrease quickly following reductions in Hg deposition. 

However, the time lag between reduced Hg deposition and reduced Hg levels in fish can vary greatly 

and is not accounted for in the RIA benefits analysis.

Comment 7: Commenter 18500 states that the EPA describes the Hg problems without providing 

evidence that actual harm in the U.S. can be attributed to EGU Hg emissions, or even to all Hg 

deposition. According to the commenter, the EPA fails to demonstrate that meaningful benefits will be 

obtained from reducing Hg deposition in the U.S. On page 4.9 of the March 2011 RIA for the Toxics

rule, the EPA states, “Model results for the continental United States indicate that total mercury

deposition (wet and dry forms) reductions from this sector [EGUs] would be 24,000 μg/m2(1.0% of total 

mercury deposition from all sources.

Response to Comment 7: The EPA disagrees with the commenter’s assertion that meaningful benefits 

would not accrue to the public due to reductions in Hg from U.S. EGUs. Chapter 5 of the RIA presents a 

detailed analysis of the benefit to IQ in children. The SAB has supported the model used in the RIA

analysis and states, “The support for the model of the relationship between IQ and methylmercury

exposure comes from Axelrad and Bellinger (2007) and from a whitepaper produced by Bellinger

(2005).” (U.S. EPA-SAB, 2011) The analysis in the RIA is not intended as the basis of the rule. It is 

intended only to estimate the costs and benefits of the proposed rule and therefore the IQ loss estimates 

presented in the RIA do not represent an attempt to afford more stringent than necessary protection in 

this rule. Furthermore, the EPA does not believe that the benefits of this rule are insignificant. The 

benefits of reduction of Hg exposure are underestimated on several counts 1) IQ is not the most sensitive 

indicator of neurological effects, 2) many health effects are unquantified, 3) benefits of reduction of 

other HAP are unquantified and 4) effects on ecosystems and wildlife are likewise unquantified. In 

addition, the co-benefits of reducing PM exposure are quite substantial and outweigh the costs of the 

rule.
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In addition, the EPA recognizes that the IQ benefits presented are an underestimate of the benefits of 

reducing Hg emissions. According to the SAB’s review of the TSD for this rule, “The loss of IQ points 

is likely to underestimate the impact of reducing methyl mercury in water bodies. The reason is that IQ 

score has not been the most sensitive indicator of methylmercury’s neurotoxicity in the populations 

studied. As noted in the TSD, in the Faroe Island study the most sensitive indicators were in the domains 

of language (Boston Naming), attention (continuous performance) and memory (California Verbal 

Learning Test), neuropsychological tests that are not subtests of IQ tests and are not highly correlated 

with global IQ. In the Seychelles study, the Psychomotor Development Index has been most sensitive 

measure and, while this is a component of the Bailey Scales of Infant Development, it is not highly

correlated with cognitive measures.”

Comment 8: Commenter 18023 states that the EPA’s analysis lacked transparency and therefore 

prevented meaningful review. One example, according the commenter, was the point the EPA made in a 

footnote on Page 5-78 of the RIA that monetized benefits of the rule could be significantly lower if lags 

in response to decreased Hg deposition were taken into account. The commenter states that lags are 

known to occur in many if not most aquatic ecosystems and that “a portion of the deposition is unlikely

to reach the water at all.”

Response to Comment 8: The EPA acknowledges that MMAPS does not account for a time lag in 

ecosystem response to reductions in Hg emissions. Ecosystems are highly variable in their response to 

reductions in Hg emissions. Due to limitations in data and methodology, the EPA was not able to 

quantify the effect of lag times on benefits.

2. Impacts on pregnant women and children.

Comment 9: Many commenters (15002, 15160, 16682, 6640, 17676, 17408, 17766, 17844, 17854, 

17875, 17922, 18421, 18432, 18435, 18436, 18932) express concern about the Hg levels found in 

children and women of childbearing age. Several commenters (15002, 18932, 17875) express concern 

that a large number of women of childbearing age are exposed to Hg at levels that lead to cord blood Hg 

levels that exceed the EPA reference dose. Commenters 15160 and 17408 identify potential health 

impacts of Hg exposure in children and developing fetuses, including speech, motor control, reading and 

writing as well as asthma, neurological damage, cancer, birth defects and other chronic health disorders. 

Commenter 15160 quotes data from the NC Department of Health and Human Services that estimate at 

least 11,811 babies are born annually with blood Hg levels that put them at risk for lifelong learning 

disabilities, fine motor and attention deficits and lowered IQ. Commenters 15160 and 17875 note that as 

many as one in six women of childbearing age have enough Hg in their blood to present a serious risk to 

a fetus during pregnancy.

Comment 10: Commenter 16640 explains that Hg accumulates in the environment and causes 

exposures long after being released from a power plant and bioaccumulates in humans along with 

arsenic, chromium and lead. The commenter quotes the American Academy of Pediatrics Policy 

Statement on Mercury which calls for, .”..efforts should be made to reduce exposure to the extent 

possible to pregnant women and children as well as the general population.” The commenter urges the 

EPA to set the strongest possible standard for Hg and other air toxics.

Response to Comments 9 - 10: The EPA agrees that Hg levels in women of childbearing age are of 

concern and that in utero exposure to levels above the reference dose may lead to adverse health impacts 

in children. The EPA further agrees that Hg and certain other HAP bioaccumulate and persist in the 

environment.
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Comment 11: Several commenters quote data from recently published studies on the impacts of Hg 

exposure. These include:

 Commenter 17676 quotes data published in 2000 by the National Academy of Science and the 

National Research Council showing that over 60,000 children are born each year at risk for 

adverse neurological effects due to in utero exposure to methylmercury (see National Academy 

of Science and Nation Research Council, Toxicological Effects of Methylmercury, 2000, 

available on the Web at: http://www.nap.edu/openbook.php?record_id=9899&page=327, 327).

 Commenter 18421 quotes a 2006 study by Dr. Kathryn Mahaffey estimating that approximately

410,000 infants are born in the U.S. each year to mothers with blood Hg concentrations in excess 

of the EPA’s reference dose.

 Commenter 18421 quotes a recent study of women conducted in Durham, North Carolina that 

found 30% of the women participating in the study had at least 1 ug/L of Hg in their blood, 

approximately 2% had blood Hg levels above 3.5 ug/L (level considered to be of concern during 

pregnancy), and 12.5% of women of Asian/Pacific Islander decent had blood Hg levels above 

3.5 ug/L (see Miranda et al., Mercury Levels in an Urban Pregnant Population in Durham 

County, 8 North Carolina. Int. J. Environ. Res. Public Health 698, 698-712 (2011).

 Commenter 17408 quotes research conducted at the Children’s Environmental Health Sciences 

Center at the University of Wisconsin that demonstrates developmental exposures to Hg are 

sufficient to cause alternations to nerve function causing permanent damage that has been 

implicated in development of neurodegenerative diseases, such as Alzheimer’s and Parkinsons. 

This commenter also notes that recent research has shown that the toxic effects of Hg exposure 

are passed down from one generation to another resulting in developmental and behavioral issues 

in the children and grandchildren of individuals exposed to low levels of Hg.

 Commenter 18421 quotes two studies conducted in Korea. The first study identified a link 

between adult leukemia and exposure to high levels of methylmercury (see Yorifuji T, Tsuda T, 

Kawakami N, Age standardized cancer mortality ratios in areas heavily exposed to methyl 

mercury, 88Int. Arch. Occup. Environ. Health. 679, 679-88 (2007). The second study evaluated 

274 Korean children found an association between Hg concentrations in urine and increased 

cholesterol, which is a risk factor for various forms of cardiovascular impacts (see Bose-O’Reilly

et al, Mercury Exposure and Children’s Health, Curr Probl Pediatr Adolesc Health Care. 2010 

September; 40(8): 186–215).

 Commenter 18432 quotes a recent study conducted in the City of Chester and Borough of 

Eddystone, Pennsylvania located in close proximity to coal- and oil-fired EGUs. This study

shows that asthma rates among children in these communities exceed 36 %.

Other commenters (18421, 18541, 17408-14) identify instances of methylmercury poisoning, such as the 

outbreaks in Minamata, Japan where the mothers exposed to elevated levels of methylmercury through 

consumption of contaminated fish typically did not exhibit any symptoms themselves, but gave birth to 

children with severe neurological and birth defects. Commenter 18421 also cites an outbreak of Hg 

poisoning in Iraq where consumption of contaminated grains resulted in serious reproductive impacts, 

including lower levels of pregnancies among the affected population.

Response to Comment 11: The EPA agrees with the commenters that research is ongoing and that new 

findings are being published that shed new light on these ubiquitous and harmful pollutants. The EPA is 

aware of the poisoning events detailed in the comments above and included descriptions of these events 

in the RIA for this rule.
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Comment 12: Commenter 17681 questions whether this rulemaking will reduce the health impacts of 

Hg exposure on women and children. This commenter argues that this rulemaking may not reduce the 

Hg exposure for women of childbearing age that eat canned fish because it may result in manufacturing 

companies relocating to countries where there are less stringent Hg emission limits on EGUs.

Response to Comment 12: The National Scale Mercury Risk Assessment shows that changes in Hg 

emissions from 2005 to 2016 were in fact likely to result in reductions in U.S. EGU attributable fish 

tissue Hg concentrations.

3. Impacts on IQ.

Comment 13: Many commenters (15002, 15160, 17409, 17716, 17766, 18421, 18425, 18435, 19506, 

and 18932) note that Hg exposure has been associated with cognitive delays, learning disabilities, and 

lower IQ levels. Commenter 15002 notes that the EPA’s own analysis has shown that a child born to an 

African-American woman in 2016 who consumed fish at the 90th percentile would experience a loss of 

approximately 7.7 IQ points in the absence of the proposed rule. Commenters 15160 and 18932 state 

that the North Carolina Department of Health and Human Services estimates that at more than 11,000 

children per year are born in North Carolina with blood Hg levels that place them at risk for lifelong 

learning disabilities, fine motor and attention deficits, and lowered IQ. Commenters 17409 and 18435 

identify recent studies such as the 2005 study by Transande that estimated between 300,000 and 600,000 

children each year have cord blood Hg levels that are associated with loss of IQ points and estimate that 

the lost productivity from the lower IQ levels is almost nine billion dollars.

Commenter 18425 states that severe impacts on cognitive thinking, memory, attention, language, and 

fine motor and visual spatial skills have been seen in children exposed to methylmercury in the womb. 

This commenter stated that the EPA’s data show 10,543 children in Wisconsin were prenatally exposed 

to unsafe levels of Hg in 2005, resulting in a 0.10 point loss in IQ per child (a total IQ loss in Wisconsin 

of 1,026.2 points). This commenter also notes that the proposed Air Toxics Rule will result in nearly an 

8.3% reduction in the average maternal daily Hg ingestion from the 2005 baseline, which would result in 

more than 10% reduction in the average IQ loss per child and total IQ loss across Wisconsin due to 

reduced Hg exposure from in-state sources.

Response to Comment 13: The EPA agrees that in utero and early childhood exposure to 

methylmercury can lead to neurological deficits in children and that the economic consequences of such 

deficits can be substantial.

Comment 14: Commenter 15002 believes that the EPA underestimated the impact of Hg on IQ by

restricting the analysis to populations who consume self-caught fresh-water fish and omitting Hg 

exposures from other freshwater and saltwater fish. This commenter also stated there is no evidence to 

support the hypothesis that some low level of Hg exposure is entirely without effect and that if the effect 

of lead on IQ extrapolates to the Hg, then low level Hg exposures may have a greater effect per unit 

exposure than higher levels.

Response to Comment 14: The EPA agrees that there may be no threshold below which PM, Hg and 

other HAP have no effect and, in fact, the EPA uses a linear relationship in the concentration-response 

functions for those pollutants. The EPA further agrees that the analysis of Hg impacts and health 

benefits are conservative.
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Comment 15: Multiple commenters (17621, 17716, 18498, 19506, 17681, 17731, 18033, 18443) 

believe this rulemaking will have little impact on IQ. These commenters argue that the EPA RIA shows 

only a fraction of an IQ point gain for the most exposed individuals, with the average effected 

individuals as prenatal children, 244,000 annually, experiencing only a 2/1000 IQ point gain. 

Commenter 18498 questions whether the EPA’s IQ impacts are real, while commenters 17716 and 

19506 argue that the benefits of the rule are insignificant. Commenter19506 believes that the benefits to 

IQ levels would still be insignificant even if the EPA included the impacts of commercially caught fresh 

and saltwater fish and self-caught saltwater fish in their analysis. Commenter 17681 argues that the 

aggregated benefit estimate of 0.00209 IQ points lost is below the level that can be measured by an IQ 

test.

Commenters 17716 and 17731 state that the EPA’s 0.11/ 0.10 average IQ loss per exposed child and 

0.176 point for the most at risk group is much lower than the EPA’s recent determination that a potential 

health risk occurs at 1-2 point IQ loss (The NAAQS for Lead, 73 FR 66964 (Nov. 12, 2008)). The 

commenter states that the EPA declined to set a more stringent NAAQS for lead because the estimated 

average IQ loss was lower than the 1-2 point range and argues that the proposed Hg limits are likely

more stringent than needed because the current Hg emission levels from EGUs have been shown to 

result in a 0.176 point IQ loss for the most at risk children, which is well below the EPA-determined 1-2 

point IQ loss level.

Commenter 17621 notes that in monetizing the loss of IQ the EPA relied on the Bureau of Labor 

Statistics National Longitudinal Survey of Youth (a national data set used to estimate the relationship 

between IQ and lifetime earnings). The commenter states that this survey does not contain a direct 

measure of IQ and is instead based on an Armed Forces Qualification Test (AFQT) that has been scaled 

to estimate IQ. The commenter states that an early analysis conducted at the request of the military 

reported a 0.77–0.80 correlation between AFQT scores and scores on a full-scale IQ test, the Wechsler

Intelligence Scale for Children (Office Secretary of Defense, 1980) and that the EPA should take into 

consideration the relative loss of precision in scaling between the AFQT and a full-scale IQ test in light 

of the small changes in IQ presented in the RIA IQ loss/reductions analysis.

Response to Comment 15: The EPA disagrees that the IQ impacts are not real and notes that the 

average reduction in IQ loss reported in the RIA do not reflect the greater than average impacts that 

reduced exposure would have at the tails of the distribution. The EPA uses a linear response model to 

predict IQ loss due to methylmercury exposure because there is no literature to date that shows a 

threshold below which no effect is observed. The SAB has supported the model used in the RIA analysis 

and states that “The support for the model of the relationship between IQ and methylmercury exposure 

comes from Axelrad and Bellinger (2007) and from a whitepaper produced by Bellinger (2005). It was 

noted that the 1-2 point decrease reflects the mean response, but that a decrease of 1-2 points at the mean 

results in a much larger decrease at the tails of the distribution. This can result in a greater impact on 

those with IQ’s that are much lower or higher than the mean.” (SAB Report available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985

2578cb006bcb04!OpenDocument) The analysis in the RIA is not intended as the basis of the rule. It is 

intended only to estimate the costs and benefits of the proposed rule and, therefore, the IQ loss estimates 

presented in the RIA do not represent an attempt to afford more stringent than necessary protection in 

this rule.

The EPA does not believe that the benefits of this rule are insignificant. The benefits of reduction of Hg 

exposure are underestimated on several counts 1) IQ is not the most sensitive indicator of neurological 

effects, 2) many health effects are unquantified, 4) benefits of reduction of other HAP are unquantified
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and 4) effects on ecosystems and wildlife are likewise unquantified. In addition the co-benefits of 

reducing PM exposure are quite substantial and outweigh all the benefits estimates for Hg.

The EPA agrees that the differences between the AFQT and full-scale IQ tests are a source of 

uncertainty; however, the EPA believes that the effect on the estimates would be very small since the 

difference between the two tests is small.

Comment 16: Several commenters (17681, 17769, 17807 and 18034) assert that the 1999 NHANES

data is out of date. These commenters state that more recent data (such as Caldwell, et. al. (2009), 

International Journal of Hygiene and Environmental Health, vol. 212, pp. 88-598) show a decline in 

NHANES blood Hg levels since 1999 and indicate that blood Hg levels have been below the EPA rfd

since 2001.

Response to Comment 16: The EPA did not apply any data from NHANES survey in the analysis of 

Hg effects on IQ in the benefits estimates for the RIA. The estimates were generated using data and 

models reviewed by the SAB as part of its review of the TSD. (SAB report available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985

2578cb006bcb04!OpenDocumeny)

Comment 17: Commenter 17621 states that with respect to the “hypothetical full scale IQ” this 

relatively small incremental change in IQ (0.18 on a 100-point IQ scale) associated with a 1 ppm Hg 

increase in hair cannot itself be measured for an individual, but must be estimated for the total 

population (through a series of analytical and exposure assumptions) to derive estimates at the national 

level (e.g., 510.8 IQ points saved in RIA, Table 5-7). The individual effects estimates for the “average”

IQ loss per exposed child were defined out to the fourth or fifth decimal place (see RIA, Tables 5-6 and 

5-7) to indicate the potential (and relatively) small effects across the different exposure scenarios.

Response to Comment 17: Although the EPA disagrees that the IQ results are too small to be 

important, the EPA acknowledges that IQ is not the most sensitive neurodevelopmental endpoint 

affected by methylmercury exposure. The EPA analysis of potential IQ loss from methylmercury

exposure is for population effects, as is done for any quantitative estimate of risk. For precision, it is 

appropriate to use a large number of significant figures in calculation, if this is supported by the data 

inputs. Upon completion of calculations, the estimate is rounded to the number of significant figures 

reflective of the least precise term. In the case of IQ, based on the effect estimates from the underlying 

epidemiological studies and the exposure estimates, the level of precision is to 2 significant digits to the 

right of the decimal place.

The EPA’s independent SAB recommended that the IQ analyses be retained but de-emphasized in the 

documentation underlying the final regulation (U.S. EPA-SAB, 2011). The SAB concluded, “The Panel 

does not consider it appropriate for EPA to use IQ loss in the risk assessment and recommended that this 

aspect of the analysis be de-emphasized, moving it to an appendix where IQ loss is discussed along with 

other possible endpoints not included in the primary assessment. Although the Panel agreed that the 

concentration-response function for IQ loss used in the risk assessment is appropriate, and no better 

alternatives are available, IQ loss is not a sensitive response to methylmercury and its use likely

underestimates the impact of reducing methylmercury in water bodies.” (U.S. EPA-SAB, 2011) The 

EPA is following the SAB recommendation by deemphasizing the IQ analysis and placing that analysis 

in an appendix to the revised TSD.
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Comment 18: Commenter 17681 states that the EPA’s IQ reduction metric, which it developed to 

assess the health impact from Hg emissions, resulted in an “aggregated benefit estimate” of 0.00209 IQ 

points lost, well below the level that can even be measured by an IQ test.

Response to Comment 18: The commenter is confusing a measurement based on an IQ test and the 

response predicted by the linear model the EPA used to calculate IQ decrements caused by 

methylmercury exposure. The EPA uses a linear response model to predict IQ loss due to 

methylmercury exposure because there is no literature to date that shows a threshold below which no 

effect is observed. The EPA notes that the average reduction in IQ loss reported in the RIA does not 

reflect the greater than average impacts that reduced exposure would have at the tails of the distribution. 

The SAB has supported the model used in the RIA analysis and states that “The support for the model of 

the relationship between IQ and methylmercury exposure comes from Axelrad and Bellinger (2007) and 

from a whitepaper produced by Bellinger (2005).” (SAB Report available at: 

http://yosemite.epa.gov/sab/sabproduct.nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985

2578cb006bcb04!OpenDocument).

4. Impacts on Food.

Comment 19: Many commenters (15002, 15160, 16682, 17405, 17408, 17409, 17254, 17683, 17766, 

18043, 18421, 18425, 18435, 18932, 17676, 17679, 17922) support this rulemaking because it will 

reduce the levels of methylmercury in the U.S. diet. These commenters consider the consumption of 

methymercury in contaminated fish to be a primary health concern and they believe that fish and

shellfish are the main sources of human methymercury exposure. Commenter 18932 states that, as of 

2008, all 50 states had issued some type of fish consumption advisory for Hg and 27 states had issued 

statewide Hg advisories for all bodies of water in the state. This commenter is also concerned that the 

number of fish consumption advisories is increasing, stating that between 2006 and 2008 the number of 

Hg advisories rose from 3,080 to 3,361. The commenter also notes that both the EPA and the Food and 

Drug Administration (FDA) issued a joint advisory urging women and children not to consume any

shark, swordfish, king mackerel, or tilefish, and to limit white albacore tuna to one meal per week.

Response to Comment 19: The EPA agrees that ingestion of methylmercury in fish is the main route of 

exposure in the American diet and that consumption of fish by pregnant women and children above the 

levels suggested by the advisories issued by the EPA and FDA can increase the risk of adverse health 

effects.

Comment 20: Commenter 15160 reports that Hg from coal-fired power plants in North Carolina has 

contaminated food, leading to advisories in North Carolina covering 17 species of ocean fish, walleye, 

and bass. Commenter 17254 states that the U.S. Geological Survey has shown that one in four fish 

contain Hg levels that exceed recommended EPA criteria and also notes that a recent issue of the 

Environmental Health Perspectives recreational anglers have been shown to have higher hair mercury 

levels. Commenter 17405 notes that human fish consumption restrictions cover every one of Wisconsin 

lakes. Commenter 17408 notes that a study of seafood-eating populations on Faroe Islands in the North 

Atlantic has shown that teenagers who were exposed to Hg while still in their mother’s womb have 

neurological and behavior problems. Commenter 17676 notes that frequent consumption of high-Hg fish 

has been associated with a number of harmful effects in adults, including effects on neurologic, 

cardiovascular, and immune systems. Commenter 18932 believes that residents in coastal areas may be 

exposed to unsafe levels of methylmercury because their diets are especially high in fish and shellfish. 

The commenter notes that a study in Alabama found extremely high levels of Hg in hair samples from 

coastal residents who consume seafood and fish every week, indicating elevated Hg levels in their 
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bodies overall. In a 1993 study, the North Carolina Department of Health and Human Services

discovered that fishermen and their families were consuming fish from the Waccamaw River that are 

under a fish advisory and that blood samples taken from this population had average Hg blood levels of 

7.5 ug/L, with approximately 40% of those tested having blood Hg levels greater than the recommended 

3.5 ug/L level for women of childbearing age. Commenter 17683 argues that families should be able to 

eat safe fish without having to worry about Hg in their bloodstreams and believes that regulation of Hg 

emissions from EGUs is overdue. Commenter 16682 states that the proposed rule can achieve reductions 

in Hg contamination in fish tissues quickly because levels of Hg in fish tissue quickly drop when the 

source is reduced. The commenter believes the proposed EPA standards will protect the public health 

and the environment.

Response to Comment 20: The EPA agrees that Hg from coal-fired power plants is a contributor to the 

levels of methylmercury in fish across the country and that consumption of contaminated fish can lead to 

increased risk of adverse health effects. The EPA agrees that this rule will reduce Hg levels in fish. The 

EPA agrees that, in some cases, Hg levels in fish can decrease quickly following reductions in Hg 

deposition. However, the time lag between reduced Hg deposition and reduced Hg levels in fish can 

vary greatly and is not accounted for in the RIA benefits analysis.

Comment 21: Commenters 15002 and 17679 believe the EPA’s analysis underestimates the impact of 

Hg emissions because the analysis focuses only on populations who consume self-caught fresh-water 

fish. Commenters argue that the EPA should include the contribution to Hg exposures from other 

freshwater and saltwater fish, including those most likely to contain large amounts of Hg (such as king 

mackerel, swordfish, large tuna, and tilefish). Commenter 17620 states that the EPA’s analysis is of 

limited usefulness in assessing the health impacts of the proposed rules because it is based on selfcaught freshwater fish rather than on commercially caught freshwater fish and saltwater fish that 

constitute the vast majority of the fish consumption in the U.S.

Response to Comment 21: The EPA agrees that the analysis presented in the RIA is an underestimate 

of the benefits of reduced Hg exposure in part due to the exclusion of some fish species especially 

saltwater fish. The EPA did not include marine fish due to data and methodological limitations.

Comment 22: Some commenters (17702, 17732, 17620, 17751, 18023) believe that the EPA’s analysis 

is not based on best available science, and that the analysis is flawed and overestimates the impact of Hg 

emissions on human health. Commenter 17751 argues that the EPA failed to fully account for the role of 

dietary selenium’s protective effects against methylmercury toxicity. This commenter states that there is 

extensive literature on the beneficial role of dietary selenium and that this literature shows that the 

binding affinity of Hg for selenium is up to a million times higher than for sulfur (Hg’s second best 

binding partner). In support of their argument, this commenter quotes work completed by an EPAfunded study showing that 97.5% of freshwater fish analyzed for a Western U.S. survey have sufficient 

selenium to “potentially protect them and their consumers against Hg toxicity.”

Response to Comment 22: The EPA disagrees with the commenters that the best available science was 

not used to generate the estimates presented in the RIA. There are uncertainties in the analysis; one of 

which is the role of selenium. The EPA was not able to quantify this relationship within the benefits 

estimates due to data and methodological limitations. There remains uncertainty with respect to the 

nature and magnitude of potential confounding between selenium and methylmercury and the associated 

effects on childhood neurodevelopment due to maternal ingestion during pregnancy. Additional research 

is needed to provide further clarity on this issue, but recent studies such as those referenced above 

reinforce the view that fish consumption during pregnancy should be approached as a case of multiple 
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exposures to nutrients and to methylmercury, with a complex and potentially interactive set of risks and 

benefits related to infant development. The EPA SAB Mercury Review Panel, in their peer review of the 

EPA’s National Scale Mercury Risk Assessment, evaluated the role of selenium in affecting Hg risk, 

and there was no consensus on the effects of selenium. The panel agreed that for all fish nutrients, there 

is not sufficient information to recommend a quantitative adjustment in health endpoint measures.

Comment 23: Commenters 17751 and 17681 argue that an analysis by Soon (See, Scientific Critique of 

EPA’s EGU MACT and NSPS Revisions, Willie Soon, PhD, June 2011) identifies a number of material 

errors in the EPA’s analysis of the health concerns related to Hg emissions from coal-fired EGUs. 

Commenter 17751 notes that Soon’s analysis and various other peer-reviewed scientific studies indicate 

that regulatory management of Hg is likely impossible, because methylmercury bioaccumulation and 

methylation are driven by factors others than elemental Hg availability. The commenter believes that 

Soon’s analysis clearly indicates that Hg emissions and impacts from sources other than those derived 

from EGUs greatly exceed the EGU emissions and impact and that even total elimination of all 

industrial emissions, inclusive of those from power plants, will not affect trace or even high 

methylmercury levels that have been found in fish tissue over century-long time periods. The 

commenter concludes that fish consumption advisories as an exposure prevention strategy make more 

sense than emissions control strategies.

Response to Comment 23: The EPA disagrees that regulatory management of EGU emissions of Hg is 

impossible and is proposing the MATS rule to just that end. The National Scale Mercury Risk 

Assessment shows that changes in Hg emissions from 2005 to 2016 were in fact likely to result in 

reductions in U.S. EGU attributable fish-tissue Hg concentrations. The EPA notes that decisions related 

to Hg emission controls are distinct from decisions about fish consumption advisories, which are 

intended to provide information to potential fish consumers. To the extent that regulations on EGU Hg 

emissions reduce concentrations of Hg in fish, specific fish consumption advisory information will 

reflect those changes in Hg concentrations.

Comment 24: Commenter 17751 disagrees with the EPA’s statement that reductions in power plant 

emissions will likely result in a reduction in Hg concentrations for fish in the ocean. Commenter 17751 

states that much valid, peer-reviewed scientific research has demonstrated that methylmercury in the 

world’s oceans is not controlled by deposition of atmospheric Hg. As an example, the commenter

discusses studies by Morel, et al. (“Response to Comment on Sources and Variations of Mercury in 

Tuna” Kraepiel, A. M. L.; Keller, K.; Chin, H. B.; Malcolm, E. G.; Morel, F. M. M.; Environmental 

Science Technology; 2004; 38(14); 4048-4048 (DOI: 10.1021/es0404217)) that show that Hg levels in 

tuna caught in the region around Hawaii have not changed over a period during which anthropogenic Hg 

inputs in the region have increased. The study’s authors suggest that these findings “provides prima 

facie evidence that this concentration is not responding to anthropogenic emissions irrespective of the 

mechanisms by which mercury is methylated in the oceans and accumulated in tuna.” This commenter

further states that the world’s oceans contain 40–200 million tons of Hg and that very little of it has been 

converted into methylmercury that can be accumulated in fish and that eliminating all of the 105 tons of 

Hg emissions released from U.S. anthropogenic sources in 2005 will leave the levels of Hg in the 

world’s oceans virtually unchanged with a 0.0003 % reduction. Further, the commenter states that the 

primary source of exposure to methylmercury for most people living in the U.S. is through consumption 

of ocean fish and that exposure to methylmercury from freshwater consumption is statistically

insignificant, as less than 0.05% of total fish and fish products consumed annually in the U.S. are 

freshwater fish (Food and Agriculture Organization of the United Nations, Trade in Fish and Fish 

Products, Fish Consumption, Fishers and Fleet Information, Tables CM 1.1 and CM 1.2).
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Response to Comment 24: The EPA disagrees that U.S. Hg emissions do not contribute to the global 

pool of Hg or affect Hg concentrations in ocean-going fish. The NAS in its 2009 report Global Sources 

of Local Pollution: An Assessment of Long-Range Transport of Key Air Pollutants to and from the 

United States http://www.nap.edu/catalog/12743.htmlreport, explains that “Hg is truly a global 

pollutant, as it has the potential, once emitted from any source, to be transformed to different chemical 

forms, transported through the atmosphere, and deposited long distances from the point of origin. 

Reservoirs that accumulate Hg include the atmosphere, the oceans, freshwater systems, soils, biota, and 

the cryosphere. Hence intercontinental transport is an important process that clearly affects U.S. 

exposures. Continued emissions will increase the amount of Hg in the global pool available for 

longrange transport and recycling among these reservoirs in the environment.” Thus since the oceans are 

considered a sink for Hg pollution it is reasonable to conclude that marine fish would be affected by that 

exposure.

Hg accumulation in fish is dependent on many variables including the age and weight of the fish. 

Additionally, Hg concentrations are variable across the oceans with methylated Hg accounting “ for up 

to 29% of the total Hg in subsurface waters (average 260 ± 114 fM). We observed lower ambient 

methylated Hg concentrations in the euphotic zone and older, deeper water masses, which likely result 

from decay of MeHg and Me2Hg when net production is not occurring “(Sunderland,2009).

That being said, the RIA is a national scale assessment which focuses on the exposures to 

methylmercury in populations who consume self-caught freshwater fish (recreational fishers and their 

families). Although there are other routes of exposure, including self-caught saltwater fish and 

commercially purchased fresh and saltwater fish, these exposures are not evaluated because 1) for selfcaught saltwater fish, we are unable to estimate the reduction in fish tissue methylmercury that would be 

associated with reductions in Hg deposition from U.S. EGUs, and 2) for commercially-purchased ocean 

fish, it is very difficult to determine the source of the methylmercury in those fish, and thus we could not 

attribute Hg levels to U.S. EGUs.

Comment 25: Commenter17751 disagrees with the EPA assessment of a direct one-to-one proportional 

relationship between reductions in atmospheric Hg and methylmercury concentrations in fish. The 

commenter believes this to be one of several errors that grossly inflate the EPA’s estimates of the human 

health benefits of the proposed controls on Hg emissions by EGUs and asserts that any health benefits 

from the EGU MACT would occur at times far removed from the time at which reductions in emissions 

occur.

Response to Comment 25: The EPA disagrees that the health benefits of Hg control are inflated. In fact 

the EPA believes that the estimates presented in the RIA are an underestimate because the EPA was not 

able to analyze the impacts using the most sensitive endpoints for human health. According to the 

SAB’s review of the TSD for this rule “The loss of IQ points is likely to underestimate the impact of 

reducing methyl mercury in water bodies. The reason is that IQ score has not been the most sensitive 

indicator of methylmercury’s neurotoxicity in the populations studied. As noted in the TSD, in the Faroe

Island study the most sensitive indicators were in the domains of language (Boston Naming), attention 

(continuous performance) and memory (California Verbal Learning Test), neuropsychological tests that 

are not subtests of IQ tests and are not highly correlated with global IQ. In the Seychelles study, the 

Psychomotor Development Index has been most sensitive measure and, while this is a component of the 

Bailey Scales of Infant Development, it is not highly correlated with cognitive measures.”

Further, the EPA disagrees that the proportionality assumed in the MMAPS model that relates the 

reduction in Hg deposition to reductions in fish tissue concentrations is inappropriate. According to SAB
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“Since the Mercury Maps approach was developed, several recent publications have supported the 

finding of a linear relationship between mercury loading and accumulation in aquatic biota (Orihel et al., 

2007; Orihel et al., 2008; Harris et al., 2007). These studies suggested that that mercury(II) deposited 

directly to aquatic ecosystems can become quickly available to biota and accumulated in fish, and 

reductions in atmospheric mercury deposition should lead to decreases in methylmercury concentrations 

in biota. These results substantiate that the assumption of proportionality between air deposition changes 

and fish tissue methylmercury level changes is sufficiently robust for its application in this risk 

assessment.”

The EPA does agree that there may be a lag time between evidence of health benefits due to the 

reduction of Hg emissions and the actual occurrence of the reductions however there is no data available 

on how long that lag may be.

Comment 26: Commenter 17751 believes that the EPA should not have relied on Faroe Islands study

because the Faroe Islanders receive Hg exposure by atypical consumption of pilot whale meat 

contaminated by PCBs which has little relationship to fish consumption in the U.S. This commenter

asserts that the EPA should have used data from the Seychelles Islands study, because this study is the 

most relevant to the U.S., where there was no adverse response observed in women or their children 

despite maternal Hg levels 10 times those found in the U.S. Commenter 17751 also notes that (1) 

Seychelles islanders consume far more fish than do Americans; (2) the amount of methylmercury in the 

U.S. population is 10 to 20 times below that of the Seychelles islanders; and (3) all ocean fish 

throughout the world contain about the same amount of methylmercury, so, per fish meal, there is no 

difference in methylmercury intake when comparing the seafood diet of Americans to Seychelles 

islanders. Commenter 17751 believes that the Seychelles Islands study is the right study to use as a basis 

for making a regulatory decisions and assessing the health impacts of Hg.

Response to Comment 26: The comment has several inaccurate statements. As published by Dr Weihe

and colleagues, exposure to methylmercury in the Faroes was largely from consumption of pilot whale 

meat; exposure to PCBs was found in the portion of the population who also consume whale blubber. 

The lipophilic PCBs are found in the fat compartment of the pilot whales; methylmercury, by contrast, is 

bound covalently to protein in the whale meat.

Contemporary publications on data and analyses from the Seychelles Child Development Study of 

Methylmercury from Fish Consumption (SCDS) have reported methylmercury-related effects from 

testing of older children in their study cohort (e.g., van Wyngaarden et al. 2006; Strain et al., 2008.)

The EPA’s RfD for methylmercury is based on multiple endpoints from the three extant large studies of 

childhood effects of in utero exposure: Faroes, New Zealand, and an integrative measure including data 

from Seychelles. Documentation for the choices underlying calculation of the RfD can be found in the 

following sources: U.S. EPA (2001) Water Quality Criterion for the Protection of the Human Health:

MethylmercuryEPA-823-T-01-001, available at 

http://water.epa.gov/scitech/swguidance/standards/criteria/aqlife/pollutants/methylmercury/index.cfm; 

U.S.EPA. 2011.Integrated Risk Information System, available at 

http://www.epa.gov/iris/subst/0073.htm; Rice et al (2003).

5. Impacts on low-income and subsistence populations.

Comment 27: Multiple commenters (15002, 16122, 17409, 17254, 17732, 17766, 17811, 18421, 18435, 

18436, 18487, 18932) note that Hg emissions have a disproportionate impact on low-income and 
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subsistence populations, such as Native Americans, Hispanics, and Location subsistence fishers. Several 

commenters (17409, 18421, 18932) state that African Americans, Native populations, Latino 

communities, Asian Americans (e.g., Vietnamese in the gulf area), and other low income communities 

who fish recreationally are more likely to eat the fish they catch. Commenter 17766 states that African 

Americans and Hispanics eat more fish that are contaminated with Hg than are their White counterparts 

because these groups eat fish to obtain a source of high quality protein and catch the fish themselves to 

make up for economic inequities. This commenter quotes 2006 statistics showing that approximately 1.4 

million African Americans and 1.3 million Hispanics were avid subsistence anglers. This commenter

further notes that many of these disadvantaged groups fish in urban areas near where they live because 

they have limited transportation options and therefore, tend to fish in urban areas where fish are most 

Hg-laden. Commenter 18932 quotes a 2005 survey of anglers in Baltimore Harbor, the District of 

Columbia, and the Tidewater Region of Virginia where interviewers found that in many instances 

anglers stated that they knew of health advisories associated with the fish that they caught, but still ate 

the fish and shared them with at-risk members of their families, e.g., women of childbearing age. In the 

Tidewater Region of Virginia, the study showed that 91% of those interviewed stated that they ate some 

of the fish they caught, 50 % of stated that having a fresh fish dinner was a very important motivation 

for fishing, and 19% stated that reducing the cost of food was a very important motivation for fishing.

Response to Comment 27: The EPA agrees that low-income and subsistence fishers are 

disproportionately affected by exposure to methylmercury in fish due to their fish consumption patterns.

Comment 28: Commenter 17254 notes that African Americans are disproportionately affected by Hg 

emissions because this population have a greater prevalence of kidney disease and are more likely to 

reside in closer proximity to industries that emit Hg and other air pollutants. Commenter 18435 provides 

maps of the southeastern states showing the proximity between concentrations of low income people, 

including both white and African-Americans, and the location of coal-fired power plants and notes that 

the close proximity of these plants to waterways near their homes makes it more likely that fish from 

those waterways would make part of their diet. Commenter 15002 notes that the EPA’s analysis 

concluded that a child born to an African-American woman in 2016 who consumed fish at the 90th 

percentile would experience a loss of approximately 7.7 IQ points in the absence of the proposed rule. 

This commenter stated that this risk represents an unacceptable burden on this population.

Response to Comment 28: The EPA agrees that low-income African Americans are at greater risk of 

adverse health outcomes due to their higher consumption rates of fish with high levels of 

methylmercury. The EPA agrees that this risk is and unacceptable burden for this population.

Comment 29: Commenter 17732 acknowledges that there are subpopulations of Native Americans 

more susceptible to methylmercury exposure because of subsistence diets based on fish and notes that 

the 1997 Mercury Study to Congress concludes that exposures among specific subpopulations including 

anglers, Asian-Americans, and members of some Native American Tribes may be more than two-times 

greater than those experienced by the average U.S. population. However, this commenter believes that 

fish consumption is limited and occurs primarily during recreational activities. Commenter 17732 notes 

that a 2004 U.S. Fish & Wildlife report concluded that the Navajo “can and should feel comfortable 

about consuming fish on a recreational basis...” and further argues that the EPA should not assume that 

exposure to Hg and other HAP on Tribal lands are equal in comparison to exposures in the more densely

populated metropolitan and urban areas where population and industrial growth continue to contribute to 

hazards to public health and environment. The commenter further recommends the EPA collect more 

public health data in areas in close proximity to regional HAP so as to better understand the true public 

health and environmental impacts.
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Response to Comment 29: The EPA agrees that the analyses presented in the RIA focused on Native 

American populations with high-end fish consumption patterns specifically the Great Lakes tribes of 

Chippewa and Ojibwe whose consumption patterns may constitute a higher risk of adverse health 

effects. The people of the Navajo nation were not included in the modeled populations for the risk 

assessment or the RIA for this rule. The EPA acknowledges that some Native American populations do 

not fit the criteria for subsistence level fishers.

6. Impacts on tourism and recreational fishing.

Comment 30: Commenters 16122 and 17732 note that Hg contamination of streams, rivers, and lakes 

threaten the economy of states and tribes that rely on fishing tourism. Quoting data published by the 

U.S. Department of Interior, Fish and Wildlife Service, commenter 16122 notes that the Wisconsin 

Department of Natural Resources sells approximately 1.5 million fishing licenses and that the sales of 

these licenses, as well as of food, lodging, gasoline, and sporting equipment related to fishing adds 

approximately $2.1 billion to the Wisconsin economy and another $5 billion to the states of Illinois, 

Indiana, Michigan, Minnesota, and Ohio.

Response to Comment 30: The EPA agrees that Hg contamination of water bodies across the U.S. has 

led to fish consumption advisories for those water bodies that may have a negative effect on recreational 

fishing. The EPA also agrees that recreational fishing has a large economic impact in many states. The 

EPA further agrees that reducing Hg levels in fish should have beneficial effect on recreational fishing. 

However, given data methodological limitations, the EPA was not able to estimate those benefits at this 

time.

7. Impacts on wildlife.

Comment 31: Multiple commenters (17679, 18033, 18043, 18248, 18487, 18541, 19214) point out that 

Hg emissions have adverse health effects for numerous species of wildlife, including reproductive, 

neurological, survival, and behavioral effects.

Response to Comment 31: The EPA agrees that Hg exposure in wildlife is responsible for various 

adverse health effects in many species across the U.S. and recognizes that research is ongoing in this 

area. The benefits to ecological health remain unquantified in the assessments for this rule due to data 

and methodological limitations. Because these benefits are unquantified, the benefits assessment 

presented in the RIA for this rule is underestimated and conservative.

8. Benefits do not justify the rule.

Comment 32: Multiple commenters (17716, 17682, 18484, 18500, 17904, 18020, 17754) argue that the 

benefits of the proposed rule do not justify the costs.

Response to Comment 32: The EPA disagrees that the benefits of the MATS rule do not justify the 

costs. As the analyses presented in the RIA for the rule show the benefits outweigh the costs by a large 

margin. Although the monetized benefits of reducing Hg emissions are not large, those benefits are also 

not equally distributed across the population. As the sensitivity analysis shows, some populations 

including low-income African Americans and some Native American populations may receive a 

disproportionate benefit, and the distributional aspects of the benefits may help to justify the costs of the 

rule. Furthermore, the analysis depended on using a less sensitive endpoint (IQ) of neurological impacts 

of Hg exposure as noted by the SAB which leads to underestimation of the benefits. Additionally, many
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other impacts of Hg emissions were not quantified including impacts on ecosystems and wildlife; 

especially fish, birds (both fish and insect eating), and mammals. Other HAP controlled by the MATS 

rule were likewise not quantified due to data, resource and methodological limitations. Even if we were 

able to fully monetize the public health benefits of reducing exposure to Hg and other HAP, it is likely

that the PM benefits would continue to dominate the total monetized benefits due to the size of the 

exposed population and the severity of the associated health effects. Despite our inability to provide 

monetized benefits of HAP emission reductions, the total monetized benefits exceed the estimated costs 

of the rule by a substantial margin, even when taking uncertainty into account.

Consideration of PM2.5 health co-benefits expected as a result of direct PM2.5 and SO2 emission 

reductions is directed by OMB Circular A-4 (p. 26, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Your analysis should look beyond the direct benefits and direct costs of your rulemaking and consider 

any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of 

the rule that is typically unrelated or secondary to the statutory purpose of the rulemaking (e.g., reduced 

refinery emissions due to more stringent fuel economy standards for light trucks) while a countervailing 

risk is an adverse economic, health, safety, or environmental consequence that occurs due to a rule and 

is not already accounted for in the direct cost of the rule (e.g., adverse safety impacts from more 

stringent fuel-economy standards for light trucks).”

It is also directed by EPA’s Guidelines for Preparation of Economic Analyses (p. 11-2, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html):

“An economic analysis of regulatory or policy options should present all identifiable costs and benefits 

that are incremental to the regulation or policy under consideration. These should include directly 

intended effects and associated costs, as well as ancillary (or co-) benefits and costs.”

In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a 

regulatory action, to the extent feasible. We further note that if we were able to fully monetize all of the 

benefit categories, the benefits would exceed the costs by an even greater amount than we currently

estimate.

9. Lack of quantification of non-Hg HAP means no benefits.

Comment 33: Commenter 17716 believes that the fact that the benefits of non-Hg HAP are not 

quantified means that no benefits exist for these reductions.

Response to Comment 33: This rule is expected to achieve important non-Hg HAP benefits. However,

monetization of non-Hg HAP benefits is limited by currently available data and methods. In summary, 

monetization of the benefits of reductions in cancer incidences requires several important inputs, 

including central estimates of cancer risks, estimates of exposure to carcinogenic HAP, and estimates of 

the value of an avoided case of cancer (fatal and non-fatal). Due to methodology and data limitations, 

we did not attempt to monetize the health benefits of reductions in HAP in this analysis. Instead, we 

provide a qualitative analysis of the health effects associated with the HAP anticipated to be reduced by

these rules. The EPA disagrees that the health benefits of non-Hg HAP could never be measured. A 

well-designed epidemiological study could measure these benefits. The EPA remains committed to 

improving methods for estimating HAP benefits by continuing to explore additional concepts of 

benefits, including changes in the distribution of risk. Quantitative estimates of these benefits are 
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provided to the extent possible, and our limited ability to monetize these benefits does not indicate that 

they are non-existent or less important.

Our treatment of these benefits follows guidance set by OMB Circular A-4 (pp. 26-27, available at: 

http://www.whitehouse.gov/omb/circulars_a004_a-4/):

“Sound quantitative estimates of benefits and costs, where feasible, are preferable to qualitative 

descriptions of benefits and costs because they help decision makers understand the magnitudes of the 

effects of alternative actions. However, some important benefits and costs (e.g., privacy protection) may

be inherently too difficult to quantify or monetize given current data and methods. You should carry out 

a careful evaluation of non-quantified benefits and costs. Some authorities refer to these non-monetized

and non-quantified effects as “intangible.”

It is also in line with EPA’s Guidelines for Preparing Economic Analyses (p. 11-3, available at: 

http://yosemite.epa.gov/ee/epa/eed.nsf/pages/Guidelines.html).

“Benefits and costs that cannot be monetized should, if possible, be quantified (e.g., expected number of 

adverse health effects avoided). Benefits and costs that cannot be quantified should be presented 

qualitatively (e.g., directional impacts on relevant variables).”

10. MATS is duplicative of the CSAPR and multiple NAAQS.

Comment 34: Commenter 17761 believes that MATS will duplicate emissions reductions achieved 

through the CSAPR and NAAQS implementation.

Response to Comment 34: The EPA disagrees that MATS is duplicative with the CSAPR and NAAQS. 

MATS will reduce emissions of toxic air pollutants not covered by the aforementioned rules. 

Furthermore when the EPA estimates the benefits for rules like MATS, the EPA includes other rules 

such as the CSAPR in the “baseline.” Any emission changes expected as a result of MATS are 

additional emission reductions beyond those regulations (e.g., CSAPR) that were considered to be part 

of the baseline.

11. U.S. EGU mercury emissions are a small contributor to the global pool.

Comment 35: Multiple commenters (17716, 17682, 18484, 18500, 17904 18020, 17754) argue that 

reductions of Hg emissions from U.S. EGUs is not a cost-effective method for reducing Hg emissions 

since Hg is emitted globally and the contribution from U.S. sources is very small.

Response to Comment 35: The EPA disagrees that controlling Hg emissions from U.S. EGUs is not a 

cost-effective method of reducing Hg emissions. The EPA agrees with NACAA (public comment EPAHQ-OAR-2009-0234-17620-A1) that “while a global mercury pool does exist, data collected at a 

number of U.S. locations over the past decade show that reductions in point source air emissions of 

mercury produce substantial improvement in the local and regional environment shortly after those 

reductions are implemented. Indeed, ongoing monitoring efforts in a number of states indicate that 

mercury levels in fish and other biota have fallen as those states have begun to address sources of 

mercury pollution.”

In November, 2002, an enhanced air monitoring site was established in Steubenville, Ohio to investigate 

source-receptor relationships for Hg deposition in eastern Ohio. The site overlooking the Ohio River 
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was in close proximity to several anthropogenic point sources, including EGUs. The data collected 

during this study demonstrated that approximately 70% of the Hg in wet deposition was due to coal 

combustion and that a significant portion of the Hg deposited in the immediate vicinity of local EGUs

was directly attributed to those local sources. The University of Michigan researchers concluded that “it 

has become evident that near-field impact of coal fired utility boilers on Hg deposition is significant and 

underestimated by the models that have been utilized in previous policy decision making.”(Keeler et al, 

2006) Similarly, wet deposition data collected throughout the Great Lakes over the past decade have 

demonstrated distinct regional variability that undercuts any suggestion that local Hg emission efforts 

are of no value. Precipitation samples collected in southeastern Michigan showed a 25 to 35% increase 

in the Hg concentration between urban sites in Detroit and a rural site 40 miles to the east. This 

phenomenon is not limited to the northern part of the country. Studies in south Florida revealed that the 

spatial and temporal patterns of wet deposited Hg were also strongly influenced by local sources. 

National data show similar variability in deposition rates; Hg deposition rates attributable to U.S. EGU

emissions at the most affected water bodies are eight times the mean rate of such deposition. The EPA’s 

modeling suggests that the proposed rule will reduce this local excess deposition from U.S. EGUs by 

80%. (Gerald J. Keeler, Matthew S. Landis, Gary A. Norris, Emily M. Christianson, and J. Timothy

Dvonch, Sources of Mercury Wet Deposition in Eastern Ohio, USA, pub Environ. Sci. Technol., 2006, 

40 (19), pp 5874–5881.)

12. HCl contribution to acidification of ecosystems.

Comment 36: Commenter 18487 points out that reducing emissions of acid gases will benefit acid 

sensitive ecosystems and the fish and wildlife that depend on those ecosystems.

Response to Comment 36: The EPA agrees that acidification poses a significant risk of adverse effects 

to fish and wildlife in aquatic and terrestrial ecosystems. Please refer to the EPA’s recent Risk and 

Exposure Assessment for Review of the Secondary National Ambient Air Quality Standards for Oxides 

of Nitrogen and Oxides of Sulfur-Main Content (Final Report available at 

http://www.epa.gov/ttn/naaqs/standards/no2so2sec/data/NOxSOxREASep2009MainContent.pdf) for a 

comprehensive report on those effects including increased Hg methylation in acidified systems. To the 

extent that acid gases contribute to acidification, the EPA agrees that those gases pose a risk for 

acidification of ecosystems. However, due to data and methodological limitations, the EPA was not able 

to quantify those risks and benefits.
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6M - Impacts and Costs: Air quality co-benefits modeling

Commenters: 17627, 17752, 19686

Comment 1: Commenter 17627 states that the 2005 base year did not include emission reductions that 

have already occurred as a result of many enforceable federal and state programs. Additionally, the 2016 

emissions are predicated off the IPM-related NODA dated October 2010 and do not include results from 

two subsequent NODAs. If the emission estimates were corrected, the benefits would not be overstated 

and it is possible that the rule could not be justified on cost considerations.

Response to Comment 1: The EPA disagrees with the commenter’s assertion that the benefits are 

overstated based on a 2005 base year. The benefits of the rule are computed based on differences 

between the 2016 baseline and the 2016 policy case, and not the differences from 2005. Therefore, to 

achieve reasonably accurate estimates of benefits, the most important feature of EPA’s approach is 

having an accurate projection from 2005 to 2016, so that the emissions reductions and economic 

downturn referenced by the commenter are included in the future base and therefore not included as part 

of the benefits of the rule. These impacts are included in both the 2016 baseline and the 2016 policy case 

and therefore are not captured as benefits of the rule. The EPA diligently included the emissions 

reductions that have occurred from 2005 to present and the final modeling done for the RIA for this rule 

is the best available national information to reflect reductions in emissions that have occurred from 2005 

to present. The data used at proposal were updated to reflect the comment process on the CSAPR, for 

which a number eastern states provided detailed updates to the EPA’s emissions projection assumptions 

for EGU, non-EGU point, stationary area, and nonroad mobile sources. All of these comments were 

included in the projections used for the final rule. Furthermore, the comment process for this rule 

provided an opportunity to make the EPA aware of any other projection changes that were needed for 

improving our benefits estimates. In the rare instances where such specific comments were made for this 

rule, the EPA included those reductions in the final 2016 projections. The EPA used the best economic 

forecasts available at the time the datasets were created. This included the use of Annual Energy

Outlook of 2010 data in the EGU projections. Other updates to point sources included the incorporation 

of all known controls in the 2016 baseline, and the inclusion of non-EGU plant closures, federally

enforceable emissions reductions, and consent decrees that have happened since 2005.

Comment 2: Commenter 17752 describes errors found in the IPM file pertaining to two of the 

commenter’s units which are affected by the proposed rule. The commenter explains that the Big Stone 

Plant was shown to have an on-line scrubber in 2011, which it does not. The file also showed an ESP, 

while the plant has only a fabric filter and not an ESP. The commenter also explains that the Hoot Lake 

Plant Unit 2 does not have any NOX control listed in the file, but it is equipped with low NOX burners 

and overfire air. The commenter requests the EPA make corrections to these and any other incorrect 

IPM files and determine the true rule impacts.

Response to Comment 2: The EPA thanks the comment for this observation and notes that IPM

modeling for the final rule has been updated to reflect these corrections.

Comment 3: Commenter 19686 states that the rule’s technical analysis fails to account for Tribes with 

respect to monitoring and modeling. The EPA used the Community Multi-scale Air Quality (CMAQ) 

model to estimate the rule’s reduction in the incidence of adverse health effects, as well as the estimated 

economic value of the reduction in the incidence of adverse health effects. The grid sizes used fail to 

account for the considerable variation in the land size of individual Tribes, which can be anywhere 

between one to thousands of acres. The smallest lands, because of their size, may be wholly or partially 
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located in areas that heavily influence airflow unlike surrounding jurisdictions (e.g., valleys, mountains), 

meaning that CMAQ grid sizes of 12 km and greater may have a hard time modeling the true effects on 

local air quality for Tribes. To predict the rule’s impact on Tribes more accurately, the commenter 

recommends that the EPA redo its CMAQ analysis and use modeling grids no greater than 4 km. 

Further, the EPA should use similar size grids for any of its forthcoming rules that may have potential 

impacts on Tribes.

In using the CMAQ model, the EPA cites as one uncertainty the “[l]ack of ozone and PM 2.5 monitors 

in rural areas” that required the EPA to extrapolate “observed ozone data from data to rural areas.” Most 

of Indian Country is located in rural areas, meaning that their lands were unrepresented by the modeling 

results. Tribal lands located in urban areas are also largely unrepresented since they possess few 

monitors to discern the presence and amount of pollutants covered by the rule. Hence, the EPA lacks the 

data to make any accurate conclusions about the rule’s impact on Tribes. Further, the EPA must get 

away from the practice of extrapolating data for Tribal lands for any of its rules and actions. 

Response to Comment 3: The EPA agrees with the commenter that the CMAQ modeling with 12 km 

grid resolution may provide a lower bound estimate on EGU contribution as higher impacts using finer 

grid resolution are possible. The EPA also agrees with the commenter that there may be some variation 

in estimated air quality within a 12 km grid cell, but we believe the air quality estimates at 12 km 

generally reflect the area within the grid cell. The EPA would like to point out that the application of a 

photochemical model at 12 km grid resolution for the entire continental U.S. is more robust in terms of 

grid resolution and scale that anything published in literature and represents the most advanced 

modeling platform used for a national Hg deposition assessment.
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6N - Impacts/Costs: Other/Miscellaneous

Commenters: 15002, 15160, 17620, 17884, 17973, 19214

Comment 1: Commenter 15002 recommends the EPA implement a 5-year review cycle for Hg and 

other HAP, similar to what is mandated by the CAA for the NAAQS. The commenter notes that 

emissions will plateau at current levels due to population increases balanced out by improved emission 

controls that become more effective and less expensive. However, the commenter also points out that no 

safe level exists for Hg or other HAP.

Response to Comment 1: The EPA welcomes the commenter’s observations regarding future emissions 

levels and control technology but notes that, while a regular 5-year review schedule is mandated by the 

CAA for the NAAQS, the schedule prescribed by the CAA for review of emission standards for Hg and 

other HAP calls for a review every 8 years. The EPA believes that subsequent periodic reviews will 

identify any improvements in techniques for the control of Hg and other HAP, and these will be 

incorporated as appropriate.

Comment 2: Commenter 17620 asks that the final rule reach a balance between protecting public health 

and avoiding unnecessary costs on the regulated community. The commenter notes that the EPA has 

projected substantial reductions in the emissions of Hg, HCl, fine PM and SO2, all of which are needed 

to protect public health. The commenter further notes that industry testing supports emission standards 

of the stringency proposed and the technology to meet the proposed standards has been in use for 10 to 

40 years.

Response to Comment 2: The EPA agrees with the commenter’s assessment that the rule achieves 

important reductions in the emissions of several air pollutants without being unduly burdensome.

Comment 3: Commenter 15160 sees the proposed rule as an important step toward ensuring that the 

living and working environments of all Carolinians are reasonably safe and encourages the EPA to 

maintain the same level of strictness in the final rule.

Response to Comment 3: The EPA thanks the commenter for their support.

Comment 4: Commenter 17884 sees the proposed rule as having little, if any, health benefit and 

believes it may endanger public health and welfare by reducing the disposable income of people for the 

necessities of life.

Response to Comment 4: The EPA does not agree with the commenter’s assertion that the rule will 

achieve little or no health benefit, and the EPA’s position is supported by information on the benefits of 

the rule documented in the rulemaking record. The commenter also makes an assertion which relies on a 

theory that the cost of a rule will result in lost income that will, in turn, result in negative health effects 

that offset the positive health effects of the rule. (This is sometimes referred to as a “health-health 

tradeoff.”) The EPA also disagrees with this claim and notes that there are a number of conceptual and 

empirical problems with any attempt to quantify the health-health tradeoffs of regulatory action to 

control air pollution. Claims about health-health trade-offs rely on questionable applications of crosssectional data and ignore key factors that may influence changes in population health risks. Additionally, 

marginal decreases in household income caused by the pass-through costs of the regulation are unlikely

to cause large changes in any single aspect of household spending, such as health care. These analyses

also fail to consider that household income may increase if individuals are able to work (or work more) 
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as a result of improved health, offsetting some or all of the pass-through costs of the rule. For these and 

other reasons, the EPA’s science and economic peer review panels have consistently advised against 

incorporating alleged health-health trade-offs in EPA analyses of regulatory effects.

Comment 5: Commenter 17973 states that the fleet of coal-fired EGUs in the U.S. is aged and 

inefficient, having operated in most cases without modern controls for 35 years or more. The commenter 

considers the proposed rule to be overdue, as all other major source categories of HAP have 

implemented controls under MACT requirements already. The commenter believes that a wellcontrolled EGU equipped with a baghouse, SO2 scrubber and SCR can meet the proposed standards.

Response to Comment 5: The EPA thanks the commenter for their support.

Comment 6: Commenter 19214 believes HAP emissions reductions beyond present levels are needed 

for the U.S. to fulfill the mission under the National Park Service Organic Act to protect national parks 

in an unimpaired condition for future generations.

Response to Comment 6: The EPA agrees with the commenter’s statement that HAP reductions will 

have a positive environmental impact in addition to the health benefits quantified for this regulation.

Comment 7: Commenter 19686 states that to better assess the impact of the rule and any forthcoming 

actions by the EPA, they recommend that the EPA provide Tribes with an appropriate number of 

monitors of various types to establish baseline monitoring data for criteria pollutants and HAP.

Response to Comment 7: The agency encourages interested tribes to work with the EPA Regional 

Offices to determine where monitoring would be appropriate, as monitoring resources are typically 

supported with state and tribal air grants.

Comment 8: Commenter 16849 states that even under revised averaging periods, TRONA and DSI is 

not a viable option, as is incorrectly stated by the EPA (“IPM Parsed Results - Policy Case,” Unplanned 

DSI Installations by 2015 includes Asbury: 2076_B_1).

Response to Comment 8: The EPA believes that DSI has the potential to be a useful and cost-effective 

control technology option for many units. We also understand that it is not an appropriate option for all 

facilities. Overall the EPA believes that the technology is most applicable for units burning lower-sulfur 

content coal (including, potentially, low-sulfur bituminous coal).

Comment 9: Commenter 17884 states that the EPA erred by failing to consider the negative health and 

welfare consequences of its proposed rule. According to the commenter, the proposed rule will have 

little, if any, health benefit and will endanger the public and welfare by reducing the disposable income 

people will have for the necessities of life. Because the purpose of the CAA is to protect public health 

and welfare, failure to consider the negative health consequences is arbitrary and capricious and 

otherwise not in accordance with law. See AT&T Corp. v. Iowa Utils. Bd., 525 U.S. 366, 388 (1999) 

(invalidating agency interpretation not “rationally related to the goals” of the governing statute).

Response to Comment 9: The EPA disagrees with the commenter that our interpretation of the statute 

is in error for the reasons set forth in the proposed rule and this final action. The EPA also does not 

agree with the commenter’s assertion that the rule will achieve little or no health benefit, and the EPA’s 

position is supported by information on the benefits of the rule documented in the rulemaking record. 

The commenter also makes an assertion which relies on a theory that the cost of a rule will result in lost 
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income that will, in turn, result in negative health effects that offset the positive health effects of the 

rule. (This is sometimes referred to as a “health-health tradeoff.”) The EPA also disagrees with this 

claim and notes that there are a number of conceptual and empirical problems with any attempt to 

quantify the health-health tradeoffs of regulatory action to control air pollution. Claims about healthhealth trade-offs rely on questionable applications of cross-sectional data and ignore key factors that 

may influence changes in population health risks. Additionally, marginal decreases in household income 

caused by the pass-through costs of the regulation are unlikely to cause large changes in any single 

aspect of household spending, such as health care. These analyses also fail to consider that household 

income may increase if individuals are able to work (or work more) as a result of improved health, 

offsetting some or all of the pass-through costs of the rule. For these and other reasons, the EPA’s 

science and economic peer review panels have consistently advised against incorporating alleged healthhealth trade-offs in EPA analyses of regulatory effects. 
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CHAPTER 7: STATUTORY AND EXECUTIVE ORDERS

7A - Executive Order 12866, Regulatory Planning and Review and Executive Order 13563, 

Improving Regulation and Regulatory Review

Commenters: 17638, 17648, 17681, 17702, 17713, 17715, 17721, 17734, 17751, 17757, 17758, 17768, 

17806, 17842, 17833, 17868, 17884, 17911, 17917, 17919, 18016, 18018, 18446, 18486, 19042, 19114

1. The EPA did not comply with EO 13563.

Numerous commenters (17638, 17681, 17702, 17713, 17715, 17721, 17751, 17757, 17758, 17842, 

17868, 17884, 17911, 17917, 17919, 18106, 18018, 18446, 18486, 19042, 19114) state that the EPA 

failed to comply with the requirements of EO 13563.

Comment 1: Multiple commenters (17638, 17713, 17884, 18446, 18486, and 19114) state that the EPA 

failed to consider the cumulative impacts of the proposed rules as required by EO 12866 and EO 13563. 

Commenter 17638 states the regulation’s benefits do not justify its costs nor impose the least burden on 

society taking into the costs of cumulative regulations. Commenter 17884 believes the EPA is producing 

a series of rule-by-rule RIAs that narrowly define what impacts the specific rule at issue has, which has 

the result of minimizing the impact of any one rule and avoiding taking responsibility for the actions 

utilities are taking in anticipation of the EPA’s entire regulatory agenda. Commenter 18446 cites a report 

by the National Economic Research Associates (NERA) that shows that the combination of the 

Transport Rule and the Utility MACT Rule will be a serious blow to the economy, causing a net loss of 

1.4 million jobs by 2020, and the combination of the two regulations will also cause a substantial 

increase in retail electricity prices, with the price increase estimated to top 23 % in some areas of the 

country. Commenter 18446 suggests the EPA withdraw the rule until the agency conducts a cumulative 

impact analysis.

Commenter 17715 suggests the proposed rule does not take into account harmonization with other 

regulations, such as the effect of this rule coupled with future requirements surrounding Coal 

Combustion Residuals (CCR), revised NAAQS, regulations surrounding cooling water intake 

impingement and entrainment (316(b)) and GHG regulations that will also be affecting sources in 

upcoming years. 

Commenter 17734 states that there are a large number of related rulemaking efforts coming out in the 

near term, including revisions to the NAAQS for PM2.5, ozone, and 1-hour SO2; a new GHG NSPS; and 

the recently promulgated CSAPR, which will make it difficult for implementing agencies and affected 

facilities to determine the most efficient use of resources to allocate in order to cost-effectively achieve 

compliance. The commenter suggests that if the agency can coordinate, reconcile, and harmonize the 

overlapping regulatory requirements, it will help to lessen these difficulties.

Commenter 17757 notes that the EPA analysis failed to take into account the impact of each of the 

CSAPR and the proposed EGU air toxics rule on the common objective of appropriate and reasonable 

emissions control.

Commenter 17842 states that while the rule estimates costs of compliance and anticipated retirements, it 

is the collective impact of all emission regulations affecting EGUs that the industry fears will create a 

snowballing cost effect, ultimately taking utilities to a point where they would have been better off 

investing in other base load generation sources. The commenter believes the proposed Utility MACT
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rule does not account for these concerns, and the resulting uncertainty places utilities in a very 

disagreeable position in terms of generation planning.

Commenter 17917 states that the EPA should consider the cumulative effects of the host of proposed 

and recently final rules, including these proposed rules, to the power utility and manufacturing sectors, 

not to mention ratepayers and others affected. The commenter believes these rules neither promote 

economic growth, competitiveness nor job creation.

Commenter 17919 states the EPA should address the timeframe and content of overlapping rules for the 

power sector, beginning with Utility MACT. The commenter believes rules should impose the “least 

burden,” taking into account the multiple and overlapping rules facing the power sector. Where the EPA 

has the capacity for flexibility, such as in the control of non-Hg HAP, subcategorization, determination 

of the MACT floor, and other areas, the commenter believes the EPA should do so. The commenter

notes that numerous rules promulgated or expected to be promulgated in 2010-2012, in conjunction with 

Utility MACT, means that the generating units subject to these rules would either have to undertake the 

installation of extensive retrofits on an unrealistic timeframe or else shutdown entirely. The commenter

suggests that the EPA extend the compliance period in the proposed rule to allow for such retrofits.

Commenters 17806 and 17833 state that the proposed rule, in addition to the NSPS for GHG emissions, 

new regulations for handling coal ash, and new revisions to the ozone and PM NAAQS, will have a 

negative impact on the economies of many regions. Commenters add that the EPA has not described 

how the regulations interrelate or whether they have a collective benefit. Commenter requests that the 

agency withdraw all the proposals mentioned and conduct a cumulative impact assessment.

Response to Comment 1: The Agency did not prepare a cumulative impact analysis to accompany the 

rule for the following reasons: 1) the various EO requirements that the Agency must comply with 

require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the 

impacts specific to a particular rule in order to judge the merits of the regulation; 3) estimates specific to 

a particular rule are more transparent than those from a cumulative impact analysis. A cumulative 

impact analysis lumps several regulations together and can potentially mask a high-cost/low benefit 

regulation among other rules that may have large net benefits. By analyzing each regulation separately, 

EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this 

particular regulation. 

This does not, however, mean EPA has failed to consider cumulative impacts of the regulation. The 

inclusion of CSAPR and other regulatory actions (including federal, state, and local actions) in the IPM 

base case reflects the level of controls that are likely to be in place in response to other requirements 

apart from MATS. This base case provides meaningful projections of how the power sector will respond 

to the cumulative regulatory requirements for air emissions, while isolating the incremental impacts of 

MATS. These results are presented in Chapter 3 of the RIA.

Additionally, the Agency does reflect on the broader cumulative impacts of our regulations. In March 

2011, EPA issued the Second Clean Air Act Prospective Report which assessed at the benefits and costs 

of regulations pursuant to the 1990 Clean Air Act Amendments. The study examines the cumulative 

impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As 

shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 

trillion for the year 2020, a figure that dwarfs the direct costs of implementation ($65 billion). The full 

report is at http://www.epa.gov/air/sect812/prospective2.html. 
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The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantly 

exceed their direct costs, which means economic welfare and quality of life for Americans were 

improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs 

combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed 

using any reasonable alternative assumptions or methods. This conclusion is likely to also be attributable 

to this rule as shown in the RIA.

In implementing rules such as the MATS, emission controls may lead to reductions in ambient PM2.5 and 

ozone below the NAAQS for PM and ozone in some areas and assist other areas with attaining these 

NAAQS. Although both RIAs calculate PM and ozone costs and benefits, it is important to note that 

there are key differences in the design and analytical objectives of a NAAQS RIA and one for a rule 

such as MATS. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air

quality standard nationwide based on an array of emission control strategies for different sources. In 

short, NAAQS RIAs hypothesize, but do not predict, the control strategies that states may choose to 

enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or 

benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the 

costs and benefits of other regulations that result in specific costs of control and emission reductions. 

Some costs and benefits estimated in the final MATS RIA account for the same air quality 

improvements as estimated in the illustrative PM2.5 and ozone NAAQS RIA, but these effects are only

counted once when considering cumulative costs and benefits.

Comment 2: Commenter 19042 suggests the EPA failed to follow the guidelines in EO 13563 for 

assessing the impact of the proposed regulation on federal agencies as well as state and local 

governments. The commenter cites OMB Circular A-4, suggesting that the EPA is required to consider 

as part of its RIAs, significant increases in the federal government’s administrative costs. The 

commenter believes that if the EPA’s Utility MACT standards result in higher electricity costs for itself 

and other federal agencies, thereby making it more difficult to administer government programs, such 

costs are considered administrative in nature.

Response to Comment 2: The EPA disagrees with the commenter’s assertion that the agency failed to 

follow the guidelines in EO 13563 and OMB Circular A-4. Circular A-4 requires the analysis of 

government administrative costs or savings when those effects are expected to be significant. The EPA’s 

analysis of costs does include direct costs to government-owned facilities that are subject to regulation 

under the rule. The agency does not believe that the indirect administrative costs are large enough to 

have a significant impact.

Comment 3: Commenters 17702 and 18018 believe the EPA has an obligation to maintain consistency

in its regulations when addressing court vacaturs and remands of CAIR and CAMR. The commenters

also state the EPA increased the stringency of both the Clean Air Transport Rule (CATR) and the 

proposed utility air toxic rule beyond what is necessary to address the deficiencies identified by the 

Courts.

Response to Comment 3: The EPA disagrees with the commenters’ assertions concerning CAMR and 

notes that comments on CAIR are outside the scope of this action. The D.C. Circuit Court vacated, not 

remanded, CAMR because the Court determined that the EPA had not properly delisted EGUs from the 

section 112 list of sources and the EPA did not have the authority to regulate HAP emissions under 

section 111 for source categories listed under section 112. (New Jersey v. EPA, 517 F.3d 574, 583 (D.C. 

Cir. 2008).) The EPA is finalizing standards for EGUs under section 112(d) of the CAA and we 
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maintain that our action is consistent with the D.C. Circuit Court’s decision does not exceed the 

minimum requirements of the statute.

Comment 4: Commenter 17638 states that the EPA did not respond to a Congressional inquiry

regarding statements that the EPA coordinated with DOE, FERC, the National Electric Reliability

Council (NERC), Public Utility Commissions (PUCs), and Regional Transmission Organizations 

(RTOs).

Response to Comment 4: The EPA is separately working on those responses. Status of the EPA 

responses to Congressional inquiry does not affect the EPA’s authority or responsibility under section 

112 to issue final emission standards for EGUs.

Comment 5: Several commenters (17868, 17758, 17911, 18106) state the EPA has not proposed any of 

the regulatory options to reduce burdens and maintain flexibility in order to comply with the EO

requirements to consider flexible approaches. Commenter 17911 notes the EPA failed to respond to the 

recommendation for less intrusive regulatory approaches suggested during the SBAR Panel process. 

Commenter 17758 states that many of the proposed measures for demonstrating compliance impose 

unnecessary burdens and excessive costs in contradiction to the EO. The commenter recommends these 

restrictive requirements be removed.

Response to Comment 5: The EPA believes it has appropriately incorporated provisions that provide 

regulated EGUs with the maximum flexibility permitted by the statute to reduce emissions and achieve 

compliance in the most cost-effective and efficient manner possible for the particular EGU, while 

assuring that significant reductions in emissions and the health benefits attendant to such reductions will 

be realized. Examples include: (1) the work practice standards for dioxin/furans and non-dioxin/furan

organic HAP, (2) the EPA’s treatment of variability in setting emission standards, (3) the provisions 

allowing emissions averaging to demonstrate compliance, (4) the availability of surrogates to determine 

compliance, (5) the choice for existing sources to comply with either input-based or output-based 

emission limitations, (6) the statutory eligibility for a 1-year extension to comply with the rule in the 

event that the additional time is necessary for installation of controls, consistent with the statutory

requirements of section 112(i)(3), and (7) the provision of an affirmative defense to any malfunction.

Comment 6: Commenter 17751 states the EPA has not demonstrated that it has considered the relative 

costs of achieving the benefits associated with the proposed regulation affecting the EGU sector by 

means of alternative regulatory strategies.

Response to Comment 6: Although the proposed rule did not include a full quantitative analysis of a 

more and less stringent regulatory alternative, a quantitative analysis of costs was included in the MACT

Floor TSD to illustrate the feasibility of the beyond-the-floor standard for lignite. The analysis of the 

floor for all subcategories constitutes a less stringent alternative than the proposed standard. 

Additionally, the proposal includes a qualitative discussion of a number of alternative approaches such 

as a health-based standard and alternative subcategorization.

Comment 7: Commenter 17721 suggests that the proposed rule would negatively impact innovation if 

ACI technology remains the only EPA-endorsed Hg control technology. The commenter suggests that 

the proposed rule include a variety of Hg control systems, including DLPS technology.

Response to Comment 7: The commenter is incorrect – the EPA does not endorse any specific type of 

pollution control technology, nor does it mandate or prohibit technologies. The MACT standard is an 
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emission-based standard that is established by considering the maximum emission reductions currently

achieved by electricity generating units. Individual facilities are free to use whatever technology they

wish in order to achieve this standard. Contrary to the commenter’s belief, the MACT standard 

encourages innovation by spurring companies to develop more effective and efficient methods for 

achieving the necessary emission reductions.

Comment 8: Commenter 17681 states that the EPA must explain how the proposed rule utilizes the best 

techniques to accurately quantify present and future benefits. Commenter 17681 states that the EPA 

must explain how the proposed rule ensures the objectivity of scientific and technological information 

and processes to support the action.

Response to Comment 8: The EPA recognizes its obligations under EO 13563 to use the best available 

techniques to accurately quantify both present and future costs and benefits as well as to ensure the 

objectivity of scientific and technological information and processes used in its analysis. As such, the 

EPA relies upon guidance from its independent scientific and economic review panels and employs peer 

reviewed processes and technical literature in completing its analyses. All necessary documentation is 

provided in the RIA and technical support materials accompanying the final rule.

Comment 9: Commenter 17868 acknowledges that the EPA has discretion in developing utility air 

toxics under section 112, and that EO 13653 provides important guidance as to use of this discretion. 

The commenter believes the projected cost for the rule is significant while providing only minimal 

benefits from the direct reduction of HAP. The commenter notes that 99.99% of the benefits from the 

proposed rule will result from co-benefits associated with estimated reductions of SO2 and NOX, 

resulting in lower ambient PM2.5 and ozone levels; however, these co-benefits are expected to occur 

following the implementation of other CAA requirements in progress. 

Response to Comment 9: The EPA disagrees with the commenter’s assertion that the benefits achieved 

from this rule are expected to occur from the implementation of other CAA requirements. In 

implementing rules such as the MATS, emission controls may lead to reductions in ambient PM2.5 and 

ozone below the NAAQS for PM and ozone in some areas and assist other areas with attaining these 

NAAQS. Although both RIAs calculate PM and ozone costs and benefits, it is important to note that 

there are key differences in the design and analytical objectives of a NAAQS RIA and one for a rule 

such as MATS. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air 

quality standard nationwide based on an array of emission control strategies for different sources. In 

short, NAAQS RIAs hypothesize, but do not predict, the control strategies that States may choose to 

enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or 

benefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the 

costs and benefits of other regulations that result in specific costs of control and emission reductions. 

Some costs and benefits estimated in this RIA account for the same air quality improvements as 

estimated in the illustrative PM2.5 and ozone NAAQS RIA, but these effects are only counted once when 

considering cumulative costs and benefits. The EPA believes that to properly understand the impacts of 

this rule, it is equally important to identify the co-benefits from reductions in PM and ozone as it is to 

identify the direct benefits resulting from reductions in HAP.

Comment 10: Commenter 17638 believes the EPA has not provided sufficient time for the public to 

meaningfully participate in this rulemaking, and the EPA’s adherence to the November finalization date 

precludes the EPA from meaningfully understanding and responding to comments that will be provided. 

The commenter believes if the EPA does not appropriately change this schedule, the EPA’s actions are 

(and will be) arbitrary and capricious, and a violation of the Administrative Procedure Act. At a 
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minimum, the commenter suggest the EPA must explain how its actions are consistent ·with the 

‘‘‘General Principles” and “Public Participation” directives of EO 13563.

Response to Comment 10: The EPA is mindful both of its obligation to provide an opportunity for 

public comment and of its obligation to proceed with this rule in a timely manner, but disagrees with the 

commenter’s assertion that it has acted arbitrarily or capriciously with regard to these obligations. The 

agency is obligated to finalize the MATS by December 16, 2011, as directed by the D.C. Circuit Court. 

This date reflects a 30-day extension the EPA obtained from the original November 16, 2011 deadline. 

The proposed rule was signed on March 16, 2011 and the public comment period was scheduled to close 

on July 5, 2011. The EPA extended the comment period an additional 30 days to close August 4, 2011. 

Agency staff began reviewing comments and identifying key issues prior to the close of the comment 

period. Additionally, the EPA held three public information sessions in Chicago, Atlanta and 

Philadelphia during the month of May where the public was able to provide comment on the rule. The 

EPA believes that its approach to public comments meets or exceeds both the letter and spirit of the 

EO’s guidance on public participation.

Comment 11: Commenter 17702 believes the EPA increased the stringency of the proposed rule 

without regard to the lack of additional health benefits that might accrue or additional costs that will be 

incurred by the public. The commenter instead states that the EPA should use its discretion to minimize 

the cost of the rule while still providing for safety of the public.

Response to Comment 11: The EPA disagrees with the commenter and notes that under the CAA, the 

agency has limited discretion in setting a MACT standard. The MACT standard is a technology-based 

standard based on the performance of existing sources in the regulated source category. It provides the 

minimum level of HAP emission control required for new and existing sources. The “MACT floor” for 

new sources is equivalent to the level of HAP emission control achieved by the best-controlled similar 

source, and the “MACT floor” for existing sources is the average level of HAP emission control 

achieved by the top 12% of that industry group’s currently operating sources. Based on the requirements 

of the CAA, the EPA can only consider economic, environmental, and public health impacts when 

setting a standard more stringent than the MACT floor. Although the EPA explored several alternatives 

for standards beyond the MACT floor, ultimately, only the lignite subcategory was subject to a more 

stringent standard.

2. The EPA did comply with EO 13563.

Comment 12: Commenter 17648 states that the proposed rule complies with EO 13563 by producing 

benefits that far exceed its costs and promoting economic and job growth. The commenter believes the 

EPA also complied with the other requirements of the EO by involving the public, employing where it 

can flexible approaches such as averaging, establishing performance based standards, relying on sound 

objective science, requiring coordination and harmonization of regulatory actions and the promotion of 

innovation. 

Response to Comment 12: The EPA thanks the commenter for these observations.

3. Legal considerations and EO 12866 and 13563.

Comment 13: Commenter 17768 believes the EPA has the legal authority to reinterpret “appropriate” to 

allow for the consideration of costs and benefits, as well as the statutory authority to consider net 
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benefits under section 112(d), and should do so to best adhere to the principles of EO 12866 and 13653, 

which instruct agencies to maximize net benefits unless a statute requires another regulatory approach.

Comment 14: Commenter 17842 encourages the EPA to consider the overall objective of section 

112(n) to reduce Hg emissions while considering the call of EO 13563 to “propose or adopt a regulation 

only upon a reasoned determination that its benefits justify its costs.”

Response to Comments 13 - 14: The Executive Orders supplement but cannot modify or diminish 

statutory requirements. The EPA believes the agency’s interpretations of section 112(n)(1) and 112(d) 

constitute the most defensible interpretation of the statute. While we agree that the cited executive orders 

direct the EPA to maximize benefits and minimize costs to regulated industries, we believe that we have 

done so within the constraints imposed by the CAA.
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7B - Paperwork Reduction Act

No comments were received specifically on the Paperwork Reduction Act (PRA) requirements, although 

the PRA is mentioned in the context of some comments regarding another topic and have been 

addressed as appropriate.
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7C - Regulatory Flexibility Act (RFA), as Amended by the Small Business Regulatory 

Enforcement Fairness Act of 1996 (SBREFA)

Commenters: 10987, 16705, 17004, 17400, 17608, 17648, 17689, 17712, 17805, 17817, 17868, 17885, 

17911, 18032, 19094, 19121, 8443

1. General.

Comment 1: Commenters 16705 and 17400 express concern that smaller utilities and those in rural 

areas will be unable to get vendors to respond to their requests for proposals, since they will be able to 

make more money serving larger utilities.

Response to Comment 1: The preamble to the proposed rule (76FR 25054, May 3, 2011) provides a 

detailed discussion of how the EPA determined compliance times for the proposed rule. The EPA has 

provided pursuant to section 112(i)(3)(A) the maximum 3-year period for sources to come into 

compliance. Sources may also seek a 1-year extension of the compliance period from their Title V

permitting authority if the source needs that time to install controls. CAA section 112(i)(3)(B). If the 

situation described by commenters (i.e., where smaller utilities and those in rural areas are less able to 

get vendor responses to requests for proposals than larger utilities) results in the source needing 

additional time to install controls, they would be in a position to request the 1-year extension. The EPA 

discusses in more detail elsewhere in this document how the agency plans to address those units that are 

still unable to comply within the statutorily mandated period.

2. Concerns with SBAR Panel.

Comment 2: Multiple commenters (8443, 10987, 17689, 17712, 17817, 17885, 17868) believe Small 

Entity Representatives (SERs) were not provided with regulatory alternatives including descriptions of 

significant regulatory options, differing timetables, or simplifications of compliance and reporting 

requirements, and subsequently presented with an opportunity to respond. Commenters reference the 

Report of the SBAR Panel, citing the following text: “SERs stated that they do not believe they were 

provided the opportunity for effective participation in the Federal regulatory process as required by

SBREFA.”

Comment 3: Commenter 17608 believes the EPA’s formal SBAR Panel notification and subsequent 

information provided by the EPA to the panel did not include information on the potential impacts of the 

rule as required by section 609(b)(1). The commenter states that such information was not provided until 

the EPA’s submission to OMB/OIRA under EO 12866, after consultation with the SERs was complete.

Comment 4: Several commenters (8443, 17608, 17868) suggest that the EPA’s rulemaking schedule 

put pressure on the SBAR Panel through the abbreviated preparation for the panel. Commenters 8443 

and 17868 note that only one panel meeting was provided and after that meeting, Panel members were 

given a mere 14 days to prepare written comments on an incredibly complex topic. Commenters note 

that the lack of a pre-panel consultation resulted in the lack of SER involvement with the EPA to draft 

outreach materials and participate meaningfully.

Comment 5: Commenters 17608 and 17868 state that the EPA did not identify regulatory alternatives 

for the SBAR Panel to consider. The commenters state the EPA did not present a proposed regulatory

approach with sufficient detail for SERs to identify potential economic effects of suggest specific 

regulatory alternatives; it had only presented them with broad discussions and raw data upon which the 
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EPA would eventually make discretionary judgments. Commenters do not believe that the EPA’s 

response to the SBAR Panel concerns regarding the deficiencies in the process relieves the EPA of its 

obligations under section 609(b).

Comment 6: Several commenters (8443, 17608, 17911) express concerns that the EPA did not provide 

participants more than cursory background information on which to base their comments. Commenter

17608 states that the EPA did not provide deliberative materials, including draft proposed rules or 

discussions of regulatory alternatives, to the SBAR Panel members. The commenter believes such 

materials could have guided the Panel’s deliberations towards regulatory alternatives that minimize the 

burden on small entities.

Comment 7: Commenter 17608 states the SBAR Panel Report does not meet the statutory obligation to 

recommend less burdensome alternatives. The commenter suggests the EPA Panel members declined to 

make recommendations that went further than consideration or investigation of broad regulatory

alternatives, with the exception of those recommendations in which the EPA rejected alternative 

interpretations of the CAA section 112 and relevant court cases. The commenter does not believe the 

Panel was provided with information necessary to make recommendations beyond a restatement of the 

EPA’s existing obligations or to evaluate specific regulatory decisions and the impacts of those 

decisions on particular small entities or small entities in general.

Comment 8: Commenters 17868 and 17911 note that the EPA did not respond to the concerns of the 

small business community, the Small Business Administration (SBA), or OMB, ignoring concerns 

expressed by the SER panelists. Commenter 17868 notes specifically that the EPA did not respond 

regarding the 3-year compliance deadline and by not acting upon OMB’s suggestions to meet again 

before the rule was proposed.

Comment 9: Commenter 19121 believes the EPA failed to convene required meetings and hearings 

with affected parties as required by law for small business entities.

Comment 10: Commenter 8443 notes that public power accounts for about 16% of all kW-hr sales to 

retail electricity consumers, approximately 46% of the MW-hr of electricity produced by public power 

systems are generated using coal, and more than 90% of public power utility systems meet the definition 

and qualify as small businesses under the SBREFA, giving more importance to the Panel.

Response to Comments 2 - 10: The RFA requires that panels collect advice and recommendations 

from SERs on the issues related to: 

- the number and description of the small entities to which the proposed rule will apply; 

- the projected reporting, record keeping and other compliance requirements of the proposed rule; 

- duplication, overlap or conflict between the proposed rule and other federal rules; and 

- alternatives to the proposed rule that accomplish the stated statutory objectives and minimize any

significant economic impact on small entities.

The RFA does not require a covered agency to create or assemble information for SERs or for the 

government panel members. Although section 609(b)(4) requires that the government panel members 

review any material the covered agency has prepared in connection with the RFA, the law does not 
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prescribe the materials to be reviewed. The EPA’s policy, as reflected in its RFA guidance, is to provide 

as much information as possible, given time and resource constraints, to enable an informed panel 

discussion. In this rulemaking, because of a court-ordered deadline, the EPA was unable to hold a prepanel meeting but still provided SERs with the information available at the time, held a standard Panel 

Outreach meeting to collect verbal advice and recommendations from SERs, and provided the standard 

14-day written comment period to SERs. The EPA received substantial input from the SERs, and the 

Panel report describes recommendations made by the Panel on measures the Administrator should 

consider that would minimize the economic impact of the proposed rule on small entities. The EPA 

believes it has properly complied with the RFA.

3. Impacts on small businesses.

Comment 11: Commenter 17004 requests that the EPA work with utilities such that new regulations are 

as flexible and cost efficient as possible.

Response to Comment 11: In developing the final rule, the EPA has considered all information 

provided prior to, as well as in response to, the proposed rule. The EPA has endeavored to make the 

final regulations flexible and cost efficient while adhering to the requirements of the CAA.

Comment 12: Commenter 17868 is concerned about the ability of small entities or nonprofit utilities 

such as those owned and/or operated by rural electric co-op utilities, and municipal utilities to comply

with the proposed standards within 3 years. The commenter believes that the EPA disregarded the SER

panelists who explained that under these current economic conditions they have constraints on their 

ability to raise capital for the construction of control projects and to acquire the necessary resources in 

order to meet a 3-year compliance deadline.

Response to Comment 12: The preamble to the proposed rule (76 FR 25054, May 3, 2011) provides a 

detailed discussion of how the EPA determined compliance times for the proposed rule. The EPA has 

provided pursuant to section 112(i)(3)(A) the maximum 3-year period for sources to come into 

compliance. Sources may also seek a 1-year extension of the compliance period from their Title V

permitting authority if the source needs that time to install controls. CAA section 112(i)(3)(B). If the 

situation described by commenters (i.e., where small entities or nonprofit utilities constraints on ability

to raise capital for construction of control projects and to acquire necessary resources) results in the 

source needing additional time to install controls, they would be in a position to request the 1-year 

extension. The EPA discusses in more detail elsewhere in this document how the agency plans to 

address those units that are still unable to comply within the statutorily mandated period.

Comment 13: Commenters 17868 and 18032 believe the EPA did not adequately consider the 

disproportionately large impact on smaller generating units. The commenters note the diseconomies in 

scale for pollution controls for such units. Commenter 17868 notes the rule will create a more serious 

compliance hurdle for small communities that depend on coal-fired generation to meet their base load 

demand. The commenter notes that by not subcategorizing units, the EPA is dictating a fuel switch due 

to the disproportionately high cost on small communities.

Commenter 18032 believes the MACT and NSPS standards are unachievable by going too far without 

really considering the impacts on small municipal units, as public powers is critical to communities, 

jobs, economic viability and electric reliability.
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Commenter 17868 believes that the EPA has not fully recognized the number of small entities that are 

impacted by the rule and underestimated the impacts of the proposed rule on smaller utilities despite the 

SER panel.

Comment 14: Commenter 19094 is a generating and transmissions electric cooperative which qualifies 

as a small entity and believes the proposed rule will ultimately result in increased electricity costs to its 

members and will negatively impact the economies of the primarily rural areas that they serve.

Comment 15: Commenter 17648 believes there is no legal or factual basis for creating subcategories or 

weaker standards for state, tribal, or municipal governments or small entities that are operating obsolete 

units, particularly given the current market situation and applicable equitable factors. The commenter 

suggests both the EPA’s and SBA’s analyses focus exclusively on the effects on entities causing HAP 

emissions and primarily on those operating obsolete EGUs, and fail to consider either impacts on 

downwind businesses and governments or the positive impacts on small entities and governments 

owning and operating competing, clean and modern EGUs.

Response to Comments 13 - 15: The EPA disagrees with the commenters’ belief that the impacts on 

smaller generating units were not adequately considered when developing the proposed rule. The EPA 

determined the number of potentially impacted small entities and assessed the potential impact of the 

proposed action on small entities, including municipal units. A similar assessment was conducted in 

support of the final action. Specifically, the EPA estimated the incremental net annualized compliance 

cost, which is a function of the change in capital and operating costs, fuel costs, and change in revenue. 

The projected compliance cost was considered relative to the projected revenue from generation. Thus, 

the EPA’s analysis accounts not only for the additional costs these entities face resulting from 

compliance, but also the impact of higher electricity prices. The EPA evaluated suggestions from SERs, 

including subcategorization recommendations. In the preamble to the proposed rule, the EPA explains 

that any basis for subcategorizing should be related to an effect on emissions, rather than some 

difference which does not affect emissions performance. The EPA does not see a distinction between 

emissions from smaller generating units versus larger units. One commenter (17648) believes that there 

is no legal or factual basis for creating subcategories or weaker standards for state, tribal, or municipal 

governments or small entities that are operating obsolete units. The commenter points out that relaxation 

in standards would not only harm downwind governments and small businesses who incur higher labor 

costs due to pollution, but will harm other small businesses and state, tribal and local governments 

developing or operating generation facilities using modern and less polluting generation technologies. 

The EPA acknowledges and generally agrees with the commenter’s assertion.

Comment 16: Commenter 18032 notes that the EPA recognizes LEEs in the rule such that they should 

receive less onerous monitoring requirements; however, the EPA does not recognize that small and 

LEEs also need and merit more flexible and achievable pollution control requirements. The commenter 

notes that the capital costs for emissions control at small-sized utility units is disproportionately high 

due to inefficiencies in Hg removal, space constraints for control technology retrofits, and the fact that 

small units have fewer rate base customers upon which to spread these costs. The commenter cites the 

Michigan Department of Environmental Quality report titled “Michigan’s Mercury Electric Utility

Workgroup, Final Report on Mercury Emissions from Coal-Fired Power Plants,” (June 2005). The 

commenter notes that the EPA has addressed such concerns previously, citing the RIA for the 1997 8-

hour ozone standard. The commenter also suggests smaller utility systems generally have less capital to 

invest in pollution control than larger, investor-owned systems, due to statutory inability to borrow from 

the private capital markets, statutory debt ceilings, limited bonding capacity, borrowing limitations 

related to fiscal strain posed by other, non-environmental factors, and other limitations.
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Response to Comment 16: The EPA acknowledges its proposal of reduced monitoring requirements for 

existing units that qualify as low emitting EGUs. Although the EPA does not believe that reduced 

pollution control requirements are warranted for LEEs, including small entity LEEs, we believe that 

flexible and achievable pollution control requirements are promoted through alternative standards, 

alternative compliance options, and emissions averaging as a means of demonstrating compliance with 

the standards for existing EGUs.

Comment 17: Commenter 8443 believes that the EPA should develop more limited monitoring 

requirements for small EGUs. The commenter notes small entities do not possess the monetary

resources, manpower, or technical expertise needed to operate cutting-edge monitoring techniques such 

as Hg CEMS and PM CEMs. The commenter notes the EPA could have identified monitoring 

alternatives to the SBAR panel for consideration.

Response to Comment 17: The EPA provided monitoring alternatives to using PM CEMS, HCl CEMS, 

and Hg CEMS in its standards. The continuous compliance alternatives would be available to all 

affected sources, including small entities. As monitoring alternatives to use of PM CEMS and HCl 

CEMS, sources would be allowed to conduct additional performance testing. Sorbent trap monitoring 

would be allowed in lieu of Hg CEMS.

4. The EPA did not comply with the RFA.

Comment 18: Commenter 17608 believes the EPA has not sufficiently complied with the requirements 

of the RFA or adequately considered the impact this rulemaking would have on small entities. The 

commenter believes the EPA has not given itself the opportunity to engage in meaningful outreach and 

consultation with small entities and therefore recommends that the EPA seek to revise the court-agreed 

deadlines to which this rulemaking is subject, re-convene the SBAR panel, prepare a new initial 

regulatory flexibility analysis (IRFA), and issue it for additional public comment prior to final 

rulemaking.

Commenter 17608 believes the IRFA does not sufficiently consider impacts on small entities as 

identified in the SBAR Panel Report. The commenter believes it is not apparent that the EPA considered 

the recommendations of the Panel. The commenter believes the description of significant alternatives in 

the IRFA is almost entirely quoted from the SBAR Panel Report, which the commenter does not believe 

is an adequate substitute for the EPA’s own analysis of alternatives. The commenter also notes the EPA 

does not discuss the potential impacts of its decisions on small entities or the impacts of possible 

flexibilities. Where the EPA does consider regulatory alternatives in principle, the commenter believes it 

does not provide sufficient support for its decisions to understand on what basis the EPA rejected 

alternatives that may or may not have reduced burden on small entities while meeting the stated 

objectives of the rule. Additionally, the commenter notes that the EPA did not evaluate the economic or 

environmental impacts of significant alternatives to the proposed rule.

Commenter 17608 believes that the EPA’s stated reasons for declining to specify or analyze an area 

source standard are inadequate under the RFA. The commenter believes the EPA must give serious 

consideration to regulatory alternatives that accomplish the stated objectives of the CAA while 

minimizing any significant economic impacts on small entities and that the EPA has a duty to specify 

and analyze this option or to more clearly state its policy reasons for excluding serious consideration of 

a separate standard for area sources.
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Commenter 17608 suggests that the EPA reconvene the SBAR Panel to solicit more meaningful 

consultation with the SERs; the EPA prepare an IRFA that includes descriptions of specific regulatory

alternatives, the effects on small entities of the regulatory alternatives, and the policy reasons for 

selected among them; and the EPA release the IRFA for additional public comment before making any

decisions about the EPA’s preferred options for final rulemaking. The commenter recognizes that the 

EPA will have to request of the litigants and the court an extension of the timeline for final rulemaking 

but feels strongly that this action is necessary.

Comment 19: Commenter 17805 believes the EPA did not fully consider the subcategorization of 

sources such as boilers designed to burn lignite coals versus other fossil fuels, especially in regard to 

non-Hg metal and acid gas emissions. The commenter references the SBAR Panel Report suggestion 

provided in the preamble of the proposed rule that the EPA consider developing an area source versus 

major source distinction for the source category and the EPA’s response.

Comment 20: Commenter 17868 is concerned that the recommendations made by the SER participants 

were ignored and not discussed in the rulemaking. Specifically, the commenter notes the EPA did not 

discuss subcategorizing by age, type of plant, fuel, physical space constraints or useful anticipated life of 

the plant. Nor did the EPA provide any opportunity for smaller emitters to use GACT—often used in 

other EPA MACT regulations to alleviate the regulatory costs and operational difficulties that would 

have burdened other small businesses including dry cleaners, metal fabricating, metal finishing, and 

others.

Comment 21: Commenter 17817 believes it is likely that different numerical or work practice standards 

are appropriate for area sources of HAP, just as in other rulemakings such as the RICE rule, and that the 

EPA would have provided the opportunity for small entities to make such demonstration had they

followed their own regulatory requirements.

Response to Comments 18 - 21: The EPA disagrees with one commenter’s (17608) assertion that the 

agency has not complied with the requirements of the RFA. The EPA complied with both the letter and 

spirit of the RFA, even under the court-ordered deadline. For example, the EPA notified the Chief 

Counsel for Advocacy of the SBA of its intent to convene a Panel; compiled a list of SERs for the Panel 

to consult with; and convened the Panel. The Panel met with SERs to collect their advice and 

recommendations; reviewed the EPA materials; and drafted a report of Panel findings. The EPA further 

disagrees with the commenter’s assertion that the EPA’s IRFA does not sufficiently consider impacts on 

small entities. The EPA’s IRFA, which is included in chapter 10 of the RIA for the proposed rule, 

describes, among other things, the economic impact of the proposed rule on small entities and the 

Panel’s findings. The economic impact of the final rule on small entities is included in chapter 7 of the 

RIA for the final rule. 

Several commenters (17608, 17805, 17868, and 17817) are concerned that recommendations made by 

the SERs were ignored and not considered or discussed in the proposed rulemaking. Specifically, 

commenters cite SER recommendations regarding subcategorization and separate standards for area 

sources. The EPA disagrees with the commenters. The preamble to the proposed standards includes 

detailed discussion of how the EPA determined which subcategories and sources would be regulated (76 

FR 25036-25037, May 3, 2011). In that discussion, the EPA explains the rationale for its proposed 

subcategories based on five unit design types. In addition, the EPA acknowledges the subcategorization 

suggestions from the SERs and explains its reasons for not subcategorizing on those bases. The 

preamble to the proposed standards also includes a discussion of the SERs’ suggestion that area source 
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EGUs be distinguished from major-source EGUs and the EPA’s reasons for not making that distinction 

(76 FR 25020-25021, May 3, 2011).

One commenter (17608) suggests that the EPA pursue an extension of the timeline for final rulemaking 

such that the SBAR Panel can be reconvened and a new IRFA can be prepared and released for public 

comment prior to the final rulemaking. The EPA entered into a Consent Decree to resolve litigation 

alleging that the EPA failed to perform a non-discretionary duty to promulgate CAA section 112(d) 

standards for EGUs. American Nurses Ass’n v. EPA, 08-2198 (D.D.C.). That Decree required the EPA 

to sign the final MATS rule by November 16, 2011, unless the agency sought to extend the deadline 

consistent with the requirements of the modification provision of the Consent Decree. If plaintiffs in the 

American Nurses litigation objected to an extension request, which we believe they would have based on 

their comments on the proposed rule, the agency would have had to file a motion with the Court seeking 

an extension of the deadline. Consistent with governing case law, the agency would have been required 

to demonstrate in its motion for extension that it was impossible to finalize the rule by the deadline 

provided in the Consent Decree. See Sierra Club v. Jackson, Civil Action No. 01-1537 (D.D.C.) 

(Opinion of the Court denying EPA’s motion to extend a consent decree deadline). The EPA negotiated 

a 30-day extension in order to finalize the rule. The EPA was able to complete the rule by December 16, 

2011; accordingly, the agency had no basis for seeking a further extension of time.
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7D - Unfunded Mandates Reform Act of 1995

Commenters: 16859, 17868, 17911, 18023

Comment 1: Commenter 16859 believes the EPA in its proposed rule does not appear to have addressed 

the statement in UMRA section 202(a)(2) directing federal agencies to consider direct state 

administrative costs and to make this information available to the public. The commenter cites concerns 

that state, local and tribal government officials expressed at a meeting with the EPA in October 2010 

regarding the potential burden associated with implementing the rule, noting that the EPA did not 

respond to these concerns in the proposed rulemaking.

Response to Comment 1: UMRA focuses on mandated costs associated with enforceable duties falling 

on states. State administrative costs are not expressly included in UMRA as the type of costs to be 

included in analyzing cost impacts to the states. Thus, the EPA does not interpret state administrative 

costs to be among mandated costs, and state administrative costs were not addressed in the proposed rule 

and also are not addressed in the final rule. The UMRA discussion in the preamble to the final rule 

addresses this response to the commenter’s concern.

Comment 2: Commenter 17868 suggests the EPA failed to meet the requirements of UMRA as the 

proposed rule does not consider significant impacts on small municipalities. These impacts include the 

increased cost of power being driven up by the compliance costs of the proposed rule, and the social and 

economic impacts of the potential shut down of power plants on municipal governments. The 

commenter was unable to find information in the rulemaking record regarding the qualitative and 

quantitative assessment of the anticipated costs and benefits of the proposed regulation on local 

governments, or an assessment of the disproportionate effect of the rule on regions of the country.

Further, commenter 17868 notes that additional regulatory permitting costs would be incurred by public 

power utilities, and therefore any comments submitted by municipal or state governments, including 

their electric utilities, be considered under SBREFA and UMRA. The commenter notes that the adverse 

cost impacts from the EGU MACT would extend directly to municipal and local government operating 

budgets, and that increasing operating costs for such not-for profit power producers would be passed on 

directly to rate payers. The commenter also notes that significant increased costs may reduce Payments 

in Lieu of Taxes to municipal operating budgets, which could in turn result in cuts to essential 

governmental services including emergency services and schools.

Comment 3: Commenter 17911 believes the EPA failed to provide a complete financial analysis of the 

cost to communities in the proposed rule. The commenter identifies specific items which the EPA did 

not take into account: (1) The impact of the rule on the Payment in Lieu of Taxes received by the 

community from the local municipal utility; (2) The additional costs to be borne by city government in 

paying for the electricity that they use for powering city government; (3) The additional costs to borne 

by the city through the utility for increases in default rates on utility payments; (4) The cost to the city

budget of potential downgrade to municipal bond ratings caused by the city having to take on higher 

debt load to pay for the emission upgrades; (5) The disparate impact of the rule on smaller cities and 

smaller generating units; and (6) The social and economic impact of the shutdown of municipal power 

generation in smaller towns and the resulting increase in power costs on the competitiveness of local 

industries and other major employers.

Response to Comments 2 - 3: The EPA assessed the impact of the proposed and final rule on all 

directly-impacted municipalities (those holding covered EGUs). As required by UMRA, the EPA 

provided a written statement of the qualitative and quantitative impacts to state, local, and tribal 
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governments, and the private sector. This analysis is presented for all municipalities in section 10.2 of 

the RIA for the proposed rule and Chapter 7 of the RIA for the final rule, and specifically for small 

municipalities in section 10.1 of the RIA for the proposed rule and section 7.5 of the RIA for the final 

rule. Total compliance costs for all government and private sector entities are presented in Chapter 8 of 

the proposal RIA and Chapter 3 of the final RIA. In the EPA’s analysis, a “small” government 

jurisdiction is defined as the government of a city, county, town, district, or special district with a 

population of less than 50,000. The EPA estimated the incremental net annualized compliance cost, 

which is a function of the change in capital and operating costs, fuel costs, and change in revenue. The 

projected compliance cost was considered relative to the projected revenue from generation. Thus, the 

EPA’s analysis accounts not only for the additional costs these entities face resulting from compliance 

with the proposal, but also the impact of higher electricity prices that government entities should face, 

and does account for projected early retirements due to the proposal among affected units owned by 

government entities. All of these results are included in Chapter 10 of the RIA for the proposed rule and 

Chapter 7 of the RIA for the final rule, and detailed results are found in the docket for the rulemaking.

As previously stated, the EPA’s analysis of costs includes direct compliance costs to units owned by 

states or municipalities that are subject to regulation under the rule. The EPA does not believe that 

indirect administrative costs are large enough to have a significant impact. Additionally, while local 

governments may incur administrative costs as outlined by the commenter, such costs would be nearly

impossible to estimate with any degree of accuracy due to the unique characteristics of each affected 

community and the numerous approaches local governments could take to minimize or offset 

administrative costs of the rule.

Comment 4: Commenters 17868 and 17911 express concerns over an apparent lack of communication 

from the EPA regarding potential impacts of the proposed rule with state and local governments as 

required by UMRA. The commenters discuss these shortcomings with respect to the EPA meeting with 

the “Big Ten” on October 7, 2010. Specifically, the commenters submit that the “Big 10” organizations 

are unlikely to have stakeholders that will be impacted by the MACT rule, and the commenters are not 

aware that any of the state/local governments that the EPA estimates will be impacted by the MACT 

rule received any meaningful communications regarding potential impacts.”

Response to Comment 4: The EPA disagrees with the commenters that there was a lack of 

communication between the EPA and state and local governments regarding potential impacts of the 

proposed rule. Although details of the proposed rule had not been established at the time of the October 

2010 meeting, the EPA believes that meaningful information was shared with representatives of the state 

and local organizations early in the regulatory process. The presentation that the EPA used to overview 

the Utility MACT regulatory effort at the October 2010 meeting with the “Big 10” included information 

indicating that the EPA was early in the process of developing the proposed action. Specifically, the 

presentation included a list of central decision points and potential issues (e.g., MACT floors and 

variability, subcategorization, pollutants for which standards would be established) for which decisions 

had not yet been made and the EPA was seeking input. That presentation is available in the rulemaking 

docket. As pointed out above, even though specific information regarding costs and other consequences 

of regulatory alternatives was not available, decisions and issues that would affect costs and other 

consequences of regulatory alternatives were presented for discussion at the October 2010 meeting with 

the “Big 10.” Thus, this process enabled meaningful and timely input by state and local officials.

The EPA also disagrees with the commenters that the “Big 10” organizations are unlikely to have 

stakeholders potentially impacted by the MACT rule. As examples, The National Association of Towns 

and Townships represent smaller communities, towns and townships, and other suburban and rural 
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localities; the National Association of Counties represents county governments; and the National League 

of Cities serves as a resource to and an advocate for the more than 19,000 cities, villages and towns. In

fact, 48 of the 112 state/local governments the EPA estimated to be potentially impacted by the MACT 

rule are also small government entities. Further, ten SERs were representatives of small entity

representatives that participated in the SBAR panel process for the proposed rule. Thus, the EPA 

disagrees that potentially impacted state/local governments did not receive meaningful communications 

regarding potential impacts either directly or through representation in the Federalism consultation 

and/or the SBAR panel process.

Comment 5: Commenter 17911 notes that the EPA never responded to suggestions by SERs during 

December 2010 that the 3-year timeline proposed by the EPA was both unrealistic and impossible to 

meet.

Response to Comment 5: The preamble to the proposed rule (76 FR 25054, May 3, 2011) provides a 

detailed discussion of how the EPA determined compliance times for the proposed rule. With respect to 

the final rule, the EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period 

for sources to come into compliance. Sources may also seek a 1-year extension of the compliance period 

from their Title V permitting authority if the source needs that time to install controls. CAA section 

112(i)(3)(B). The EPA discusses in more detail elsewhere in this notice how the agency plans to address 

those units that are still unable to comply within the statutorily mandated period.

Comment 6: Commenter 17911 states the EPA failed to fully evaluate the unintended consequences of 

this rule on local economies, especially in mid-sized and smaller communities where a disproportionate 

share of those over 65 and those under the poverty level reside.

Response to Comment 6: The EPA conducted its economic analyses in response to the statutory and 

executive orders requirements that it must follow for economically significant rules such as this one. The 

agency’s analysis included estimates of the increase in retail electricity price both nationally and 

regionally, and this analysis shows no increases in retail electricity price above 7% in 2015, and lower 

price increases thereafter. Such an analysis is informative to meet the requirements of EO 12898 

(Environmental Justice). State and local authorities are best equipped to mitigate impacts related to 

increases in electricity rates.

Comment 7: Commenter 18023 states that the EPA’s RIA must adhere to UMRA and EO 12866 in 

conducting cost-benefit analysis.

Response to Comment 7: The EPA adhered to the requirements of UMRA and EO 12866 in preparing 

the cost-benefit analysis that is presented in the RIA for the proposed and final rules. The agency

presented its analysis of the impact of the rule on federal, state, and local government entities in Chapter 

10 of the RIA for the proposed rule and Chapter 7 of the RIA for the final rule. This analysis serves as 

the written statement that is required under section 202 of the UMRA. Intergovernmental consultations 

as required under section 204 were conducted and were placed in the docket for this rulemaking. The 

agency explained why this standard was proposed, and alternatives to it, in the preamble for the 

proposal. The contents of the RIA are consistent with what EO 12866, and the guidance in OMB 

Circular A-4, requires for an RIA.
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7E - Executive Order 13132, Federalism

Commenters: 16859, 17701, 17791, 17868, 18447

1. Federalism requirements.

Comment 1: Commenter 16859 points out that section 6.(b)(2)(B) of EO 13132 requires that the EPA 

provide to the OMB a federalism summary impact statement (FSIS) containing a number of elements, 

including a statement of the extent to which the concerns of state and local officials have been met. 

Commenter indicates that states continue to remain uncertain of the extent to which the EPA is 

considering state administrative costs, including state administrative costs for this proposed utility

MACT rule.

Response to Comment 1: As required by section 6(b)(2)(B) of EO 13132, the EPA provided a FSIS in 

its proposed rule and provides an updated impact statement in the preamble to the final rule. The final 

rule impact statement presents the EPA’s assessment of the compliance costs of the regulatory option 

being promulgated on state and local governments. In addition, the statement addresses state and local 

officials’ uncertainty regarding the extent to which the EPA is considering state administrative costs. We 

note that state administrative costs are not expressly included in the Federalism guidance as the type of 

costs to be included in analyzing cost impacts to the states. That is, the focus is on mandated costs 

associated with enforceable duties falling on states, and the EPA does not interpret state administrative 

costs to be among mandated costs. 

Comment 2: Commenter 17868 believes that the EPA ignored several principal tenants of EO 13132. 

Specifically, the commenter references section 3(b) of EO 13132, which requires agencies to consult 

with state and local officials to determine whether federal objectives can be attained by other means 

where there are significant uncertainties as to whether national action is authorized or appropriate.

Response to Comment 2: Commenter implies that there is significant uncertainty about the agency’s 

authority to issue the final rule and whether it is appropriate to address the hazards to public health and 

the environment posed by EGUs. The EPA disagrees with the commenter. The requirements of section 

112 of the CAA are unambiguous in imposing a duty on the EPA to establish national emission 

standards for EGUs once it determines that it is appropriate and necessary to do so to protect public 

health and the environment.

Comment 3: Commenter 18447 does not understand why the EPA categorically states that the federal 

government will not provide funds necessary to pay the imposed “substantial direct compliance costs on 

state and local governments.” The commenter believes the costs of complying with the rule will be 

substantial and will impact ratepayers dramatically, potentially driving residents and businesses from the 

city in an effort to seek cheaper electricity elsewhere. The commenter believes its city is more 

disproportionately impacted by the rule than utilities with larger and more diverse generation resources.

Response to Comment 3: EO 13132 provides that when a regulation imposes substantial direct 

compliance costs, the agency has the option of either providing the funds necessary to pay those direct 

costs or consulting with state and local officials. It does not explicitly favor either option. With respect 

to the air toxics regulation for EGUs, the EPA consulted with state and local officials. As described in 

the preamble to the proposed rule, the EPA invited 10 national organizations representing state and local 

elected officials to a consultation meeting that was held on October 27, 2010 (76 FR 25085, May 3, 

1011). The purposes of that consultation were to provide general background on the proposal, answer 
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questions and solicit input from state/local governments. As required by the EO, a FSIS was included in 

the preamble to the proposed rule. An impact statement is also included in the preamble to the final rule.

In response to the commenter’s concerns that their costs of complying with the rule will be substantial 

and disproportionately high resulting in dramatic impacts on their ratepayers, the EPA believes that 

flexible and achievable pollution control requirements are promoted through alternative standards, 

alternative monitoring and compliance options, and emissions averaging as a means of demonstrating 

compliance with the standards for existing EGUs. Moreover, as discussed elsewhere in this document, 

the EPA’s analyses indicate that the impacts of compliance with the rule will not cause a significant 

increase in electricity costs to rate payers.

2. Federal and state interaction.

Comment 4: Commenters 17791 and 17701 appreciate the EPA’s participation in ongoing meetings 

with industry, environmental groups, state air regulators and state energy officers to provide the 

opportunity to better understand how they can work together as rules such as this proposal are 

implemented. The commenters note that the EPA officials have made themselves available and have 

sought input on the rulemaking from their organization representing utility commissioners. The 

commenter encourages continued dialog and interaction between federal and state air and energy

regulators.

Commenter 17791 points out that continued collaboration between the federal agencies, states, and 

industry will be essential to further promoting energy efficiency and reducing emissions. The 

commenter discusses prior state energy efficiency efforts that the EPA was involved with -- the National 

Action Plan on Energy Efficiency (NAPEE) and the State Energy Efficiency Action Network (SEEAction).

Response to Comment 4: The EPA welcomes these observations and recognizes the important 

contributions of state and local governments to the rule development process. The EPA will continue to 

work with state and local governments to fulfill its mission of protecting human health and the 

environment.
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7F - Executive Order 13175, Consultation and Coordination with Indian Tribal Governments

Commenters: 12462, 15182, 16122, 17674, 17732, 17733, 17846, 18017, 19686

Comment 1: Several commenters (12462, 16122, 17846) support stringent EPA regulations on toxic air 

emissions that must eliminate the disproportionate impact on the American Indians and Alaska Natives, 

and Indigenous Peoples, their lands, waters and natural resources.

Commenter 16122 also notes that the EPA has a responsibility to not only identify but address the very 

significant effects that Indian tribes and their members face from their exposure to Hg emissions from 

EGUs. The commenter notes the impacts of Hg contamination pose not only disproportionally high and 

adverse health effects, but unique and distinctive threat to its members because of the enormous and 

cultural value natural resources have for the Tribe and its members.

Comment 2: Commenter 15182 notes concern within tribal communities that methylmercury in ogaa

(walleye) may pose a serious threat to the health of fetuses and young children as the practice of 

harvesting, sharing, and consuming the fish is passed down through generations. The commenter notes 

that ogaa and other fish represent a significant subsistence food source for tribal communities and that 

tribes are disproportionately impacted by the Hg levels in these fish that regularly exceed the EPA fish 

consumption guidance values. The commenter suggests that limitations on the consumption of ogaa and 

other species as a result of elevated Hg concentrations threaten the traditional Anisinaabe lifeway and 

the ability of the Chippewa people to fully exercise their treaty harvest rights.

Response to Comments 1 - 2: The EPA acknowledges the support for stringent federal regulations of 

EGU air toxics emissions from commenters and understands the concerns expressed by commenters 

with regard to tribal member exposure to Hg emissions from EGUs and elevated Hg levels in 

subsistence fish. We believe that the final rule will substantially reduce the emissions of Hg in the U.S. 

The resulting reduction in emissions will benefit communities with subsistence lifeways, including 

Native American Indians and Alaska Natives, whose traditional diets include high consumption of fish.

Comment 3: Commenter 12462 requests that the EPA fulfill its mandate to respect the rights of tribes, 

as sovereign governments, to exercise their right to self-determination with an appropriate consultation 

process on regulations that affect the health, safety and welfare of Indigenous Peoples. The commenter 

asserts that the federal government and the EPA must acknowledge its trust responsibility to Tribes to 

end the disproportionate impact of air toxins from EGUs. The commenter also cites an example in which 

the Michigan Department of Environmental Quality (MDEQ), was delegated the authority to issue a 

Permit to Install (PTI) to a coal-fired power plant but did not consider the different and disproportionate 

impacts on Tribes.

Comment 4: Several commenters (16122, 17733, 17846, 19868) state that the EPA has a strict duty and 

legal obligation under the Trust Responsibility to promulgate a MACT standard that fully and 

adequately protects its environmental interests and its tribal resources. Commenters note that it is clear 

that Hg deposition from EGUs have significantly impacted culturally-important lands, waters and 

natural resources on reservations.

Commenter 19686 recommends that the EPA devote more of its resources to conduct in-depth studies 

regarding the effects of Hg emissions on Tribal communities, and in fact, the EPA should do such 

studies for other pollutants. Further, commenter 19686 recommends that the EPA conduct a benefits 

analysis that fully assesses the rule’s impacts on Tribal air quality and health, as well as cultural and 

subsistence practices. 
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Comment 5: Commenter 18540 believes that the EPA has a trust responsibility to ensure that the 

Community’s water rights, and other guarantees and benefits provided in the Arizona Water Settlements 

Act (AWSA) are preserved, and that the trust responsibility prohibits the agency from imposing a Utility

MACT that limits the community’s ability to receive and use Central Arizona Project (CAP) water. The 

commenter believes the proposed rule would force the closure of Navajo Generating Station (NGS), 

inhibiting and possibly eliminating the Community’s right to receive and utilize its allocation of CAP 

water guaranteed by the AWSA. The commenter believes that the proposed Utility MACT rule would 

make it extremely difficult, if not impossible, to pay for CAP water and would eviscerate the future 

Development Fund revenue stream that is intended to subsidize CAP water costs and pay for operation, 

maintenance, and replacement charges associated with the delivery of CAP water. Even more, the 

proposed Utility MACT rule would limit the Community’s ability to farm its reservation lands and its 

future economic development opportunities, and would negatively impact the livelihood and health of

Community members.

Comment 6: Commenters 17674 and 17732 have concerns with the consultation with their tribal 

governments as required by EO 13175. Commenter 17674 is troubled that the EPA has not undertaken 

any formal consultation with their tribal community, despite a formal request submitted in July. The 

commenter believes given the nature of the interests at stake, the implications of the proposed rule, and 

the EPA’s federal trust obligations, consultation must be among senior-level EPA officials and tribal 

leaders. Commenter 17732 states that the EPA only provided a generic letter to the tribal government as 

consultation. The commenter believes the proposed rule will have substantial direct effects on its tribal 

community, which relies on two of the three coal-fired power plants identified in the Tribal Outreach 

memo, and their supporting mines, for one third of its general operating fund in addition to significant 

jobs provided by both the plants and their mines. Therefore the commenter believes that the EPA must 

do better to engage their tribal government in meaningful consultation on this and other proposed 

rulemakings.

Response to Comments 3 - 6: The EPA appreciates these comments and recognizes the importance of 

appropriate consultation with tribes in developing this rule, consistent with the federal government’s 

trust responsibility to federally recognized tribes. The EPA agrees that this rule affects tribes and as 

such, we actively encouraged tribes to participate in our rulemaking. We conducted outreach and 

information sharing with tribal environmental staff through the monthly National Tribal Air Association 

calls, at the National Tribal Forum, and a webinar targeting tribal environmental professionals on the 

content of the proposal. In addition, we sent letters to all tribal leaders and offered consultation on the 

rule, prior to proposal and after the proposal, to ensure tribes had the opportunity to participate in the 

process. We also participated in a face-to-face meeting with tribes in Arizona who were concerned about 

the potential impact of this rule on their income and water rights. Following this meeting, we held an 

additional technical meeting on the IPM modeling used in the RIA and provided one-on-one 

consultation with the Navajo Nation, Gila River Indian Community and the Ak-Chin Indian 

Community. Thus, the EPA disagrees with commenter statements that the EPA has not undertaken any

formal consultation with their tribal community. The EPA also points out that senior-level EPA officials 

were involved in the meetings. The EPA would like to clarify that the generic letter to tribal 

governments to which one commenter refers was not intended to be “the consultation” but, rather, it 

offered consultation.

With regard to commenters’ concerns about the impact of the final rule on NGS and the delivery of 

water under water settlements in Arizona, the EPA recognizes the significance of NGS to the Central 

Arizona Project and has been consulting with affected Indian tribes and working closely with other 

federal agencies, including the Department of the Interior, on these issues. The EPA does not believe 
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that the agency is precluded from regulating NGS under section 112 of the CAA or that based on 

available information the water settlements require exclusion or disparate treatment of the facility under 

this CAA regulation. The facility is currently regulated under other CAA programs, and we believe that 

the requirements of section 112 also apply. The EPA is, however, mindful of the complex situation 

relating to NGS and the delivery of water in Arizona. The EPA is committed to continuing to work 

closely with affected tribes and other federal agencies to consider these issues as the rule is 

implemented, consistent with the federal government’s trust responsibility to the tribes. The EPA also 

notes that it is not currently certain what decisions will be made with respect to NGS's operation to 

address the rule’s requirements. The EPA’s modeling and projections are intended to be a reflection of 

possible compliance using specific tools, assumptions, and methodologies that the agency believes to 

reflect the best and most current information related to the power sector. It is not intended to reflect 

actual compliance decisions, since those will be made individually by the affected industry based on 

what makes most sense using existing technologies or other, more cost-effective strategies. For that 

reason, we caution commenters not to assume that any statements in EPA’s modeling analyses that a 

plant is projected to close reflect the only possible outcome of the final rule. The EPA will work with 

relevant authorities to ensure a smooth transition with this rule and address specific issues as they arise. 

Public utility commissions and other authorities, including tribes, will need to develop and implement 

compliance plans in order to address harmful emissions. In addition, there are certain provisions for 

granting utilities some additional time to comply, if conditions warrant (see preamble).

With regard to one commenter’s concerns about the permits issued by the MDEQ, we note that the 

agency under its environmental justice (EJ) strategy known as Plan EJ 2014 is actively pursuing tools, 

resources and guidance to improve the incorporation of EJ considerations in our permitting. However, 

this rule will not affect the preconstruction permitting New Source Review programs, and this issue 

cannot be addressed by this rulemaking.

In response to one commenter’s recommendation that additional studies and analyses be conducted, we 

agree that additional analysis would be helpful to better understand the impacts of air pollution, 

particularly Hg, on Native American populations. This rule addresses impacts of air pollution on Native 

American populations in that it regulates Hg air pollution from EGUs. The EPA’s Office of Research 

and Development has undergone realignment to better address agency priorities, for which 

disproportionate exposure is of particular concern. This issue will fall within the content areas of the 

Sustainable and Healthy Communities, Air, Climate and Energy, and Safe and Sustainable Water 

Resources research programs, which are working in a more integrated way with sustainable human and 

ecological well-being as the goal. Air pollution contamination of food fish will fall within their work on 

multipollutant emissions, transport and cascading effects. This comment will be provided to those 

groups to ensure that these issues of critical importance to Tribal communities are given due 

consideration in research efforts.

Comment 7: Commenter 17732 generally supports the proposed NESHAP Rule in its goal of 

addressing reductions of HAP from stationary sources. The health and well-being of the natural 

environment and the people of the tribal nation are of utmost importance to the commenter. As a tribal 

nation and small government landlord of affected EGUs, the commenter states that the EPA is obligated 

to consult with the tribal nation and analyze the economic impacts to the nation in promulgating the 

proposed rule. The commenter further states that the EPA is required to tailor the proposed rule so that 

the costs of compliance for plants located on the tribal nation are achievable within a reasonable 

timeframe, while taking into account the unique challenges of the plants for this and future rulemakings. 

The commenter explains that compliance costs to meet BART have the potential to impact the tribal 

nation economy significantly. The commenter is concerned that the rule will create a recurring threat of 
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severe reductions in the revenue received from the power plants and their supplying mines. The 

commenter asks that the EPA analyze the impacts from these rulemakings and provide flexibility for 

compliance scheduling so that EGUs upon which the Nation relies can continue operations.

Response to Comment 7: The EPA recognizes the concerns raised by the commenter as a tribal nation 

and small government landlord of EGUs, although landlords of affected facilities are not included in the 

definition of an affected small entity. The EPA estimated the potential impacts associated with 

complying with the rule on all entities that own affected EGUs, including those located on tribal nation 

land. We offered consultation to all tribal governments and conducted one-on-one consultation with the 

commenter. With respect to the compliance schedule, the EPA has provided the maximum 3-year period 

for sources to come into compliance as allowed by section 112 of the CAA. Sources may also seek a 1-

year extension of the compliance period from their Title V permitting authority if the source needs that 

time to install controls. CAA section 112(i)(3)(B). The EPA discusses in more detail elsewhere in this 

document how the agency plans to address those units that are still unable to comply within the 

statutorily mandated period.

Comment 8: Commenter 17674 expresses concern with the EPA’s presumption in the rulemaking that 

the NGS will close in 2015, citing the RIA where the EPA presumes that two of the three units would 

retire with or without implementation of the Utility MACT and the third would be forced to retire as a 

result of the economic and regulatory burdens imposed by the proposed rule. The commenter believes 

these assumptions are in contrast to prior statements by the EPA regarding the facility during the BART 

rulemaking. The commenter also believes the EPA must address the catastrophic impacts that the Utility

MACT will have on Arizona tribes and reconcile these opposed positions.

Response to Comment 8: As mentioned previously, the EPA conducted extensive outreach and 

consultation on this rule. However, because of concerns raised by several tribes, and in order to help us 

better understand their concerns, we also participated in a face-to-face meeting with tribes in Arizona 

who were concerned about the potential impact of this rule on their income and water rights. Following 

that meeting, we held an additional technical meeting on how IPM is used in the RIA and provided oneon-one consultation with the Navajo Nation, Gila River Indian Community and the Ak-Chin Indian 

Community. We point out that IPM is used to analyze the power sector’s cost-minimizing response to 

meet electricity demand with MATS in place. The EPA modeling and projections are intended to be a 

reflection of possible compliance using specific tools, assumptions, and methodologies that the agency 

believes reflect the best and most current information related to the power sector. It is not intended to 

reflect actual compliance decisions, since those will be made individually by the affected industry based 

on what makes most sense using existing technologies or other, more cost-effective strategies. Thus the 

EPA’s IPM analysis of MATS does not dictate what a given facility must do to comply with MATS. 

Each facility may determine its own compliance strategy to meet the emission rate limits in MATS. The 

EPA will work with relevant authorities to ensure a smooth transition with this rule and address specific 

issues as they arise. Public utility commissions and other authorities, such as tribes, will need to develop 

and implement compliance plans in order to address harmful emissions. In addition, there are certain 

provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 9: Commenter 17674 discusses numerous considerations regarding NGS, suggesting it 

should be treated differently from other generating units because it is a unique facility with a significant 

federal purpose. The commenter notes that NGS powers the delivery of water, a trust resource, to fulfill 

the mandate of eight Congressionally-approved Indian water rights settlements, to Native American 

communities, and provides jobs both directly and through the associated coal mine.
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Response to Comment 9: As discussed above, the EPA is sensitive to the commenters’ concerns and 

intends to work with tribal and other authorities to ensure a smooth transition and address specific issues 

as they arise. However, we note that section 112 of the CAA imposes specific requirements with respect 

to the methodology the EPA must use in establishing emission standards for HAP, including Hg 

emissions from EGUs. The commenter suggests treating NGS differently from other generating 

facilities, and we interpret this comment at least in part as a request for a subcategory for NGS. Pursuant 

to CAA section 112(d)(1), the EPA may subcategorize sources based on differences in class, type, or 

size. In the preamble to the proposed rule, the EPA further explains that any basis for subcategorizing

(e.g. class) must be related to an effect on emissions, rather than some difference which does not affect 

emissions performance. The EPA does not believe a subcategory based on the identified issues is 

consistent with the statutory authority to subcategorize. In addition, the EPA does not have any HAP 

information for NGS that demonstrates that the HAP emissions characteristics of that facility are 

different such that subcategorization is appropriate, nor do the commenters provide any. Another

commenter believes that there is no legal or factual basis for creating subcategories or weaker standards 

for state, tribal, or municipal governments or small entities that are operating obsolete units. The 

commenter points out that relaxation in standards would not only harm downwind governments and 

small businesses who incur higher labor costs due to pollution, but will harm other small businesses and 

state, tribal and local governments developing or operating generation facilities using modern and less 

polluting generation technologies. The methodology for determining emission standards under CAA 

section 112 does not result in requirements that specify the means of complying with standards. Thus, 

affected sources make their own determination regarding how they will comply with the standards. We 

believe that flexible and achievable pollution control requirements are promoted in the final rule through 

inclusion of alternative standards, alternative compliance options, and emissions averaging as a means 

of demonstrating compliance with the standards for existing EGUs.

Comment 10: Commenter 18017 states that if the proposed rule and other pending rules require 

installation of new control equipment costing hundreds of millions of dollars, the potential result could 

be early closure of their plant because the owners will be required to comply before they know whether 

the approvals necessary to operate after 2019 can be obtained. The commenter is concerned that the 

EPA may establish final emission limits governing NGS PM emissions that are so stringent that a new 

PM control will be required with compliance dates before approvals can realistically be obtained. The 

commenter asserts that this would lead to high compliance costs and could jeopardize continued 

operation of the NGS facility with severe economic impacts on numerous Indian Tribes.

Response to Comment 10: As the EPA has noted previously in this document, facilities that have or are 

already in the process of installing significant emission controls are likely to experience lower 

compliance costs as the result of this rule. Many coal facilities have already invested in pollution 

controls, and they are well positioned to comply with this rule with modest changes to operations. The 

EPA will work with relevant authorities to ensure a smooth transition with this rule and address specific 

issues as they arise. In addition, there are certain provisions for granting utilities some additional time to 

comply, if conditions warrant (see the preamble for the final rule for more information on MATS and 

Tribes).

Comment 11: Commenter 19686 states that the EPA needs to integrate the United Nations Declaration 

on the Rights of Indigenous Peoples (signed in December 2010) into the rule and other EPA actions. A 

number of federal entities including the Department of the Interior and Department of Justice are taking 

actions to implement the Declaration in their programs and policies. However, the EPA has been silent 

on how it plans to implement the Declaration. The rule is a good place for the EPA to start, making sure 

that the individual and collective rights of Tribes are protected and advanced in the EPA’s efforts to 
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reduce Hg and other toxic emissions from EGUs. The NTAA asks that the EPA inform our Tribal 

members about how it plans to implement the Declaration through the rule and other EPA actions with 

potential Tribal implications.

Response to Comment 11: The U.S. announced its support for the United Nations Declaration on the 

Rights of Indigenous Peoples in December of 2010. US agencies, including EPA, are currently engaged 

in many initiatives to address the issues in the Declaration. Consistent with the Declaration’s call to 

develop a concept of self-determination specific to indigenous peoples, EPA has worked to strengthen 

the government-to-government relationship with tribes through the development and implementation of 

its May 4, 2011 Policy on Consultation and Coordination with Indian Tribes. Consistent with the 

important provisions of the Declaration that address environmental issues, in the development of this 

rule EPA encouraged tribal participation, by requesting data and information from the tribes to help us 

understand the impacts of the pollutant from the power plants in Native American Communities. 

Additionally, EPA conducted a series of outreach and consultation activities including consultation prior 

to proposal and post proposal, webinars, and onsite consultation with several tribes at their request. The 

EPA’s discussion of EO 13175 includes additional details regarding EPA’s consultation and 

coordination with Indian tribes. 

Comment 12: Commenters 17846 and 19686 state that the Tribe and its members are greatly concerned 

about the environmental, health, and economic impacts of Hg deposition from coal-fired EGUs. Because 

of this, commenter 17846 commends the EPA for proposing a rule that, in accordance with the 

requirements of CAA section 112, applies the same emission limits to all EGUs within a subcategory. 

This is critical to avoid the creation of Hg “hot spots,” which could leave large portions of Indian 

country susceptible to continuing Hg contamination.

Response to Comment 12: The EPA acknowledges commenters’ concerns and appreciates their 

support of this important rule that will reduce emissions of Hg and other air toxics. 

Comment 13: Commenter 19686 states that the EPA has failed to provide Tribes with any assurances 

that their communities and land will not be part of Hg emission hotspots as a result of the rule’s 

implementation. The EPA has a trust responsibility to Tribes that requires it to look out for the general 

welfare of such Tribes when taking actions with potential Tribal implications. The commenter 

recommends that the EPA develop a plan for dealing with hotspots that affect Tribes. In addition, the 

EPA must provide Tribes with a map overlay of Tribal lands and EGUs so that Tribes can have a better 

understanding of how the rule might impact them.

Response to Comment 13: In the final rule, the EPA established technology-based standards consistent 

with the requirements of CAA section 112(d). Such standards require all sources within a source 

category or subcategory to reduce HAP emissions to the same level without consideration of risk. To 

determine whether additional standards are necessary, the EPA will consider whether risk remains from 

HAP emissions from a source category within 8 years of promulgating final section 112(d) standards 

pursuant to section 112(f)(2). We encourage the commenter’s suggestions on how to continue to 

minimize the potential local impact of Hg from these sources as the rule is implemented. The EPA will 

provide any non-privileged available information relevant to Hg deposition in Indian country in 

response to a request from the tribe. Finally, we encourage tribes to work with the EPA as it considers 

the risk to public health, including tribal members, in determining the need for further standards as the 

EPA reviews these standards consistent with the statute.
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Comment 14: Commenter 17846 states that the Tribe and its members are greatly concerned about the 

environmental, health, and economic impacts of Hg deposition from coal-fired EGUs. Because of this, 

The Fond du Lac Band of Lake Superior Chippewa commends the EPA for proposing a rule that, in 

accordance with the requirements of section 112, applies the same emission limits to all EGUs within a 

subcategory. This is critical to avoid the creation of Hg “hot spots,” which could leave large portions of 

lndian country susceptible to continuing mercury contamination. 

Response to Comment 14: The EPA shares the tribes concerns about Hg and its potential impact on 

tribes. We believe this rule will prevent local hotspots from occurring.
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7G - Executive Order 13045, Protection of Children From Environmental Health Risks and Safety 

Risks

Commenters: 10822, 12462, 16121

Comment 1: Commenter 10822 provides a copy of a journal article entitled “Pregnancy Loss and 

Maternal Methemoglobin Levels: An Indirect Explanation of the Association of Environmental Toxics

and Their Adverse Effects on the Mother and the Fetus.” According to the abstract, the aim of this 

epidemiologic study was to point out a relationship between the exposure to products of coal 

combustion, and complications in pregnancy where one third of causes of stillbirth are still unknown.

Comment 2: Commenter 12462 notes Hg is of special concern to Tribal children and women of 

childbearing age, as Hg is a neurotoxin that causes neurological delays and damage. The commenter

states in utero exposure to Hg, via contaminated fish eaten by expectant mothers, can impair thinking, 

memory, attention, language, and fine motor and spatial skills. Additionally, the commenter states that 

children who eat Hg-contaminated fish are at risk for decreased brain function.

Comment 3: Commenter 16121 supports the EPA for its proposal to reduce Hg and other harmful 

emissions, stating the American public, especially vulnerable populations such as pregnant women and 

children, is currently not adequately protected from Hg exposure in the environment. The commenter

briefly summarizes Hg issues related to health effects and exposures for these populations. 

Response to Comments 1 - 3: The EPA acknowledges the concerns of all three commenters and 

appreciates their input regarding health effects of Hg and other coal combustion emissions. In addition, 

the EPA thanks commenter 16121 for their general support of the proposal.
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7H – Executive Order 13211, Actions Concerning Regulations That Significantly Affect Energy 

Supply, Distribution or Use

Commenters: 18447

Comment 1: Commenter 18447 suggests that, despite the EPA’s conclusion, the rule is likely to have 

adverse effect on the supply, distribution, or use of energy, and the EPA downplays the impact of the 

rule with respect to the costs that the taxpayers and U.S economy must bear, which the commenter 

believes are substantial.

Response to Comment 1: As discussed extensively elsewhere in this document, the preamble to the 

final rule, the RIA, and other supporting materials, the EPA disagrees with commenter and maintains 

that the EPA’s analysis of the rule is reasonable, and does not understate impacts as the commenter 

suggests.
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7I - National Technology Transfer and Advancement Act

No comments were received specifically on the National Technology Transfer and Advancement Act

(NTTAA) or its requirements. To the extent that the NTTAA is referenced in the context of comments 

regarding another topic it has been addressed as appropriate.
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7J - Executive Order 12898, Federal Actions to Address Environmental Justice in Minority 

Populations and Low-Income Populations

Commenters: 17254, 17681, 17697, 17710, 17713, 17766, 18433, 18934, 19145, 19210, 

19536/19537/19538

1. General comments regarding impacts on minority and low-income populations.

Comment 1: Commenter 17254 presents a map showing the close correlation between the location of 

populations below the poverty line expected in 2016 and the locations of power plants. The commenter

states that while the EPA developed these maps to show the potential impacts from fish consumption in 

nearby waterways, the evidence also shows that these populations face higher risks because of the air 

they breathe.

Commenter 17254 notes that coal-fired power plants are disproportionately located in or near low 

income and minority communities. The commenter states that 68% of all African Americans in the U.S. 

live within 30 miles of a power plant, as opposed to 56% of whites. The commenter also notes that even 

though African Americans compromise 13% of the U.S. population, they account for 17% of the 

population living within 5 miles of power plant waste sites.

Comment 2: Multiple commenters (17524, 19210, 19536, 19537, 19538) note that disadvantaged 

communities that rely on the extra source of protein from fishing shoulder a disproportionate share of 

the impact from Hg pollution. Commenter 17524 cites a study that Sierra Club commissioned from 

Bendixen and Amandi, a polling firm, in which increased risks to the Hispanic community are identified 

from fishing in urban communities, where fish caught tend to have the highest concentration of Hg 

contamination. The commenter notes that the study reports that Hispanics in California consume almost 

twice the EPA safe limit of Hg due to subsistence fishing.

Response to Comments 1 - 2: The EPA agrees that minority and low-income populations are 

overrepresented among those persons who live in close proximity to coal-fired power plants and that 

certain low income and minority community members (such as subsistence fishers) consume higher 

levels of fish that may be contaminated by Hg. For these reasons, the EPA expects that minority, lowincome and indigenous population groups would benefit disproportionately from the reduced emissions 

that will result from the rulemaking, both in terms of reduced inhalation of pollutants and reduced 

ingestion of Hg-contaminated fish.

Comment 3: Commenter17681 requests that the EPA work towards developing scientific evidence of 

EGU’s impact on Hg blood concentrations in at risk populations, such as minorities and the elderly. The 

commenter notes that they are cautious to endorse a rule which will financially impact such populations 

to great extent while at the same time it is witnessing unexplained substantial reductions in blood Hg 

concentrations of all population classes according to the EPA’s National Health and Nutrition 

Examination Survey (NHANES) data.

Response to Comment 3: First, the EPA has developed an analytical method to estimate the impact of 

Hg emissions from U.S. EGUs on Hg fish tissue concentrations and the implications for human health, 

as documented in the National-Scale Mercury Risk Assessment. Second, the EPA disagrees that there is 

a statistically discernible downward trend in the NHANES data on blood Hg. The EPA is unaware that a 

formal statistical analysis for temporal trends has been completed for NHANES data on blood Hg levels 

for the period 1999 to 2008. Mahaffey et al. 2009, evaluating NHANES data collected 1999 to 2004 for 
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women at child-bearing age, could “not support the conclusion that there was a general downward trend 

in blood mercury concentrations over the 6-year study period.” However, the same publication noted 

that “there was a decline in the upper percentiles reflecting the most highly exposure women” having 

blood Hg concentration greater than established levels of concern. Visual observations of the data show 

a slight decrease in Hg blood level concentrations from 1999-2008 at the geometric mean. This decrease 

may not be statistically significant based on overlapping confidence intervals. A decrease in Hg blood 

level concentrations is also observed at the 95th percentile. Except for differences observed between 

1999 and 2008, the temporal decrease may not be statistically significant. Conclusions cannot be drawn 

without further and more formal statistical analysis of the data.

The EPA remains concerned that substantial numbers of women of childbearing age in the U.S. may 

have blood Hg levels that are equivalent to exposures at or above the RfD. Mean and 95th percentiles 

from recent NHANES data are below 5.8 ug/l (a blood Hgy concentration equivalent to the RfD). 

However, blood levels for some portions of the population (high consumers of fish, for example) may be 

indicative of exposures above the RfD. The EPA did not find data for NHANES blood distributions 

above the 95th percentile. Modeled data from Tran et al., 2004 provided estimates showing high blood 

Hg levels at the 99th percentile for females of child-bearing age (i.e., 24.41 ug/L at the 99th percentile). 

Mahaffey et al. 2009 showed that 2.4% of women of child-bearing age had blood Hg values above 5.8 

ug/L. Other published studies have shown that various population groups can have high blood Hg levels 

(Mahaffey 2005; Miranda et al. 2011; Hightower and More 2003; Hightower et al. 2006; McKelvey et 

al. 2007). For example, in Hightower et al. 2006, the authors found that Asian populations had Hg 

exposures greater than 5.8 ug/L in 83% of the Asian population compared to 12% for the total survey 

population.) (Butler Walker, J., J. Houseman, et al. (2006). “Maternal and umbilical cord blood levels of 

mercury, lead, cadmium, and essential trace elements in Arctic Canada.” Environ Res 100(3): 295-318; 

Hightower, J. M. and D. Moore (2003). “Mercury levels in high-end consumers of fish.” Environ Health 

Perspect 111(4): 604-608; Hightower, J. M., A. O’Hare, et al. (2006). “Blood mercury reporting in 

NHANES: identifying Asian, Pacific Islander, Native American, and multiracial groups.” Environ 

Health Perspect 114(2): 173-175.)

Comment 4: Several commenters (17697, 17710, 18433) note that Guam is designated as a “distressed 

nonmetropolitan middle-income” area due to both high poverty and unemployment rates, yet its utility

costs are among the highest in the nation. Given these circumstances, commenter 17710 requests that the 

EPA consider relief for the Guam Power Authority (GPA) from the final rule.

Commenter 17710 suggests the compliance costs and risks associated with the rule would require 

significantly increased electricity rates that could cause economic hardship on its customers, such as the 

unemployed, underemployed and those with limited or fixed incomes.

Response to Comment 4: The EPA disagrees that the rule will result in significantly increased prices 

for electricity. The increase in electric rates to consumers as shown in the RIA will be 3.7% on average 

nationally by 2015. These increases are accompanied by substantial benefits to health from the emission 

reductions that will take place across the country due to this rule. The increased price information is 

factored into the agency’s decision making and is discussed in more detail in the RIA. States and local 

entities responsible for utility rate structures are best positioned to deal with economic impacts on low 

income customers and with the overall distribution of increased costs. 

The EPA expects that the general population, including low income persons, would experience 

significant health benefits as a result of this rulemaking. The standards would prevent as many as 17,000 

premature deaths and 11,000 heart attacks a year and would provide particular health benefits for 
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children, preventing 120,000 cases of childhood asthma symptoms and about 11,000 fewer cases of 

acute bronchitis among children each year. The EPA estimates that for every dollar spent to reduce 

pollution from power plants, the American public and American businesses will see up to $13 in health 

and economic benefits. It is also likely that household income for some low income families may

increase if individuals are able to work (or work more) as a result of improved health.

Finally, the EPA has acknowledged the unique circumstances of non-continental EGUs, such as those on 

Guam, and adopted specific provisions for them in the final rule.

Comment 5: Commenter 18934 suggests that in the case of EJ communities, more extensive reductions 

beyond that required to meet the average level achieved by the top 12% of plants be required as such 

technology exists. The commenter offers to work with the EPA to further define EJ communities for 

such a purpose.

Response to Comment 5: CAA section 112(d) standards are technology-based standards. Pursuant to 

section 112(d)(3), the EPA establishes MACT floor limits for existing sources based on the best 

performing 12% of sources. After establishing the MACT floors, the statute requires the agency to 

determine whether standards more stringent than the MACT floor are achievable after considering the 

costs of achieving such additional emission reductions and the non-air quality health and environmental 

impacts of more stringent standards. CAA section 112(d)(2). The EPA has conducted an analysis 

consistent with section 112(d)(2) for this rule and determined that a more stringent standard is 

achievable for one pollutant from one existing source subcategory. As the D.C. Circuit recognized in 

Sierra Club v. EPA, 353 F.3d 976 (D.C. Cir. 2004:

“These [112(d)(2) and (d)(3)] emission standards are to be based not on an assessment of the risks posed 

by HAP, but instead on the maximum achievable control technology (MACT) for sources in each 

category. Senate Report, at 148 (“The MACT standards are based on the performance of technology, 

and not on the health and environmental effects of hazardous air pollutants.”). The standards, at a 

minimum, must reflect the emissions limitation achieved by the best-performing sources in a particular 

category. . . The idea is to set limits that, as an initial matter, require all sources in a category to at least 

clean up their emissions to the level that their best performing peers have shown can be achieved.” 353 

F.3d at 990.

In Sierra Club, Sierra Club argued that the phrase “non-air quality health and environmental impacts” in 

112(d)(2) required the EPA to consider the “impacts of deposition, persistence, toxicity and 

bioaccumulation of metal HAP emissions on people, wildlife and the environment.” The Court rejected 

this argument and upheld the EPA’s interpretation of the phrase, which was that “‘non-air quality ... 

impacts’ refers to any health and environmental impacts ... that may result directly or indirectly from 

[the control] measures that will achieve the emission reductions.” 353 F.3d at 990-91. The Court further 

held that “Sierra Club’s interpretation would collapse the technology-based/risk-based distinction at the 

heart of the Act, undermining the central purpose of the 1990 Amendments.” Id. The commenter here 

seeks to infuse risk into setting technology-standards, which is not permissible.

Within 8 years after the EPA promulgates section 112(d) standards, section 112(f) directs the agency to 

evaluate the risk remaining after implementation of the MACT standards to determine whether the 

standard provides an ample margin of safety to protect public health. The EPA will consider risks posed 

to disadvantaged communities in that evaluation, but any resulting standards must be national in their 

scope and applicability. To the extent that any given community is seeking greater protection than a 
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national rule would provide, we encourage them to work with the appropriate State and local authorities 

to fashion solutions that are specific to their community.

Comment 6: Commenter 19145 provides several statistics on the disproportionate impacts related to 

African Americans and power plants. The commenter uses these statistics to show pollution from power 

plants is an issue of racial disparity as African Americans are most likely to be exposed to the toxins 

coming from power plants and the impact is apparent through the higher rates of infant mortality, low 

birth weight, and premature births among the population. The commenter also notes that the African 

American population has increased rates of asthma, with power plant pollution being a contributing 

factor to asthma and chronic bronchitis.

Response to Comment 6: The EPA agrees that minority populations, including African Americans, 

generally have worse health than whites and that many minority and low income communities are 

overburdened by air pollution. The EPA agrees that the African American population has increased rates 

of asthma compared to other population groups and that pollution from power plants can be a 

contributing factor to asthma and chronic bronchitis. To that extent, African Americans living in the 

vicinity of power plants can be expected to receive disproportionate benefits from the rule’s 

implementation.

Comment 7: Several commenters (19536, 19537, 19538) believes information gathering and better 

understanding of the cumulative health impacts in areas where many sources of HAP are located 

together, such as industrial areas, would be beneficial for addressing EJ concerns.

Response to Comment 7: The EPA generally agrees with the value of assessing cumulative impacts in 

such areas, and that additional data would be useful in that process, but collection of these data is outside 

the scope of this regulatory action.

2. The EPA did not meet requirements of EO 12898.

Comment 8: Commenter 17713 believes the Environmental Justice Statement included in the proposed 

rule does not meet the requirements of EO 12898 as it failed to address increased electric rates to 

consumers that will cause disproportionate harm to minority, fixed-income and low-income populations, 

as well as health impacts from the decreased disposable incomes that these consumers would have to 

spend on health care, food, cooling and heating, and housing.

Response to Comment 8: The EPA does not agree with the commenter’s assertion that the agency

failed to consider the impacts of increased electric rates to consumers, including minority, fixed income 

and low-income populations. The commenter also makes an assertion which relies on a theory that the 

cost of a rule will result in lost income that will, in turn, result in negative health effects that offset the 

positive health effects of the rule. (This is sometimes referred to as a “health-health tradeoff.”) The EPA 

also disagrees with this claim and notes that there are a number of conceptual and empirical problems 

with any attempt to quantify the health-health tradeoffs of regulatory action to control air pollution. 

Claims about health-health tradeoffs rely on questionable applications of cross-sectional data and ignore 

key factors that may influence changes in population health risks. Additionally, marginal decreases in 

household income caused by the pass-through costs of the regulation are unlikely to cause large changes 

in any single aspect of household spending, such as health care. These analyses also fail to consider that 

household income may increase if individuals are able to work (or work more) as a result of improved 

health, offsetting some or all of the pass-through costs of the rule. For these and other reasons, the 
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EPA’s science and economic peer review panels have consistently advised against incorporating alleged 

health-health tradeoffs in the EPA analyses of regulatory effects.

The agency’s rule requires reductions of HAP such as Hg, arsenic, lead and other metals, that are shown 

to cause serious injury to exposed populations. The benefits of Hg and HAP emission reductions, along 

with the substantial benefits from reductions in emissions of PM, SO2, and other pollutants are shown in 

our RIA. Populations that are the focus of EO 12898 will benefit from these reductions as shown in the 

RIA. In addition, the increase in electric rates to consumers as shown in the RIA will be 3.7% on 

average nationally by 2015, with some consumers in certain regions seeing increases of less than 10% 

while other consumers in different regions will see increases of only 1%. These increases in electric 

rates may not be minimal in some areas of the U.S., but they should be seen in light of the substantial 

benefits to health from the emission reductions that will take place across the country due to this rule.

Comment 9: Commenter 17713 believes the Environmental Justice Statement failed to consider the 

cumulative impacts of the rule in addition to other power sector rules, which disproportionately impact 

lower income, elderly and minority populations. The commenter cites an economic analysis prepared by

National Economic Research Associates for the American Coalition for Clean Coal Electricity (ACEE) 

showing estimated increases in electricity prices, natural gas prices, and loss of jobs from the combined 

impacts of the proposed rule and the CSAPR. The commenter also includes in their comment a copy of a 

January 2011 publication entitled “Energy Cost Impacts on American Families, 2001-2011” and cites a 

March 2010 study performed for the Affordable Power Alliance by Management Systems, Inc. on the 

effect of GHG regulations, both of which conclude that there are disproportionate impacts on low 

income and minority groups from these regulations.

Response to Comment 9: As discussed above, the EPA disagrees with the assertion that the rule will 

result in disproportionate negative impacts on low-income, elderly, and minority populations. The EPA 

believes this rule will provide significant benefits to all citizens, including minority, low-income and 

indigenous populations. Furthermore, the EPA has recently assessed the cumulative impact of 

regulations adopted to implement the 1990 CAA Amendments. In March 2011, the EPA issued the 

Second Clean Air Act Prospective Report which assessed the benefits and costs of regulations pursuant 

to the 1990 CAA Amendments. The study examines the cumulative impact of these regulations (found 

at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in the report, the direct benefits 

from the 1990 CAA Amendments reach almost $2 trillion for the year 2020, a figure that dwarfs the 

direct costs of implementation ($65 billion). The full report is at 

http://www.epa.gov/air/sect812/prospective2.html. The direct benefits of the 1990 CAA Amendments 

and associated programs significantly exceed their direct costs, which means economic welfare and 

quality of life for Americans were improved by passage of the 1990 Amendments. The wide margin by

which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this 

result would be reversed using any reasonable alternative assumptions or methods. The EPA believes 

the same conclusion applies to this rulemaking, as discussed in the RIA. 

The economy as a whole is also stronger with 1990 CAA Amendment programs as cleaner air leads to 

better health and productivity for American workers and less money spent on health care to treat air 

pollution-related health problems. Economy-wide modeling shows that long-term economic growth is 

greater and American household economic welfare is improved because benefits such as fewer sick days 

and lower medical costs more than offset the economy-wide cost of investing in air pollution control.
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Comment 10: Commenter 17713 suggests that high energy prices from the rule will lead to businesses 

cutting costs by laying off workers, with low-wage workers being the groups that will be impacted by

such layoffs. The commenter notes that low-wage workers are disproportionately Black and Hispanic.

Response to Comment 10: As discussed elsewhere in this document, the EPA’s analysis shows that 

high energy prices will not result from this rule, and increases are expected to be 3.7% on average 

nationally by 2015. The EPA estimates that the overall impact on short-term employment will be an

increase on net of 46,000 jobs associated with the rule, with an increase in long-term jobs annually of 

9,000 (with jobs being measured as job-years, or 1 year of employment for one full-time worker). The 

range of employment impacts in the long-term is a loss of 15,000 to a gain of 30,000 jobs. Thus, any 

lay-offs will be smaller than the number of jobs expected to be supported or created from compliance 

with the rule.

Comment 11: Commenter 17713 believes the EPA’s regulations will significantly impact the cost of all 

fossil fuels, leading to an increase in prices of all basic goods, disproportionately impacting minority

populations. The commenter provides statistics showing the percentage of income spent on food, 

housing and clothing by minority populations in comparison to Whites.

Response to Comment 11: Although there may be increases in price for electricity, natural gas, and 

coal associated with this rule, it should be noted that the increase in electricity price to consumers is less 

than 4% by 2015, and the increase in natural gas price on average from 2015-2030 is less than 

1.5%. These estimates are presented in the RIA for the rule. Thus, these increases are unlikely to 

significantly affect the prices of basic goods, and are modest when considering the substantial benefits 

from reductions of HAP and other pollutant reductions that this rule is expected to achieve. These 

benefits will be enjoyed by minority populations, as well as other populations, and to a disproportionate 

extent for those living in the vicinity of power plants.

Comment 12: Commenter 17713 notes that the combined impacts from increased unemployment, 

reduced incomes, and increased prices for housing, basic necessities, energy, and utilities resulting from 

the EPA regulations will further reduce Black and Hispanic discretionary incomes.

Response to Comment 12: As discussed elsewhere in this document and the preamble to this rule, the 

EPA provides estimates of the impact of this rule on energy prices, unemployment, and prices for 

industries affected by any predicted increases in energy prices in the RIA for this rule. As stated above, 

the EPA expects that the impacts of increased electricity prices would be small and would be more than 

offset by increases in employment and the substantial benefits from reductions of HAP and other 

pollutant reductions that this rule is expected to achieve.

3. The EPA met requirements of EO 12898.

Comment 13: Commenter 17766 believes the current rule as written, would significantly protect 

minority and low-income populations living near coal- and oil-burning EGUs by lowering Hg, HAP, and 

fine particulate emissions in the air and in turn Hg in water and accumulated in fish.

Response to Comment 13: The EPA agrees with this comment.
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7K - Statutory and Executive Orders: Other 

Commenters: 15182, 16705, 17295, 17400, 17697, 17710, 17824, 18038, 18433, 18433, 18575, 19042, 

19213, 19580

Comment 1: Commenter 15182 requests that the EPA further regulate emissions from power plants to 

meet the goal of achieving zero emissions of nine critical pollutants (including Hg) by 2020, which the 

EPA and other signatories established under the Binational Program to Restore and Protect Lake 

Superior.

Response to Comment 1: Reductions in Hg and other emissions from this action are modeled for full 

compliance in 2016. Although this action is neither intended nor required by the CAA to achieve the 

zero emissions target of the Binational Program to Restore and Protect Lake Superior, it is a critical step 

toward significantly reducing overall emissions of these pollutants in support of that goal by the 

year 2020.

Comment 2: Commenter 17751 believes the proposed rule does not adequately comply with EO 13563, 

EO 12866, the RFA or UMRA. The commenter also believes the proposal does not show the proposed 

emissions reductions would have substantial benefit, ignores the “dwarfing” presence of Hg from natural 

sources, and attempts to justify the rule almost completely from alleged co-benefits. The commenter also 

notes that the proposal does not fully consider that state of scientific knowledge, is duplicative of other 

regulatory programs, violates the requirements of the Information Quality Act (IQA), and fails to carry

out the requirements of UMRA and EO’s to compare costs and benefits of alternative regulatory

approaches, including no regulation.

Response to Comment 2: The EPA has complied with all applicable statutory and executive order

requirements in the preparation of this rulemaking. The RIA for the proposed rule does show that the 

emission reductions from this rule would result in substantial benefits (on the order of $50 to over $100 

billion). Accounting for ancillary benefits is standard practice in benefit-cost assessment since these 

benefits are a consequence of the rule, regardless of the rule’s intended purpose. As such, the EPA 

estimates all of the anticipated costs and benefits associated with a regulatory action, to the extent 

feasible, for the purpose of determining the likely impacts, not to justify an action. This rule is expected 

to achieve substantial PM2.5 health benefits resulting from primary PM and SO2 emission reductions and 

are, thus, an important category to quantify. Consideration of ancillary benefits in benefit-cost analysis 

is directed by OMB Circular A-4.

Comment 3: Multiple commenters (16705, 17295, 17400, 17697, 17710, 18038, 18433, 18575, 19213) 

request that the EPA evaluate the impact to their utility under the SBREFA, UMRA, EO 13563, EO

13132, EO 12866 and EO 13211 based on their concerns with the proposed rule. The commenters state 

that they have standing under these Executive Orders to call for reasonable and cost-effective 

regulations to achieve reductions in air pollution in a reasonable timeframe.

Response to Comment 3: The EPA has complied with all applicable statutory and executive order 

requirements in the preparation of this rulemaking. All utilities that the agency expects will be impacted 

by this rule have been included in all analyses completed as part of compliance with the applicable 

statutory and executive order requirements. The results of these analyses are contained in the RIA for 

this rule, in various TSD) prepared for this rule, and the results are summarized in the preamble for this 

rule. Results of these analyses are available in various level of detail in the RIA and the TSDs, and the 

detailed results can be found in the docket for this rulemaking and through the official web site for this 
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rule. In adopting a final rule establishing national emission standards, the EPA is not required to conduct 

individual plant-specific analyses under the cited statutes and executive orders.

Comment 4: Commenter 18575 requests that the EPA review the impacts of the proposed rule on a 

“least cost to society basis,” pursuant to EO 13563, 12866, 13211, and 13132, as the commenter

believes the EPA can propose less costly, yet still protective, alternatives to the proposed rule.

Comment 5: Commenter 19580 recommends the EPA more closely follow the existing requirements 

for promulgating regulations and actually conduct detailed analysis prior to rulemaking. This analysis 

would include: a review of the EPA’s IQA Guidelines; a detailed RFA analysis to determine the impact 

of a regulatory action upon small businesses before certifying that there is no significant economic 

impact; UMRA analysis to determine the least costly, most cost-effective, or least burdensome 

alternative that achieves the objective of the rule; and PRA analysis to determine if OMB approval is 

needed to meet information collection requirements. 

Response to Comments 4 - 5: The EPA is obligated to meet the relevant requirements of the CAA. In 

doing so, the agency developed control strategies in the proposal that would show how affected EGUs 

could meet these requirements at least cost to them consistent with the requirements of the rule. In 

addition, the agency is mindful of mitigating the cost to society as part of this regulatory effort and 

completed economic impact analyses for this rule that examined the impacts not only to the electric 

power sector but to sectors outside of the power sector. These analyses are in the RIA for the rule. The 

agency also completed analyses and consultations in compliance with the stated Executive Orders; the 

OMB and other federal agencies reviewed these analyses and was aware of the consultations. All of the 

analyses are in the RIA and in other documents within the docket for this rulemaking; documentation for 

the consultations are in the docket as well. 

Comment 6: Commenter 19042 suggests the Obama Administration has, with limited transparency and 

no Congressional and industry scrutiny, promulgated a complex scheme of Executive Orders, reports, 

scorecards, and associated documents that assert implementation of various environmental regulations 

will reduce costs to the federal government and industry without any supporting analytical regulatory

documentation. The commenter notes several sustainability goals identified by EO 13514 and imposed 

by the CEQ, noting that as a result of the proposed Utility MACT standards, utility costs will increase 

within the federal budget, obviating any potential savings claimed by the Obama Administration due to 

implementation of EO 13514.

Response to Comment 6: In adopting today’s final rule, the EPA has complied with the statutes and all 

relevant executive orders, and has provided extensive documentation in support of its technical and 

economic analyses. To the extent that the commenter is questioning other actions taken by the Executive 

Branch, this comment is outside the scope of this rulemaking.

Comment 7: Several commenters (19536, 19537, 19538) maintains that because endangered, threatened 

and other protected species have been documented with high levels of Hg, and the livelihood and 

reproductive success of these creatures can be affected by this and other hazardous pollutants, the EPA 

is required to consult with the appropriate agencies to determine the levels at which emissions need to be 

set not only as required under the Endangered Species Act (ESA) section 7(a)(2) but also to meet the 

EPA’s ESA section 7(a)(1) duty to determine how the EPA can use its authority to enhance the recovery

of these species.
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Response to Comment 7: The EPA generally agrees that such species are threatened by high levels of 

Hg and other HAP and that actions to reduce those levels is appropriate. However, the commenters are 

incorrect in their assertion that the EPA must conduct an ESA consultation in this action. In a challenge 

to the NESHAP for primary copper smelters, the D.C. Circuit Court held that the ESA does not apply to 

the MACT standard setting process under CAA section 112(d). Sierra Club V. EPA, 353 F.3d 976, 992 

(D.C. Cir. 2004).
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CHAPTER 8: RULE LANGUAGE CORRECTIONS

8A - Rule: Definitions (existing)

Commenters: 17174, 17316, 17386, 17402, 17620, 17623, 17648, 17681, 17690, 17715, 17716, 17721, 

17725, 17728, 17733, 17754, 17756, 17771, 17775, 17796, 17800, 17801, 17804, 17805, 17808, 17812, 

17818, 17821, 17838, 17843, 17846, 17855, 17870, 17878, 17880, 17881, 17904, 17914, 18024, 18025, 

18031, 18034, 18425, 18427, 18444, 18483, 18498, 18963, 19040, 19114, 18023

Several commenters requested that the EPA review the proposed definitions for consistency and clarity.

1. Definition of natural gas.

Comment 1: Multiple commenters (17174, 17801, 18483, 17878) request that the EPA review and 

revise the definition of natural gas to be consistent with the NSPS. For natural gas, the third element of 

the NSPS definition is excluded in the NESHAP definition (i.e., “A mixture of hydrocarbons that 

maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at 

least 70 % methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per 

dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot)”). Commenters 17801 and 

17878 state that by excluding this provision, IGCC or other generating units will be subject to the same 

standards as coal-fired boilers despite the fact they burn substitute natural gas (SNG), which is the same 

chemically as natural gas. Should such IGCC or other generating units remain subject to the rule, fuel 

sampling should be allowed as a compliance demonstration option in lieu of a Hg CEMS or sorbent trap 

methodology due to Hg being removed from the fuel prior to combustion and the absence of postcombustion Hg controls. If the EPA decides that the definitions should have different scopes and 

limitations, the reasons for the divergent definitions should be clarified. Commenter 17174 also requests 

that the EPA use the definition for distillate oil in the subpart Db NSPS, which contains a limitation on 

the weight % nitrogen, while the proposed definition for the Utility MACT does not.

Response to Comment 1: The EPA concurs with the commenters concerning the definition of natural 

gas from the NSPS and has made the suggested revisions to the 40 CFR subpart UUUUU definitions in 

the final rule so as to be consistent with 40 CFR Part 75. Concerning the IGCC units, EPA must regulate 

such units if the gas at issue is derived from coal or oil and EPA is listing coal- and oil-fired EGUs. 

Although EPA believes that IGCC units could sample the gas stream before it enters the turbine, as 

noted elsewhere in this document, EPA has dropped fuel sampling, and, thus, the issue is moot. Owners 

or operators of IGCCs will need to perform instrumental monitoring (Hg CEMS or sorbent traps) or 

quarterly emissions testing for mercury.

Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, 

ethane, or propane) produced in geological formations beneath the Earth’s surface that 

maintains a gaseous state at standard atmospheric temperature and pressure under 

ordinary conditions. Natural gas contains 20.0 grains or less of total sulfur per 100 

standard cubic feet. Additionally, natural gas must either be composed of at least 70 % 

methane by volume or have a gross calorific value between 950 and 1100 Btu per 

standard cubic foot. Natural gas does not include the following gaseous fuels: landfill 

gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, 

coke oven gas, or any gaseous fuel produced in a process which might result in highly

variable sulfur content or heating value.
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2. Definition of EGU.

Comment 2: Several commenters (17620, 17316, 17805) request that the EPA clarify in the final 

regulations what the “25 MW” in EGU definition references. Commenter 17316 questions whether the 

25 MW EGU threshold refers to the power supplied to the grid (i.e., the net MWs) or the power 

generated by the EGU (i.e., the gross MWs). The commenter indicates that the 40 CFR 60.2 definition 

of EGU implies that the net MW is of more relevant concern. Similarly, Commenter 17620 recommends 

that the EPA specify whether the unit can produce more than 25 MWe is based on its maximum rated 

capacity, short-term peak capacity, or if it is based on the unit’s current ability taking into consideration 

the age of the unit and its thermal efficiency.

Comment 3: Commenter 17805 requests that the EPA clarify that the definition of EGU is assessed by

reference to the maximum electrical generating capacity of the generator the combustion unit serves. 

Thermal units, or boilers, are not, from an engineering standpoint, assigned MW or MWe ratings in 

design or specification and are only known to be assigned to generator electric output (i.e., to the 

generators a boiler serves). Thus, the thermal capabilities of a combustion unit are specified by reference 

to generator output. The commenter requests that the definition of EGU should therefore be revised as 

follows:

“Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit 

serving a generator of more than 25 megawatts (MWe) that serves a generator that 

produces electricity for sale. A fossil fuel-fired unit that cogenerates steam and electricity

and supplies more than one-third of its potential electric output capacity and more than 25 

MWe output to any utility power distribution system for sale is considered an electric 

utility steam generating unit.”

Comment 4: Commenter 18425 states that the definition of EGU is unclear for two reasons:

 The phrase “of more than” can have multiple reasonable definitions (e.g., that a facility has the 

capability to produce 25 MWe or that the facility is actually producing 25 MWe). The 

commenter recommends that the definition should be clarified that EGUs will be affected by the 

proposed rule if they are capable of producing 25 MWe rather than only when they produce 25 

MWe during operation.

 It is unclear if cogenerating units can be classified as EGUs using the first sentence of the 

definition as it is currently written. The commenter recommends that the definition specify

whether cogenerating units apply.

Comment 5: Commenter 17818 supports the proposed definitions for fossil fuel, fossil fuel-fired and 

the specification that an EGU must have fired coal or oil for more than 10.0 % of the average annual 

heat input during the previous three calendar years or for more than 15.0 % of the annual heat input 

during any one of those calendar years to be considered a fossil fuel-fired EGU but indicates that the 

provision for combusting more than “73 megawatt-electric (MWe) (250 million British thermal units per 

hour, MMBtu/hr) heat input (equivalent to 25 MWe electrical output) of coal or oil” is confusing. The 

commenter suggests that it would seem to be more appropriate to consistently relate MW thermal as 

fossil fuel fired heat input rather than MW electric (73 MW, or 73 MW thermal, or 73 MWhr/hr).

Comment 6: Alternatively, Commenter 17316 states that depending on the heat rate of an EGU, it may

require more or less than 250 MMBtu to generate 25 Mw of electricity. The commenter states that 

referencing 250 MMBtu/hr as a threshold marker is confusing and 25 Mw alone should be used as the 
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applicability threshold in all Sections of the rule for consistency and clarity.

Comment 7: Commenter 17386 states that the definition of “Electric utility steam generating unit”

provided in section 63.10042 of the proposed rule seems to include inconsistent designations. The 

definition suggests the 25 MW threshold is a gross value for EGUs that output electricity only (1st 

sentence) and a net value for EGUs that output steam and electricity (2nd sentence): “Electric utility 

steam generating unit means a fossil fuel-fired combustion unit of more than 25 megawatts electric 

(MWe) that serves a generator that produces electricity for sale. A fossil fuel-fired unit that cogenerates

steam and electricity and supplies more than one-third of its potential electric output capacity and more 

than 25 MWe output to any utility power distribution system for sale is considered an electric utility

steam generating unit.”

Commenter 17386 states that classifying EGUs based on their gross MW capacity, for EGUs that output 

electricity also conflicts with the 40 CFR 60 definition that implies the 25 MW threshold is based on net 

electrical output, as identified below: “Electric utility steam generating unit means any steam electric 

generating unit that is constructed for the purpose of supplying more than one-third of its potential 

electric output capacity and more than 25 MW electrical output to any utility power distribution system 

for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a 

steam-electric generator that would produce electrical energy for sale is also considered in determining 

the electrical energy output capacity of the affected facility.”

Commenter 17386-A2, therefore, requests that the EPA clarify the rule to identify whether the 25 MW 

applicability threshold is based on gross electricity generation or net electrical output. The commenter

also recommends utilizing the 25 MW net electrical output approach consistent with the 40 CFR 60 

definition in all sections of the MACT rule for consistency and clarity.

Comment 8: Commenter 17818 supports the applicability cutoff limit of greater than a 25 MWe rating 

level, but questions the applicability of the proposed rule to EGU’s that have an actual “nameplate”

rating capacity of 25 MWe or less but have actual demonstrated outputs of greater than 25 MWe. 

Numerous examples of units with nameplate capacity listed as 25 MWe or less have demonstrated 

summer and/or winter outputs of greater than 25 MWe, as documented in EIA listings. Conversely, the 

EIA listings also identify EGUs with 25 MWe nameplate capacities that have actual demonstrated 

output ratings less than 25 MWe. Such units that have actual ratings below the original nameplate may 

have permit restrictions or other cycle restrictions that prevent the unit from attaining actual outputs 

greater than 25 MWe. Units with 25 MWe nameplate rating but have demonstrated generation outputs in 

excess of 25 MWe may have been under-rated from the manufacturer or may have undergone 

modifications or operating practices that increase the output in excess of that anticipated by the 

generator manufacturer. Commenter believes that the EPA must consider these circumstances in 

determining unit applicability.

Comment 9: Commenters 17818 and 17843 support the EPA’s proposed EGU exemptions as listed in 

paragraphs (a) through (c) of section 63.9983.

Comment 10: Commenter 18031 agrees with the EPA’s expanded EGU definition which supports 

renewable energy from biomass, however clarification is needed to ensure that boilers which provide 

steam to a generator <25 MW are not considered EGU’s under the proposed EGU MACT Rule. 

Commenter currently owns and operates four units that burn a combination of biomass, coal, and natural 

gas. Commenter is in the process of upgrading these facilities in order to provide for even more biomass 

generation to help meet a state mandate of 25 % renewable energy by 2025. Careful wording of the 
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definition of an EGU in the proposed EGU MACT Rule is important to ensure the viable future of these 

renewable energy sources.

Commenter 18031 states that the EGU definition in the proposed EGU MACT Rule allows for up to 10 

% coal on a 3-year basis, and up to 15 % on a one-year basis, and these units would still qualify as

industrial boilers, even though the rated capacity is greater than 25 MW per unit. Two of Commenter’s

four biomass units (located at the Hibbard Renewable Energy Center) are greater than 25 MW rated 

capacity of the turbine/generator. Allowance for the use of coal for start-up and flame stabilization is 

important due to the nature of the woody biomass combustion characteristics at these units. Biomass 

heat content can vary from 2000 to 6500 Btu/lb with a moisture content ranging from 24 % to 65 %. 

Coal helps to reduce the impact of this variability, resulting in better combustion and increased 

operational stability.

Commenter 18031 states that because of the small size of these units, the emphasis on renewable 

biomass generation, and the fact their primary function historically has been to provide steam to an 

industrial process (paper mill), the Hibbard Renewable Energy Center boilers are more properly 

classified as industrial boilers, not EGUs. Commenter supports retaining the language in the EGU

definition that would allow the continued use of coal for start-up and flame stabilization, and yet classify

these boilers as industrial boilers, not EGUs.

Commenter 18031 states that two of their boilers that burn primarily biomass were primarily designed 

as industrial boilers to provide steam to a co-located paper mill. These two solid fuel boilers are both 

rated at greater than 250 MMBtu/hr (270 MMBtu/hr), however the turbine/generator each unit serves is 

less than 25 MWe, so these boilers should be classified as industrial boilers, not EGUs. CAA section 

112(a)(8) defines an EGU as: “a fossil fuel-fired combustion unit of more than 25 megawatts electric 

(MWe) that serves a generator that produces electricity for sale...... “ . ...Since the boilers do not feed 

turbine/generators greater than 25 MWe, and have a primary purpose of providing steam to a paper mill, 

they should not be classified as utility boilers. These boilers are more properly defined as industrial 

boilers, and should fall under the Industrial Boiler MACT requirements. The definition of an EGU in the 

final EGU MACT Rule should not require boilers rated at greater than 250 MMBtu/hr, but serving a 

generator <25 MW, to meet the EGU MACT emission limits and other requirements.

Comment 11: Commenters 17316 and 17386 state that section 63.9983(c) of the proposed MACT rule 

references an applicability threshold of 250 MMBtu/hr, with a parenthetical indicating that this heat 

input is equivalent to 25 MW. Commenters note that, depending on the heat rate of an EGU, it may 

require more or less than 250 MMBtu to generate 25 MW of electricity. Commenters state that 

referencing 250 MMBtu/hr as a threshold marker is confusing; 25 MW alone should be used as the 

applicability threshold in all sections of the rule for consistency and clarity.

Comment 12: Commenter 17733 strongly agrees with the preamble’s statement that units that do not 

meet the efficiency standards required to be a cogeneration unit should still qualify as EGUs if they

otherwise meet the definition of an EGU. Otherwise, owners of coal and oil-fired units would be 

encouraged to avoid the EGU MACT requirements by reducing their units’ efficiency. This result would 

clearly be contrary to the intent of the CAA, and also clearly violate the EPA’s Trust Responsibility and 

its obligations under the Environmental Justice Doctrine. The commenter requests that the EPA should 

make it clear in the final rule that any unit that does not meet the efficiency requirements of a 

cogeneration unit will still qualify as an EGU if the unit otherwise meets the CAA EGU definition.

Further, Commenter 17733 strongly disagrees with the EPA’s interpretation of the CAA section 
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112(a)(8) definition “that a non-cogeneration unit must both have a combustion unit of more than 25 

MWe and supply more than 25MWe to any utility power distribution system for sale to be considered an 

EGU pursuant to this proposed rule so as to be consistent with the cogeneration definition in CAA

section 112(a)(8).” This interpretation is contrary to the plain language of the first sentence of CAA

section 112(a)(8). This sentence makes clear that an EGU includes “any fossil fuel-fired combustion unit 

of more than 25 megawatts that serves a generator that produces electricity for sale.” Nowhere does it 

indicate that a non-cogeneration unit must supply more than 25 MWe to a utility-power distribution 

system for sale to be considered an EGU.

Commenter 17733 states that the EPA’s narrowing of the definition of an EGU is especially concerning, 

since it is likely to exclude from the requirements of the EGU MACT Rule many older, less efficient, 

and dirtier facilities. Owners of these facilities will likely be incentivized to reduce their electrical output 

to just below 25 MWe and thereby avoid having to implement more effective Hg controls. This will 

allow substantially more Hg contamination to occur, and therefore will be inconsistent with the EPA’s 

Trust Responsibility and the Environmental Justice Doctrine.

Commenter 17733 states that the EPA should make clear that units that fail to qualify as a cogeneration

unit will appropriately be considered an EGU if they meet the qualifications in the first sentence of the 

EGU definition. This would mean that units that do not meet the efficiency standards for a cogeneration

unit are considered an EGU if they are a fossil fuel-fired combustion unit of more than 25 MW, that 

serves a generator that produces electricity for sale (regardless of whether the generator actually supplies 

more than 25 MWe to a utility power distribution system). By applying this standard, the EPA can 

ensure that units that do not meet the cogeneration efficiency requirements are appropriately treated like 

any other fossil fuel-fired unit. This will allow the EPA to help limit Hg emissions and therefore their 

impact on Native American communities.

Comment 13: Commenter 17648 states that the EPA has scoped the Toxics Rule properly to apply to 

EGUs that meet the definition of EGU in CAA section 112(a)(8). The affected sources will all be units 

with original nameplate rate capacity of more than 25 MW, consistent with the statutory definition of 

EGUs, thus excluding from the rule relatively small units.

Comment 14: Commenter 17775 supports the EPA’s choice of dates for defining a new EGU.

Response to Comments 2 - 14: The EPA’s interpretation of the statutory definition of the source 

category found in CAA section 112(a)(8) (.”..combustion unit of more than 25 megawatts...”) is that it 

clearly refers to the size of the combustion unit (i.e., boiler) rather than to the size of the generator. Thus, 

EPA is not modifying the definition of an EGU such that it relies on the generator size as suggested by

some commenters as this would be outside EPA’s authority. We do not interpret the CAA section 

112(a)(8) definition to include consideration of the size of the generator for a non-cogeneration 

combustion unit as long as the combustion unit itself is greater than 25 MW.

As noted by other commenters, boilers by themselves do not generate any electricity. The EPA had, 

therefore, provided for clarity the general heat input equivalency. However, other commenters indicated 

that this equivalency would not hold uniformly as a result of differences in boiler efficiency. Further, 

EPA’s stated intent was to use the “nameplate” capacity of the boiler (i.e., the design capacity expressed 

on the “nameplate” affixed to the boiler). Absent such a “nameplate,” the boiler size contained in the 

original permit would serve as the “nameplate capacity.” The EPA has re-evaluated its use of the term 

“MW” and believes the correct interpretation would be “megawatt-thermal,” or MWt (thermal power 

produced by the combustion unit) as opposed to MWe which is the electric power generated by the 
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generator. The EPA has modified the final rule to note only the 25 MW distinction for consistency and 

clarity rather than the equivalent heat input. Further, EPA interprets the “more than” in the literal sense 

to mean a combustion unit having a nameplate capacity (either original or modified) of greater than 25 

megawatts regardless of its current operating capacity. Any combustion unit having a nameplate 

capacity of 25 MW or less, regardless of the size of the generator being served, would not be subject to 

the final rule.

The EPA agrees with the commenter that we erred in providing the “non-cogeneration” definition and 

have removed it from the final rule. Further, EPA believes that the statutory definition for noncogeneration units is clear in CAA section 112(a)(8) and in the final rule, EPA adheres to that definition. 

However, EPA believes that the commenter has misunderstood the provisions of the rule. There are no 

“efficiency standards required to be a cogeneration unit” included in the proposed or final rule. There is 

only the requirement contained in CAA section 112(a)(8) that the cogeneration unit supply “more than 

one-third of its potential electric output capacity and more than 25 megawatts electrical output to any

utility power distribution system for sale...”

The EPA specified in Table 10 of the proposal preamble that the output-based emission limits (i.e., 

lb/MWh or lb/GWh) are specified as “gross.” The EPA has made this clarification in the final rule.

4. Definition of cogeneration facility.

Comment 15: Commenter 19040 questions why the definitions for a cogeneration facility differ in the 

proposed rule and the Transport rule. The definition in the Transport Rule requires the cogeneration

system either be a topping-cycle or bottom-cycle unit and the electric sales onto the grid cannot exceed 

the greater of one-third the nameplate capacity or 219,000 MWh per year.

Response to Comment 15: The EPA is operating under different statutory provisions for the CrossState Air Pollution Rule and the Mercury and Air Toxics Standards. We believe that our definitions in 

each rule are consistent with the relevant statutory authority.

5. Definition of “fossil fuel-fired.”

Comment 16: Commenter 17733 supports the EPA’s definition of “fossil fuel-fired,” which helps 

ensure that units cannot make short-term operational changes to avoid or delay meeting the requirements 

of the EGU MACT Rule, consistent with the first sentence of the CAA definition and the EPA’s 

obligations under the Trust Responsibility and the Environmental Justice Doctrine.

Comment 17: Commenter 17805 recommends that the definition of “fossil fuel-fired” should also be 

revised as follows for consistency: 

“Fossil fuel-fired (or cogeneration means a cogeneration means an electric utility steam 

generating unit (EGU) that is capable of combusting sufficient fossil fuel more than 73 

MWe (250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output of fossil 

fuels to generate 25 MWe from such fuels alone. To be ‘‘capable of combusting’ ‘ fossil 

fuels, an EGU would need to have these fossil fuels allowed in their permits and have the 

appropriate fossil fuel handling facilities on-site (e.g., coal handling equipment, including 

coal storage area, belts and conveyers, pulverizers, etc.; oil storage facilities). In addition, 

fossil fuel-fired means any EGU that fired fossil fuels for more than 10.0 % of the 

average annual heat input during the previous 3 calendar years or for more than 15.0 % of 
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the annual heat input during any one of those calendar years.”

Commenter 17880 also recommends this proposed definition of fossil-fuel fired.

Comment 18: Commenter 17796 recommends that the EPA revise the definitions for “fossil fuel” and 

“fossil fuel-fired steam generating unit” to be consistent with the definitions of subpart D.

Comment 19: Commenter 17818 states that the definition of “fossil fuel-fired” units should be refined 

to reduce confusion and inconsistencies. The commenter provides several examples where the language 

uses both MW to convey fossil fuel-fired heat input and to convey MW electric. The commenter 

suggests that it may be more appropriate to relate MW thermal as fossil fuel-fired heat input rather than 

MW electric.

Response to Comments 16 - 19: As noted elsewhere, the EPA has made some changes to the definition 

of “fossil fuel-fired” in the final rule; we believe the final definition to be consistent with the statutory

definition in CAA section 112(a)(8). In addition, as noted elsewhere, the EPA has clarified its use of the 

term “MW” and has removed the than 73 MWe (250 million Btu/hr, MMBtu/hr) equivalency term.

Comment 20: Several commenters indicated that the definition of “fossil fuel-fired” did not adequately

account for fuel switching and would require permit revisions to eliminate any mention of using coal or 

oil to produce electricity and the removal of all coal handling equipment, coal storage areas.

Comment 21: Commenters 17756 and 17775 state that the definition of “fossil fuel-fired” EGUs may

potentially discourage natural gas and biomass conversions which require “bridging strategies.” The 

EPA views a unit as “capable of combusting” fossil fuels if burning those fuels is allowed in their 

permits and they have the appropriate fuel handling equipment on site therefore the unit would be 

subject to the proposed Toxics Rule. The commenter requests that the EPA revise the definition of 

“fossil fuel-fired” EGUs.

Comment 22: Commenter 18023 requests that the EPA update the definition of “fossil fuel-fired” to 

adequately account for fuel switching as a potential compliance strategy.

Response to Comments 20 - 22: The EPA does not agree with the commenters and we are not revising 

that aspect of the definition of “fossil-fuel fired.” The EPA does not agree that sources will have to 

dismantle all their fossil-fuel handling systems and revise their Title V permits to prohibit fossil-fuel 

combustion above a certain threshold, though either approach may be independently sufficient to make a 

source incapable of combusting sufficient fossil fuel to meet the definition of “fossil-fuel fired.” Sources 

could retain both their fossil-fuel handling facilities and their Title V permit authority as long as the 

source is not combusting fossil-fuel more than 10.0 % of the average annual heat input during the 

previous 3 calendar years or for more than 15.0 % of the annual heat input during any one of those 

calendar years. The EPA believes the definition provides flexibility for sources while simultaneously 

preventing sources from improperly avoiding regulation. EGUs that want to use fuel switching as a 

compliance strategy must make the commitment in their Title V permit to preclude being coal- or oilfired EGUs.

Comment 23: Commenters 18023 and 17775 state that the “look-back” period may potentially penalize 

a unit that retains capability to combust fuels other than natural gas and units that previously burned coal 

or oil. Commenter 18023 recommends that the EPA should eliminate the “look-back” period and define 

an affected unit by whether it actually has heat input exceeding the stated thresholds. A unit that, 
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beginning on the effective date, fires less than 15 % coal or oil on an annual basis (and less than 10 % on 

a triennial basis) would not be considered “fossil fuel-fired” and would not be considered an affected 

facility. Under this scenario, a unit that switches to natural gas and retains its capability to combust coal 

or oil would not be penalized for burning coal or oil during the time period before the effective date.

Comment 24: Commenter 17775 recommends that the EPA should revise the definition to change the 

“look-back” period to begin 3 years after the unit’s final compliance date so that it does not penalize a 

unit for having burned coal or oil in the period before compliance or for switching to natural gas but 

retaining the ability to combust coal or oil (a desirable outcome to provide system reliability). The 

commenter further states that unit owners would need to convert the unit to 100 % biomass or natural 

gas within 3 years and remove all capability to burn coal or oil in order be exempt from the EGU MACT 

rule. Alternatively, the unit could convert to biomass or natural gas by 2012 and ensure that the heat 

input from coal or oil in 2012, 2013 and 2014 is below the annual 15 % heat input requirement and the 

3-year requirement of 10 % heat input. Commenter 17775 also requests that the EPA clarify that a unit 

that switches to natural gas and later switches back to highly controlled coal use would not be in 

violation of the 3-year average for the years it was burning natural gas.

Response to Comments 23 - 24: As noted elsewhere, the EPA has made changes to the definition of 

“fossil fuel-fired” which we believe will address this comment. Further, a Title V permit modification 

that prohibits the combustion of coal or oil would make the source incapable of legally burning such 

fuels and would be sufficient to satisfy the requirements of the final rule.

6. Definition of “oil-fired electric steam generating unit.”

Comment 25: Commenter 17805 recommends that the definition of “oil fired electric steam generating 

unit” should be revised as follows for consistency: 

“Oil-fired electric utility steam generating unit means an electric utility steam generating 

unit that either burns oil exclusively, or burns oil alternately with burning fuels other than 

oil at other times. In addition, oil-fired means any EGU that fired oil (or more than 10.0 

% of the average annual/teat input during the previous 3 calendar years or (or more than 

15.0 % of the annual/teat input during any one of those calendar years.”

Comment 26: Commenter18024 submits that the EGU MACT Rule should exclude the fuel input 

associated with complying with state reliability requirements from the heat input calculation for the 

liquid oil-fired unit subcategory. Commenter requests that the EPA add the following language to the 

proposed definition of “units” designed to burn liquid oil fuel:

“Units designed to burn liquid oil fuel subcategory includes any EGU that burned any 

liquid oil for more than 10.0 % of the average annual heat input during the previous three 

calendar years or for more than 15.0 % of the annual heat input during any one of those 

calendar years, either alone or in combination with gaseous fuels, provided, however, that 

liquid oil burned during the three calendar year period to meet state reliability 

requirements shall be excluded from the heat input calculation.”

Alternatively, Commenter18024 would support changing the applicability definition for “units”

designed to burn liquid oil fuel from > 10 %/15 % of actual heat input to >30 % of actual heat input (3-

year rolling average). Based on historical operation, the commenter believes that 30 % oil firing at a 

facility would be sufficient to provide needed reliability in conformance with the State reliability rules.
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Comment 27: Commenter 17725 notes that the definition for “oil-fired EGU” may have the unintended 

consequence of excluding some units using emissions averaging. The proposed regulations state that 

emissions averaging can only be used for units within the same subcategory at the same location, and 

under the common control of the same person. But, as the fuel use of the dual-fueled units is managed at 

the site to meet the requirements of averaging, there is the risk that an individual dual-fueled EGU at the 

site may use more than 85-90 % natural gas, and therefore may no longer meet the definition of “oilfired EGU.” If a unit does not meet the definition of “oil-fired EGU” then, it is ineligible to be used in 

the averaging strategy.

Response to Comments 25 - 27: As stated above, the EPA is revising the definition of “oil-fired 

electric utility steam generating unit.” We believe this is appropriate to be consistent with the definition 

of “fossil-fuel fired.” We are making a similar change to the definition of “coal-fired” EGU and adding a 

definition for “natural gas-fired” EGU. We think these definitional changes provide clarity to the 

approach we proposed.

We have determined that it is appropriate to establish a limited-use liquid oil-fired EGU subcategory. 

There are 64 liquid oil-fired EGUs in the 2010 ICR database with annual oil-fired capacity factors of 

less than 5 % and 80 with annual capacity factors of less than 10 %. In requesting the limited-use 

subcategory, commenters specifically pointed to periods of natural gas curtailment as being those 

periods where the subcategory would be most useful. Although commenters indicated a prevalence of 

natural gas/oil co-fired EGUs, the EPA believes that there may be other liquid oil-fired EGUs that do not 

co-fire natural gas but that could be subject to mandatory operation during periods of natural gas 

curtailment in their operating area if sufficient non-natural gas capacity is not available.

Therefore, we are establishing a limited-use subcategory for liquid oil-fired EGUs with an annual oilfired capacity factor of less than 5%.

Commenters also noted the dichotomy of establishing a NESHAP to reduce emissions of HAP to the 

environment while at the same time requiring an EGU to run for the sole purpose of conducting 

emissions testing and thereby emitting those same HAP. Because the operation of these units is 

infrequent and unpredictable, performing testing to demonstrate that emission limits are being met 

requires the sources to be scheduled to be operated merely for the purpose of performing testing. We 

realize that similar situations occurred in the gathering of emissions data through the 2010 ICR. 

However, unlike the case of one time testing on a limited number of these units, upon the effective date 

of the final rule, such testing would be mandatory on a yearly basis for all of the EGUs. Because 

requiring testing under this rule would in many cases require operators of these EGUs to schedule 

operation of these EGUs at times they would not otherwise run, it would result in both extra cost related 

to the testing as well as extra emissions; therefore, the Agency believes that it is technically and 

economically impracticable to monitor emissions for these EGUs, and that they should be subject to 

work practice standards that would not require emissions monitoring.

Liquid oil-fired EGUs subject to this subcategory would be required to conduct an annual tune-up 

according to manufacturer’s specifications.

We agree with the comment to the extent it suggests that emissions from natural gas-fired EGUs cannot 

be averaged with emissions from oil-fired EGUs. Averaging units in different subcategories is 

inconsistent with EPA’s approach to averaging as explained in the proposed rule and in this case it is 

particularly inappropriate because natural gas fired EGUs are not subject to standards under CAA 

section 112. Sources attempting to manage their oil-input to maintain or avoid meeting the definition of 
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oil-fired EGU should take the necessary steps to ensure compliance.

7. Definition of “coal-fired electric utility steam generating unit.”

Comment 28: Commenter 17805 recommends that the definitions of “coal-fired electric utility steam 

generating unit” should be revised as follows for consistency: 

“Coal-fired electric utility steam generating unit” means an electric utility steam 

generating unit meeting the definition of “fossil fuel fired” that burns coal or coal refuse 

either exclusively, in any combination together, or in any combination with other fuels in 

any amount. In addition, coal-fired means any EGU that fired coal for more than 10.0 % 

of the average annual/teat input during the previous 3 calendar years or for more than 

15.0 % of the annual/heat input during any one of those calendar years.

Comment 29: Commenter 17623 requests that the EPA update the definitions to clearly state that the 

emissions standards applicable to coal-fired units also apply to any EGU using any amount of coal or 

coal refuse, whether blended with other fuels or burning both coal and petcoke. The commenter states 

that although the preamble contains the appropriate language, the definitions for each subcategory could 

be interpreted differently if read separate from the preamble. The commenter recommends that the final 

rule clearly specifies that the standards for coal-fired units apply in cases where an EGU is burning coal 

or any combination of coal and another fuel.

Response to Comments 28 - 29: As stated elsewhere, the EPA is revising the definition of “coal-fired 

electric utility steam generating unit.” We believe this is appropriate to be consistent with the definition 

of “fossil-fuel fired.” We are making a similar change to the definition of “oil-fired” EGU and adding a 

definition for “natural gas-fired” EGU. We think these definitional changes provide clarity to the 

approach we proposed. In addition, EPA has revised the definitions to make clear that a unit is not an 

oil-fired EGU if it meets the definition of “coal-fired EGU.”

Comment 30: Commenter 17868 disagrees with the EPA’s decision not to include petcoke in the coal 

subcategory and urges EPA to review UARG’s comments on the subject.

Comment 31: Commenters 17623 and 18034 recommend that the coal subcategorization definitions 

should be reviewed and revised for clarity.

Comment 32: Because the EPA chose not to subcategorize based on coal rank or liquid fuel type (i.e., 

No. 2/ No. 6), Commenter 17881 believes that fuel type should correspond to the subcategory definition. 

As long as the emission limits are being met for the applicable subcategory, the blend of 

bituminous/sub-bituminous or other solid fuel should not matter. The same can be said for different 

ranks of liquid fuels. Ultimately, compliance is based on the subcategory definition, not on fuel types, 

and the onus is on the facility to demonstrate compliance.

Response to Comments 30 - 32: The EPA generally agrees with the commenters’ characterization of a 

sources responsibility to assure its compliance with the final rule. The EPA has revised the definitions in 

the final rule in a manner that we believe provides added clarity. As petroleum coke (pet coke) is 

derived from liquid oil rather than coal, we believe it appropriate to maintain it as a subcategory of oil.

Comment 33: Commenter18034 suggests that the coal subcategorization definitions be based solely on 

fuel heat content design criteria. Alternatively, the EPA should provide a definition of height-to-depth 
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ratio to avoid misinterpretation regarding applicability of coal units since some investigators not have 

the necessary information to verify the proper categorization of a unit. The commenter further suggests 

that may create an inadvertent loop-hole in the rule if a unit is designed to burn coal with heat content 

greater than 8,300 Btu/lb and a height-to-depth ration greater than 3.82, and therefore would not be 

subject to the emission limits.

Comment 34: Commenter 17914 states that it is the fuel properties that impact the potential Hg 

emissions rate and submits that they have designed and supplied boilers to burn similar low-rank coals 

with lower height-to-depth ratios than the proposed ratio cut-off of 3.82 in the U.S. EGU market. The 

commenter believes the ratio was determined directly from Figure 19 of Chapter 20 in, “Steam/its 

generation and use,” 40th Edition but states that the dimensions are illustrative only and do not reflect a 

firm design criteria. The commenter respectfully questions the significance of the boiler dimensional 

criterion as a condition for establishing the Hg emissions limit for an existing EGU and states that an 

arbitrary limit on HID may actually prohibit a designer from reaching the most optimized combustion 

system and furnace design for new EGUs. Like commenter 18034-A3, Commenter 17914 requests that 

the EPA consider using the noted fuel characteristic as the sole criteria for defining the appropriate Hg 

emissions limit.

Comment 35: Commenter 17846 states that the definition “burn lignite coal” provides too much 

flexibility for EGUs to switch categories by simply changing their fuel source and does not make clear 

that the 3.82 height to depth ratio applies to the EGU furnace and not the EGU as a whole. The 

commenter requests that the EPA revise the rule’s definition to limit the subcategory to “any EGU 

designed to burn only [lignite coal] in an EGU with a height-to-depth ratio of 3.82 or greater.”

Response to Comments 33 - 35: The EPA does not believe it appropriate to base the subcategorization 

solely on the fuel heat content. However, the EPA has revised the definition of the subcategory to more 

adequately define the subcategory without precluding some fuel blending for purposes of compliance. 

The EPA does not believe that units designed to burn this low rank virgin coal will be constructed 

outside the area where the coal is found because of the unique considerations that are involved; 

proximity to the mine has been included in the definition.

8. Definition of “coal refuse.”

Comment 36: Multiple commenters (17754, 17855, 17812, 17838, 18963, 17804) recommend that the 

definition of coal refuse be reviewed and updated to account for the documented and inherent variability

of the fuel source. The commenters note that the definition of “coal refuse” in the proposed rule contains 

additional qualifying language that requires material to exhibit “ash content greater than 50 % (by 

weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per pound) on a dry 

basis to be defined as coal refuse.” Therefore, much of the coal refuse combusted would not meet the 

applicable definition because it would not satisfy the applicable ash content and heating value 

criteria. The commenters requests that the EPA revise the definition of “coal refuse” under the proposed 

rule by eliminating the restrictions on heating value and ash content to account for the variability and be 

consistent other federal regulatory language.

Comment 37: Commenter 17855 states that the definitions do not seem to incorporate waste-coal power 

plants as affected facilities, although we believe it is the EPA’s intent that these plants be regulated as 

EGUs under this rule. Similarly, Commenters 17754, 17838 and 18963 question how a unit combusting 

coal refuse that does not satisfy the definitions under the proposed rule of either coal refuse or coal 

would be classified, and whether it would therefore effectively avoiding regulation under the proposed 
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rule altogether. The commenters further state that the heating value and ash content within the proposed 

definition of “coal refuse” are inconsistent with the EPA’s clear recognition in the preamble to the 

proposed rule of the environmental benefits associated with the combustion of coal refuse.

Comment 38: Commenter-17812 states that waste-coal plants that are classified as Qualifying Facilities 

either as Independent Power Production Facilities or Cogeneration Facilities burning waste-coal had 

their fuel supply certified by FERC. The commenter refers to the preamble and its reference to the 

NHSM rule that currently-mined coal refuse should not be considered a solid waste under the Resource 

Conservation and Recovery Act (RCRA), as long as it is not discarded. The NHSM rule further states 

that the coal refuse would be subject to the Utility MACT regulation, if the unit meets the definition of 

EGU. The commenter indicates that the definition of coal refuse should be revised so that coal refuse 

can be subject to the Utility MACT regulations, consistent with the language of the NHSM rule.

Comment 39: Commenter 17880 states that if a unit combusts coal by-products, it should be subject to 

regulation under CAA section 129 – Solid Waste Combustion Rule. In February of 2011, the EPA 

determined that unless processed coal refuse is discarded, it cannot be considered solid waste under the 

Non-Hazardous Solid Waste Definition Rule.

Response to Comments 36 - 39: The EPA has revised the definition of “coal refuse” to be consistent 

with the definition found in 40 CFR subpart Da. The EPA believes that the definition of “Coal-fired 

electric utility steam generating unit” already clearly states that coal refuse is a covered fuel. Units 

burning coal refuse and not meeting the definition of an EGU in the final rule would likely be subject to 

the Industrial Boiler NESHAP (40 CFR Part 63, subpart DDDDD).

Certification of a fuel by FERC or any other body does not supersede the appropriate definitions 

applicable to CAA section 112. EGUs burning a coal refuse meeting the definition of a “solid waste”

under the NHSM rule would be subject to standards issued pursuant the CAA section 129 (e.g., the final 

CISWI rule); however, we did not identify in the proposed rule any EGUs that are burning coal refuse 

that is a solid waste. Furthermore, no units indicated in comments that they are burning coal refuse that 

is a solid waste so all units that meet the definition of EGU and combust coal refuse are subject to this 

final rule.

9. Definition of fossil fuel.

Comment 40: Commenter 18427 requests that the EPA revise the definition of “fossil fuel” in the 

proposed Utility MACT as follows:

“Fossil fuel means natural gas, oil, coal and any form of solid, liquid, or gaseous fuel 

derived from such material for the purpose of creating useful heat.”

The commenter states that there is no justifiable basis to define the term “fossil fuel” meaningfully 

differently under the two relevant regulatory programs, both of which apply to fossil fuel-fired electric 

utility steam generating units. Further, revising the definition of fossil fuel under the proposed Utility

MACT in this manner will ensure consistent application of the applicable regulatory standards to these 

units.

Further, the commenter requests that the EPA clarify within subpart Da and the proposed Utility MACT 

that the definition of “fossil fuel” does not include landfill gas, biogases or other materials such as 

engineered fuels that are produced from processing components of municipal solid waste. The 
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commenter believes that the EPA has not intended to include landfill gas or other biogases within the 

definition of “fossil fuel,” but states that there is some ambiguity presented by the definitions included in 

the proposed rules as drafted because both the proposed Utility MACT and the proposed revision to 

subpart Da define and use the term “gaseous fuel” (which is contained within the definition of “fossil 

fuel”) to encompass a broader category of fuels than fossil fuels.

The commenter also requests:

 EPA clarify in the context of the proposed rules that neither subpart Da nor the proposed Utility

MACT would apply to a unit which exclusively or primarily combusts a “gaseous fuel” that is 

not otherwise a fossil fuel.

 EPA clarify the circumstances under which a non-fossil gaseous fuel-fired unit may be affected 

by the proposed rules.

 To the extent that use of a non-fossil gaseous fuel may be covered under subpart Da or the 

proposed Utility MACT under certain circumstances, the proposed rules should be clear with 

respect to the manner in which such non-fossil gaseous fuels may be affected.

Response to Comment 40: Some fossil fuels in current use at EGUs (e.g., petroleum coke) were not 

derived for the purpose of creating useful heat. Therefore, including this phrase in the definition as 

commenter suggests would preclude coverage of an EGU burning pet coke under the final rule unless 

the unit blended the pet coke with coal such that the unit met the definition of “coal-fired electric utility

steam generating unit.” The EPA recognizes that there may be differences in the definition of “fossil 

fuel” among the different regulatory actions, but we have determined that byproducts of fossil fuels 

should be regulated for HAP in the same manner as raw fossil fuels because the fuel-borne HAP content 

is the same as the raw fuel, regardless of whether there was an intent to create the byproduct for the 

purpose of creating useful heat. For example, pet coke contains the same fuel borne HAP as the raw 

fossil fuel from which it is derived (i.e., oil). In addition, although pet coke is a byproduct of oil refining, 

it is also currently recognized as a valuable fuel commodity, which was not the case when the 40 CFR 

Part 60, subpart Da definition was promulgated. For these reasons, we are retaining the proposed 

definition [AND REVISING THE Da DEFINITION?] [Christian – are you modifying your definition of 

“fossil fuel” to remove the “derived for the purpose of creating useful heat” part? If so, we’d note that 

here also.]

The EPA believes that the definitions are sufficiently clear that only fossil fuels, or fuels derived from 

fossil fuels, are covered under the final rule. Materials noted by the commenter (e.g., landfill gas, 

biogases, materials derived from municipal solid waste) are, in EPA’s opinion, clearly not derived from 

“fossil fuel” and, thus, not covered under the final rule. “Gaseous fuel” in the definition of “fossil fuel”

is clearly linked to fossil fuels through the “derived from” phrase. The EPA does not believe that there is 

any confusion in the definition.

10. Definitions of miscellaneous terms.

Comment 41: Several commenters note inconsistent definitions for operating limits. Commenters 

17716 and 18498 state that the PM operating limit is defined in section 63.10011(d) as “the average of 

the PM filterable results” of the three Method 5 performance tests runs and as “at or below the highest 1-

hour average” measured during the most recent performance test in Table 4. The commenters suggest 

that the inconsistency should be eliminated by using a filterable PM (FPM) limit as a surrogate for nonHg metal HAP instead of total PM (TPM). However, if a PM operating limit is used, the inconsistency 

between sections should be reviewed and corrected.
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Response to Comment 41: The comment is moot because rule now allows compliance with filterable, 

not total, particulate matter (PM).

Comment 42: Commenter 17800 states that the EPA provides four inconsistent definitions for 

minimum control device operating parameters in:

 the preamble (“The average of the three minimum (or maximum) values from the three runs for 

each applicable parameter would establish a site-specific operating limit.”(FR Vol. 76, No. 85, p. 

25,029));

 Section § 63.10042 (“90 %” of the “test average” during the most recent performance test);

 Table 4 (“at or above the lowest 1-hour average”); and

 Table 8 (“12-hour block average” “at or above” the operating limit established under 

§ 63.10011(c)).

The commenter recommends that the EPA adopt the “90 %” criterion and the 12-hour-block average to 

provide some level of flexibility to account for changes in unit operation. Furthermore, the commenter 

requests that the EPA provide data to support achievability or enforceability of operating parameters 

under the final definition.

Response to Comment 42: This comment is moot because rule no longer requires parameter 

monitoring or operational limits for pollution control devices.

Comment 43: Commenter 18444 supports limiting emissions of total filterable and total condensable 

PM and therefore recommends that the PM definition in the proposed rules include the sum of the total 

filterable and total condensables.

Response to Comment 43: As explained elsewhere, the rule now uses filterable PM as an indicator of 

non-Hg metals since filterable PM, total PM and total PM2.5 provided comparable correlations with the 

metals emissions. As a result, the comment requesting a definition clarifying that total PM emissions is 

the sum of the condensable and filterable PM is moot.

Comment 44: Commenter 18023 requests that the EPA revise the definition of an operating day to be 

consistent with the NSPS. Specifically, the commenter suggests that the definition of an operating day’s 

worth of data in section 5.2. 1, Sorbent Trap Monitoring Systems, should include no less than 18 hours 

of valid data rather than only 15 minutes.

Response to Comment 44: The commenter’s suggestion to establish a minimum data collection period 

that would constitute a boiler operating day is inconsistent with the Agency’s view that data collection, 

as well as emissions control device operation, needs to occur during each period of unit operation, 

regardless of the duration. The rule maintains requirements to operate the monitoring system and collect 

data at all required intervals at all times that the affected unit is operating, except for periods of 

monitoring system malfunctions or out-of-control periods and periods of monitoring quality checks, and 

to use all data collected outside these periods in assessing continuous compliance.

Comment 45: Commenter 17681 requests that the EPA clarify the definition of a “30 Operating Day

Rolling Average” as well as the methods used to calculate the average. Commenter requests that the 

EPA clarify that a 30-operating day is based on the average of all applicable hours in the 30-day period.
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Response to Comment 45: The agency is unsure of the commenter’s clarification request, as a 30 boiler 

operating day rolling average is the average of all the hourly values calculated over 30 previous, 

consecutive boiler operating days. The equation is as follows:

30      =

1

30h 





where k = individual hourly average over previous 30 days on which fuel was combusted.

The rule contains a definition of boiler operating day in section 63.10042 and the equation in section 

63.10021(b)(3).

Comment 46: Commenter 17721 requests that the EPA revise the definition of “minimum sorbent 

injection rate” on page 25123 of the proposed rule as follows:

“Minimum Sorbent Injection or Addition Rate means 90 % of the test average sorbent 

injection or addition rate for each sorbent measured according to Table 7 to this subpart 

during the most recent performance test demonstrating compliance with the applicable 

emission limits.”

Response to Comment 46: This comment is moot because rule no longer requires monitoring of the 

sorbent injection rate.

Comment 47: Commenters 17801 and 17821 recommend that the EPA modify the proposed definition 

(p. 25123) of gross output as follows:

“Gross output means the gross useful work performed by the steam generated and, for an 

IGCC electric utility steam generating unit, the work performed by the stationary

combustion turbines. For a unit generating only electricity (including IGCC), the gross 

useful work performed is the gross electrical output from the unit’s turbine/generator sets 

(including steam turbines). For a cogeneration unit, the gross useful work performed is 

the gross electrical, including any such electricity used in the power production process 

(which process includes, but is not limited to, any on-site emission controls), or 

mechanical output plus 75% of the useful thermal output measured relative to ISO 

conditions that is not used to generate additional electrical or mechanical output or to 

enhance the performance of the unit (i.e., steam delivered to an industrial process).”

Response to Comment 47: The EPA has modified the definition in the final rule as follows:

Gross output means the gross useful work performed by the steam generated and, for an 

IGCC electric utility steam generating unit, the work performed by the stationary

combustion turbines. For a unit generating only electricity, the gross useful work 

performed is the gross electrical output from the unit’s turbine/generator sets. For a 

cogeneration unit, the gross useful work performed is the gross electrical, including any 

such electricity used in the power production process (which process includes, but is not 

limited to, any on-site processing or treatment of fuel combusted at the unit and any onsite emission controls), or mechanical output plus 75 % of the useful thermal output 

measured relative to ISO conditions that is not used to generate additional electrical or 

mechanical output or to enhance the performance of the unit (i.e., steam delivered to an 
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industrial process).

Comment 48: Commenters 17801and 17821 recommend modifying the definition of Heat Input (p. 

25,123) as follows: “Heat Input means heat derived from combustion of fuel in an EGU (synthetic gas to 

the combustion turbine for IGCC) and does not include the heat input from...” This will help avoid any

confusion or inconsistent application of using coal in lieu of syngas as the basis for any values based on 

heat input.

Response to Comment 48: The EPA has modified the definition in the final rule as follows:

Heat input means heat derived from combustion of fuel in an EGU (synthetic gas for an 

IGCC) and does not include the heat input from preheated combustion air, recirculated 

flue gases, or exhaust gases from other sources such as gas turbines, internal combustion 

engines, etc.

Comment 49: Commenter 17821 supports the rule’s proposed definition for fuel type, specifically 

agreeing that receiving fuel from different suppliers does not constitute a change in fuel type.

Response to Comment 49: The EPA appreciates the commenter’s support. The EPA has made 

revisions to certain definitions as discussed elsewhere to provide clarity in the final rule.

Comment 50: Commenter17402 suggests that the EPA’s definition of “deviation” is too broad and 

results in excessive infeasible reporting requirements. The commenter recommends that operating limits 

and monitoring requirements should not be included in the definition. Additionally, the commenter 

recommends that any notification of exceedances should be reported in semiannual compliance reports 

rather than the current proposed notification schedule.

Response to Comment 50: Even though the agency disagrees with the commenter’s view, a rule change 

to drop almost all operating limits and control device parameter monitoring in favor of frequent 

emissions testing or continuous monitoring should alleviate the commenter’s concerns. The proposed 

notification schedule for deviations from operating limits established by unit owners or operators by 

choice for non-mercury metals monitoring and for fuel oil moisture monitoring for hydrogen halides will 

remain. The EPA has modified the definition of “deviation” in the final rule as follows:

Deviation.

(1) Deviation means any instance in which an affected source subject to this subpart, or 

an owner or operator of such a source:

(i) Fails to meet any requirement or obligation established by this subpart including, but 

not limited to, any emission limit, operating limit, or work practice standard; or

(ii) Fails to meet any term or condition that is adopted to implement an applicable 

requirement in this subpart and that is included in the operating permit for any affected 

source required to obtain such a permit.

(2) A deviation is not always a violation. The determination of whether a deviation 

constitutes a violation of the standard is up to the discretion of the entity responsible for 

enforcement of the standards.

Comment 51: Commenter 17838 states that the definition of FGD creates confusion because the first 

sentence of the definition appears to state that any dry FGD technology shall require an “add-on air 

pollution control system located downstream of the steam generating unit.” In order to avoid the 
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potential inconsistency between these two sentences of the definition, the Commenter recommends that 

the EPA revise the definition of FGD to expressly state in the second sentence that the sorbent injection 

system in a CFB boiler need not be a separate add-on air pollution control system located downstream of 

the steam generating unit.

Response to Comment 51: We believe that the last sentence of the definition (“Sorbent injection 

systems in fluidized bed combustors (FBC) or circulating fluidized bed (CFB) boilers are included in 

this definition.”) clearly indicate that the Agency considers CFB to be a “dry flue gas desulfurization 

technology.” However, we have made a minor edit to the definition to indicate that alkaline sorbent must 

be used in CFB units to qualify.

Comment 52: Commenter 17771 requests that the EPA revise the language defining the work practice 

standard requirement to “optimize combustion” to avoid a situation where facilities might be required to 

completely shut down operations every 12 to 18 months in order to achieve compliance.

Response to Comment 52: Although the rule does not define the work practice standard requirement to 

“optimize combustion,” the final rule increases the time between burner inspections to 36 months and to 

48 months for EGUs that employ neural net technology. This lengthening of time better coincides with 

routine boiler inspections and should alleviate the commenter’s concerns over frequent, premature 

shutdowns.

Comment 53: Commenter 17655 states that the rule does not clearly define the term “optimize” with 

respect to the work practice standard for organic HAPS. Section 63.10021(a)(16)(iv) includes a 

subjective requirement to “optimize” total emissions of CO and NOX per manufacturer’s specifications, 

but the commenter argues that the term needs to be defined so that it is not interpreted as “minimized” or 

“balanced” by future facilities seeking compliance. The commenter suggests that an operational 

definition should aim to yield reduced CO levels and comply with applicable NOX limits throughout the 

normal range of operation and suggests that manufacturers’ recommendations, if available, could be of 

considerable assistance in developing the definition.

Response to Comment 53: The EPA recognizes the economic drivers behind optimal combustion of 

fuel to maximize output while minimizing fuel costs, and the EPA recognizes the nuances of managing 

NOX emission limits with these optimization efforts. Rather than drive tuning toward “minimal NOX” or 

“minimal CO” thresholds, we have developed language requiring tuning to conform with “best 

combustion engineering practice” for each burner type affected. We expect owners or operators of 

EGUs to maintain the balance of optimal combustion with NOX control and use sound combustion 

engineering practice to maintain that balance. In the final rule we have also added incentives for units 

that employ neural net combustion optimization systems during hours of normal operation.

Comment 54: Commenter 17728 indicates that the definitions for major and area sources are 

inconsistent within section 112(a). The section defines major and area sources as any “stationary source 

located within a contiguous area and under common control.” The section also declares that the 

“stationary source” term is defined in CAA section 111(a), stating that “any building, structure, facility, 

or installation which emits or may emit any air pollutant.”

Response to Comment 54: The EPA did not provide definitions for “major source” or “area source”

within the final preamble. Instead, EPA relies on the definitions as they appear in CAA section 112.
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8B - Rule: Definitions (new)

Commenters: 17655, 17696, 17711, 17718, 17721, 17725, 17755, 17760, 17800, 17808, 17878, 17881, 

18025

Comment 1: Several commenters (17760, 17718, 17808, 18025) recommend new definitions with 

regard to oil-fired units to ensure that applicability is capacity-based. Commenter 17760 and 17718 state 

that the EPA should adopt the term “oil-affected units” to address oil-fired and oil- and gas-fired units 

that have low capacity factors on oil fuel usage. In the proposed rule, the definition determines whether 

a unit that combusts oil is an affected unit based on the percentage of oil combusted by the unit 

compared to its total heat input. Because the exclusion is based on a fuel combustion ratio, a unit that 

operates for only two days (one on oil, one on gas) could be subject to the proposed rule, and a unit that 

combusts the same quantity of oil as the first unit but operates for multiple days on gas to be excluded. 

Such an arbitrary result is possible given the current operating practices for oil and oil/gas units. Since 

the promulgation of the Acid Rain Program regulations in 1993, the operation of oil- and oil/gas-fired 

units has changed significantly. A large fraction of these units are no longer base load units, and 

typically operate at capacity factors well below 50 %. In many cases, the capacity factor is less than 15 

%. The EIA Annual Energy Outlook 2011 forecasts that the amount of liquid fuels used for electricity

generation in 2015 will be approximately 60 % lower than 2000 levels.

The commenters suggest that the EPA define an oil-affected unit (an oil-fired unit that is subject to the 

EGU MACT rule) as:

“A unit that had a three-year average oil heat input greater than 10 % of the maximum 

potential annual heat input, calculated by multiplying the maximum design heat input by

8760. This definition would ensure that the EGU MACT rule targets EGUs with greater 

HAP emissions from the combustion of oil, and address EPA’s concerns regarding 

limited use oil-fired units, which typically operate at very low capacity factors.”

Response to Comment 1: As noted elsewhere, the EPA has modified the definition of “oil-fired” EGU. 

A discussion of the limited use issue is provided elsewhere in this document.

Comment 2: Commenters 17808 and 18025 request that the EPA adopt a definition for a limited-use 

oil-fired EGU, which is any boiler that burns any amount of liquid oil, has a rated capacity of greater 

than 25 MW, and has an annual average capacity factor based on its oil use of 10.0 % or less over the 

past 3 years (and not more than 20.0 % in each of those 3 years). The commenters recommend this 

definition it reflects the varying loads of an EGU and is precedented in Part 75. The commenters also

suggest that that ”capacity factor” is the ratio of the unit’s actual annual oil heat input to the unit’s 

maximum design heat input times 8,760.

Response to Comment 2: A discussion of the limited use issue is provided elsewhere in this document.

Comment 3: Commenter 17725 proposes that the EPA adopt a new definition, “Oil-fired facility for site 

averaging,” to account for the event that a site meets its emissions limits but may have individual dualfired units which do not meet the oil-fired EGU definition. Currently, the source owner may be forced to 

operate the EGU on oil just to maintain the EGU’s oil-fired status and eligibility for inclusion in the 

averaging calculation, resulting in additional emissions with no compliance benefits. In fact, based on 

the amount of oil-firing needed, the site’s emissions average may increase to the point where site-wide 

compliance is not attained. The commenter recommends a definition based on the total average oil-fired 
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heat input for all EGUs within the site averaging plan as follows:

“For purposes of site averaging, the subcategorization for individual EGUs shall be based 

on the EGU’s operation prior to the effective date of the regulations. Upon the effective 

date of the regulations, subcategorization shall be based on the total oil-fired heat input 

divided by the total heat input from all fuels from the affected EGUs An Oil-fired facility

shall have an average annual heat input on oil more than 10.0% for the 3 calendar years 

prior to the effective date of the regulations or more than 15.0 % for any single year 

within the three-year period.”

The commenter states that this definition encourages the use of lower emitting fuels through emission 

averaging but does not limit compliance options or require mandatory oil-firing to maintain an EGU’s

oil-fired status.

Response to Comment 3: As noted elsewhere, the EPA has modified the definition of “oil-fired” EGU. 

Discussions of the limited use and site averaging issues are provided elsewhere in this document.

Comment 4: Commenter17800 recommends that the EPA provides definitions for certified Flow, CO2, 

or O2 monitoring systems, with respect to appendix A, subpart UUUUU. The commenter inquires as to 

whether the certification refers to CFR Part 75 or Part 60.

Response to Comment 4: In the final rule, section 3.2.3 of Appendix A explicitly states that the 

certified flow rate, diluent gas, and moisture monitoring systems that are used to convert Hg 

concentrations to units of the standard must be installed, certified, operated, maintained, and qualityassured according to 40 CFR Part 75. This is reinforced by §§63.10010(b) through (d).

Comment 5: Commenter 17715 recommends that the EPA use the part 72 definitions for CO2 and flow 

range determination and the definition for zero gas to provide an accurate definition which harmonizes 

the definitions across more than one rule.

Response to Comment 5: The agency agrees with the commenter, and, as part of its review to reduce 

burden and costs, decided to better integrate MATS monitoring requirements with those of the Acid 

Rain program. As a result, and as mentioned elsewhere, the rule builds off the Acid Rain program 

requirements whenever possible.

Comment 6: Commenter 17711 requests that the EPA add a definition for fuel cell to avoid any 

misinterpretations. Although the commenter believes the steam generating unit language is intended to 

address integrated gasification fuel cells, the wood products industry commonly uses the term fuel cells 

to refer to biomass combustion devices.

Response to Comment 6: Fuel cells as noted by commenter would not be EGUs under the final rule as 

they are biomass-fired and, thus, not fossil fuel-fired.

Comment 7: Commenter 17721 proposes that the EPA add the following definition of DLPS to section 

63.10042 of subpart UUUUU of the proposed rule (page 25121): 

“Dual liquid powder sorbent injection (DLPS) is an Hg-control technology where a liquid 

sorbent is added onto the coal before combustion and a powder sorbent is mixed with the 

coal, injected into the furnace, or is duct injected. The liquid sorbent is a water solution of 
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a bromine compound, while the powder sorbent is an alkaline powder containing calcium 

and significant levels of aluminosilicates.”

The commenter further suggests that the following language be added to the proposed rule to expressly

authorize or at least recognize DLPS systems as available emissions control technology:

 (at the fourth-to-last sentence in section III.D.6.c, which appears on page 25014 of the proposed 

rule) “Hydrogen chloride and HF have also been shown to be effectively removed using DSI 

where a dry, alkaline sorbent (e.g., hydrated lime, trona, sodium carbonate) is injected upstream 

of a PM control device, or when powder sorbents such as those used in a dual liquid-powder 

sorbent system are combined with coal or injected into the fireball of the furnace.”

 (at the second-to-last paragraph in section III.D.6.c, which appears on page 25014 of the 

proposed rule) “The use of halogen additives in combination with powders containing calcium 

and aluminosilicates leads to significant reduction of SO2 as well as nearly complete control of 

emitted Hg. A dual liquid-powder sorbent (“DLPS”) system consists of adding an aqueous 

solution of a halogen, especially a bromine compound, onto the coal upstream of the furnace. 

Then a powder sorbent containing calcium and aluminosilicates is injected into the furnace 

during combustion of the halogen-containing coal. With some fuels, adequate Hg control is 

achieved with only the powder sorbent. Whether halogen is added or not, the use of the powder 

sorbent results in capture of the Hg and other HAP metals in a microencapsulated non-leaching 

form in the ceramic matrix of the coal ash remaining from combustion. Such methods are in 

commercial use and perform well with high sulfur coals, as it provides for sulfur removal as 

well. An additional advantage is that the Hg and other HAP metals are bound tightly in the fly 

ash so that they do not leach from the ash during storage or reuse, including during reuse in 

concrete.”

 (after the sentence beginning “Activated carbon injection is the most successfully demonstrated 

Hg-specific control technology,” in section D.8.c, which appears on page 25017 of the proposed 

rule) “On the other hand, the effectiveness of the dual liquid-powder sorbent (“DLPS”) system 

for controlling SO2, Hg, and other HAP metal emissions may not be compromised by the sulfur 

content of the coal.”

Commenter 17721 also suggests that the following language be added to the rule:

 (following sentence in section III.E, which appears on page 25023 of the proposed rule) 

“Hydrogen chloride also has a large acid dissociation constant (i.e., HCl is a strong acid) and 

it, thus, will react easily in an acid-base reaction with caustic sorbents (e.g., lime, limestone), 

including the powder sorbent containing calcium and aluminosilicates used in the Chem-Mod 

DLPS system.”

 (at the first sentence in section IV.I.(6)(3), which appears on page 25030 of the proposed rule) 

“For units with dry scrubbers, DSI (including ACI), or DLPS, you would be required to measure 

the sorbent injection or addition rate for each sorbent used during the performance tests for HCl 

and Hg and determine the minimum hourly rate of injected sorbent for each test run.”

 (at the last sentence in section IV.J.1.(3), which appears on page 25031 of the proposed rule) 

“For units with dry scrubbers, DSI systems, or DLPS systems we are proposing that you 

continuously monitor the sorbent injection or addition rate and maintain it at or above the 

operating limits established during the performance tests.”

 (following sentence in section V.K., which appears on page 25052 of the proposed rule) “These 

parameters include pH, pressure drop and liquid flow rate for wet scrubbers; and sorbent 

injection or addition rate for dry scrubbers, DSI systems, and DLPS systems.”
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 (following sentence in section V.M., which appears on page 25054 of the proposed rule) “This 

includes technologies to control acid gases (wet and dry scrubber technology and the use of 

sorbent injection), the Hg requirements (co-benefits from other controls such as scrubbers and 

FFs and Hg-specific controls such as ACI and DLPS), the non-Hg metal requirements (upgrades 

and or replacements of existing particulate control devices), and other HAP emissions (GCP).”

 (following sentence in section V.M., which appears on page 25054 of the proposed rule) “For 

Hg, EPA projects that companies will comply through the collateral reductions created by other 

controls (e.g., scrubber/SCR combination), ACI, or DLPS technology.”

 (In section 63.10011(b)(6)(iv), which appears on page 25114 of the proposed rule) “For a dry

scrubber, dry sorbent injection (DSI) system, or dual liquid-powder sorbent (DLPS) system, you 

must establish the minimum hourly average sorbent injection or addition rate for each sorbent, as 

measured during the three-run performance test and as defined in §63.10042, as your operating 

limit.”

 (In section 63.10022(a)(4), which appears on page 25118 of the proposed rule) “For each 

existing unit participating in the emissions averaging option that is equipped with dry sorbent 

injection or dual liquid-powder sorbent injection, maintain the 3-hour average parameter values 

at or below the operating limits established during the most recent performance test;”

Response to Comment 7: The agency reviewed the changes suggested by the commenter, and, apart 

from adding “or other sorbent injection system” to the description of dry sorbent injection, did not make 

other changes. The Agency notes that the process described by the commenter has been addressed

already in the preamble.

Comment 8: Commenter 17755 suggests that the EPA provide a definition of “operating” with regard 

to section 63.10020(b), which states that the CEMS must operate at all times that the affected EGU is 

operating. The commenter recommends that the definition should clarify whether operating will include 

times when the unit is combusting fuel, or only include times when the unit is producing electricity, or if 

operating includes when the boiler fans are being operated (i.e., ID and FD fans), and will it include 

startup, shutdown, malfunction, maintenance, and/or offline periods.

Response to Comment 8: The comment is moot because rule’s definition of the term boiler operating 

day already describes operation as the being the period when fuel is combusted at any time.

Comment 9: Commenter 17696 requests that the EPA create an explicit definition for the ”maximum 

normal operating load” at which performance tests would be required to be conducted under 

63.10007(c). The commenter suggests that defining the term will minimize variations in implementation 

and recommends that the term be defined as”90-100 % of the unit’s reported maximum 

load as identified in EPA’s Emissions Collection and Monitoring Plan System (ECMPS) or EIA-767.”

Comment 10: Commenter 17881 notes that the term “normal load” is not defined in either Part 63 

subpart UUUUU or its associated appendix A. For purposes of defining normal load at which the RATA 

should be operated, the commenter recommends that the provisions of 40 CFR Part 75, appendix A, 

section 6.5.2.1 should be adopted in order to eliminate any potential confusion and provide needed 

flexibility for infrequently operated units (i.e., peaking units), in which case the normal operating load 

may vary widely.

Response to Comments 9 - 10: The agency reviewed the commenters’ concerns, and the rule has been 

revised so that for purposes of this rule a normal load shall have the meaning given in section 6.5.2.1 of 

appendix A to Part 75. 
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Comment 11: Commenter 17881 recommends that the EPA develop a definition for “long-term cold 

storage” to clarify the EPA’s intent on reporting for those units placed into long tern cold storage 

(LTCS). The commenter states that if the EPA intends to allow discontinuation, similar to the associated 

provisions in 40 CFR Part 75, the proposed appendix A should also be revised to include relevant 

supporting infrastructure (i.e., a definition for LTCS, provisions in subpart UUUUU to clarify the 

reporting obligation for such units etc.).

Response to Comment 11: The rule has not been changed because agency finds the comment not 

relevant, since an inoperable EGU would have no emissions to report.

Comment 12: Commenter 17878 recommends that ambiguities regarding measurement of “Btus”

should be resolved by explicitly defining “British thermal unit” or “Btu” as the gross calorific value (i.e., 

the higher heating value). This will eliminate the possibility of confusion with the net calorific value 

(i.e., the lower heating value). Disputes and misunderstandings may result if it is unclear to which basis, 

gross or net calorific value, the rule refers. 

Response to Comment 12: The agency disagrees with the commenter’s assertion that the rule is 

ambiguous, for the Agency and its rules have consistently used the higher heating value, i.e., the gross 

calorific value, in association with a British thermal unit (Btu). No changes to the rule have been made.
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8C - Rule: Corrections to tables

Commenters: 17174, 17191, 17197, 17675, 17677, 17691, 17716, 17718, 17721, 17725, 17775, 17800, 

17801, 17808, 17821, 17881, 17886, 17909, 17913, 17915, 18034, 18498, 18539

Comment 1: Several commenters request that the EPA look at inconsistencies within the tables 

contained in the proposed rule. Most of the comments pertained to specific tables, however Commenter

17677 states that the tables are confusing because they appear to be summarizing too much information 

in one table and are not pollutant category oriented, e.g., Dioxin/Furans, Non-Hg Metals, Mercury, Acid 

Gases. The commenter suggests that clarity may be achieved by creating more tables and separating by

fuel types as most all facilities will be ≥ 8,300 Btu/lb, then by unit types under each fuel section, then by

the pollutant groups. The commenter recommends that the EPA expand the last column “Using these 

requirements as appropriate” to include specifics rather than statements which may be too general to 

provide clarity. Additionally, listing a reference method for each test and then including the exceptions 

to that reference method, as done in some rows, is recommended.

Response to Comment 1: The agency reviewed the concerns of this commenter, as well as other 

commenters, and the rule tables have been revised for clarity.

Specific comments to tables have been organized by Table, below.

1. Table 1:

Comment 2: Commenter17174 recommends that Table 1 should state that total particulate matter 

(filterable and condensable) is the pollutant being regulated rather than “particulate matter” in order to 

clearly agree with the preamble.

Comment 3: Commenters 17801 and 17821 note that Footnotes 1, 2, 3, and 4 from Table 1 (p. 25125-

25126) are missing so the readers cannot confirm or fully assess the intent.

Comment 4: Commenter 17909 questions whether the agency intended to insert OR vs. AND between 

choices for compliance based on total PM, total non-Hg metals, and individual HAP metals. The 

commenter recommends that the EPA clarify Table 1 and correct the text of the preamble and the rule 

accordingly. The commenter further states that if Table 1 is correct as written, the preamble and the rule 

should be updated to match and that tests that are not compared to a standard are unnecessary and should 

be deleted from the description of the initial and ongoing testing requirements. If Table 1 is not correct 

the commenter requests a detailed explanation and guidance as to how to run initial and subsequent 

stack tests, how to assess compliance of those results, and how to determine the “operational limit” for 

continuous compliance should be issued by the EPA. The commenter also requests that this portion of 

the proposed rule should be re-written and re-published for comment.

Response to Comments 2 - 4: Based in part on the comments received and the Agency’s review of 

those comments, the table now identifies the type of particulate matter in the emissions limit, contains 

all footnotes, and has comparable rule text. The Agency sees no need for reproposal because its 

revisions follow from these and other comments and are a logical outgrowth of the proposal and 

suggested revisions. 

2. Table 2:
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Comment 5: Commenter17191 requests that the EPA revise Subpart UUUUUU of Part 63-Emission 

Limits for Existing EGUs, Table 2, Row 3 regarding IGCC units to include the SO2 CEMs option for 

acid gas compliance in new and reconstructed IGCC units, adjusting the SO2 emission limit as 

appropriate for existing units.

Comment 6: Commenter 17801 notes that Footnotes 5, 6, and 7 from Table 2 (p. 25126-25128) are 

missing so the reader cannot confirm or fully assess the intent.

Comment 7: Commenter 17909 questions whether the agency intended to insert OR vs. AND between 

choices for compliance based on total PM, total non-Hg metals, and individual HAP metals. The 

commenter states that no indication is given as to how (or even if) results of tests to determine total 

particulate AND total non-Hg HAP metals AND individual HAP metals, as discussed in the preamble of 

the rule (p.25029) and the rule itself (p. 25103),are to be compared to the standards in Table 2. If Table 2 

is correct, a source could comply by running tests to determine total particulate (if results are less than 

0.030 lb/MMBTU, the source passes initial certification), and no metals data would be needed at all OR 

a source could determine total metals and no total particulate or individual metals data would be needed, 

etc. Subsequently, the commenter emailed the EPA. The EPA’s email stated that both particulate AND 

metals testing are indeed required during the initial certification testing and in subsequent tests required 

every 5 years. No indication was given as to how to determine compliance of the results, however the 

EPA did state that a relationship or correlation between filterable particulate and total particulate would 

be developed. The EPA also stated a relationship or correlation between total particulate and total metals 

emissions could be developed. The commenter requests clarification on whether this means that one 

would check total metals test results against the Table 2 standard (pass/fail) and check the total 

particulate results (pass/fail), then try to correlate those results with a Method 5 filterable test result and 

a PM CEMS reading. That PM CEMS reading in lb/MMBTU then would be the “operational limit” to 

be calculated on a 30 boiler day operating average to determine compliance. The commenter

recommends that EPA clarify Table 2.

The commenter further recommends that EPA clarify Table 2 and correct the text of the preamble and 

the rule accordingly. The commenter states that if Table 2 is correct as written, the preamble and the rule 

should be updated to match and that tests that are not compared to a standard are unnecessary and should 

be deleted from the description of the initial and ongoing testing requirements. If Table 2 is not correct 

the commenter requests a detailed explanation and guidance as to how to run initial and subsequent 

stack tests, how to assess compliance of those results and how to determine the “operational limit” for 

continuous compliance should be issued by the EPA. The commenter also requests that this portion of 

the proposed rule should be re-written and re-published for comment.

Response to Comments 5 - 7: The agency reviewed all comments and revised the rule to allow an SO2

alternative emissions limit for new IGCC EGUs that employ flue gas desulfurization technology, to 

include all footnotes, and to allow the EGU owner or operator to choose one of a number of nonmercury HAP metals alternative emissions limits and demonstrate compliance with the selected limit 

only. As mentioned elsewhere, the agency finds no need to repropose the rule. 

3. Table 3:

Comment 8: Commenter 17881 suggests that the current reference of 63.10005, which relates to the 

initial compliance requirements is very broad, and a more appropriate citation would be 63.10005(f).

Comment 9: Commenters 17174 and 17691 state that the reference provided in Table 3 
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regarding annual performance tests for work practice standards, section 63.10005, does not contain any

reference for tune-up work practice performance tests to be conducted annually. However, section 

63.10006(r) contains language regarding meeting applicable tune-up work practice standards. The 

commenters request that the proper citation and period testing be provided in Table 3. Furthermore, 

Commenter 17691 adds that section 63.10006(r) states that sources required to meet an applicable tuneup work practice standard must conduct a performance tune-up according to 63.10007, but that section 

speaks only of performance testing, not tune-ups. The commenter requests that each section be reviewed 

for clarity.

Comment 10: Several commenters (17716, 18498, 17725) recommend that the phrase “performance 

test” in Table 3 be replaced with “boiler tune-up” to avoid confusion and be consistent with the language 

in 63.10005(f).

Response to Comments 8 - 10: The agency reviewed the commenters’ concerns, and Table 3 in the rule 

has been revised to better describe the work practice standards. As the performance test for some units 

subject to a work practice standard is a tune-up, no change to the rule language was made.

4. Table 4:

Comment 11: Commenter 17197 provides the following recommendations for Table 4:

 If compliance with the applicable Table 1 and 2 emissions limits is being demonstrated using Hg 

CEMS, SO2 CEMS, and PM CEMS, there is no need to also establish operation limits for the 

EGU’s control equipment. Therefore, Table 4 is unnecessary, but should at least be modified to 

state that Hg, acid gas and total PM compliance can be demonstrated using CEMS. Section 

63.9991 (a) should also be modified to read “You must meet the requirement in paragraph (a)(1) 

and or (2) of this section.”

 The commenter recommends that the rule should clearly state that: If continuous compliance is 

demonstrated with PM CEMS, a fabric filter bag leak detection system (BLDS) operating limit is 

not applicable. Table 4 contains both PM CEMS and Fabric Filter Control “Operating Limits”

and the fabric filter operating limit requirement to install and operate a BLDS could be 

interpreted as additive to the PM CEMS requirement.

 The commenter suggests that operating limit for Dry Scrubber DSI and carbon injection control 

in Table 4 may only be intended for EGUs that demonstrate Low Emitting EGU status for Hg 

and qualify for alternate monitoring. The operating limit requires that the sorbent or carbon 

injection rate be maintained at or above the lowest 1-hour average sorbent flow rate measured 

during the most recent performance test demonstrating compliance with the Hg emissions 

limitation. However, since the Hg CEMS performance test is the initial 30-day rolling average 

period, the minimum 1-hour injection rate could be zero. Furthermore, the commenter states that 

if continuous compliance is demonstrated with Hg CEMS or sorbent trap monitoring, section 

63.9991 should clearly state that establishing operating limits for dry scrubber, DSI, or carbon 

injection control is not required.

Comment 12: Commenter 17721 states that Table 4 should be revised as follows:

“Dry scrubber, DSI, or DLPS injection control: Maintain the sorbent injection or addition 

rate at or above the lowest 1-hour average sorbent flow rate measured during the most 

recent performance test demonstrating compliance with the Hg emissions limitation.”
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Comment 13: Commenters17174and 17775 suggest that the intended reference provided in Table 4 

regarding fuel analysis procedures to demonstrate compliance with the applicable limits may be 

63.10011(c) and not 63.10011(d). No provisions for fuel analysis compliance are found in the reference. 

Similarly, Commenter 17881 states that the Fuel Analysis requirement should reference 63.10011(c)(3-

6) as applicable.

Comment 14: Commenter 17675 recommends that the language in Table 4 be revised to allow 

flexibility when implementing the parametric monitoring requirements for EGUs. The commenter points 

out that parameters determined at the maximum operating rate(s) as required by the language in the 

proposed standard will not be attainable over all levels of operation without the flexibility to set ranges 

of parameters that vary with operating levels, heat input, or electrical output of the EGU historical data 

and multiple tests to be utilized when establishing parameter ranges for operating parameters, consistent 

with 63.864(j) (Part 63 subpart MM).

The commenter also indicates that paragraph 2.a (operating limits for acid gas scrubbers) contains 

clarity issues and a possible error. The paragraph is unclear if the requirements to “maintain the pH at or 

above the lowest 1-hour average pressure drop across the wet scrubber” are intended to apply to pH and 

liquid flow rate; pressure drop and liquid flow rate; or pH, pressure drop, and liquid flow rate. However, 

if the EPA intended to regulate pressure drop, regulation/monitoring should be removed from the 

requirements for acid gas scrubbers that utilize spray absorption because there is no way to adjust or 

control the pressure drop, nor does it have any relationship to the acid gas scrubbing efficiency of a 

spray absorber.

Comment 15: Commenter 17821 notes that in Table 4, pH is incorrectly referenced “2. Wet acid gas 

scrubbers... a. Maintain the pH at or above the lowest 1-hour average pressure drop.” Also, pH is 

omitted from the description on page 25,112 of how to monitor various operating parameters.

Comment 16: Commenter 17808 notes inconsistencies between the operating limits specified in Table 4 

and Table 7. Page 25030 of the preamble states that the operating limits for an ESP would be based on 

the “minimum hourly values” for each test run; however, Table 7 requires sources to “collect secondary

voltage and current... every 15 minutes during the entire each individual test run in the three-run 

performance test by computing the average of all the 15-minute readings taken during each test run.”

Comment 17: Commenter 17881 states that the requirement that the injection rate shall be maintained 

at or above the lowest 1-hr average is in conflict with the definition of minimum sorbent injection rate 

provided in 63.10042, which states that the minimum rate means 90% of the test average sorbent

injection rate for each sorbent measured during the most recent performance test.

Commenter 17881 also states that the Performance Testing requirement should specify that operating 

load must be monitored and recorded.

Response to Comments 11 - 17: The commenters’ concerns are moot, for with the exception of a new 

option for meeting the non-Hg HAP metals emissions requirements through the use of a PM CPMS, the 

rule no longer requires operating parameters for pollutants. 

5. Table 5:

Comment 18: Commenter 17886 states that Table 5 specifies a Method 5 front half temperature of 320 

degrees F and should instead reference Method 5B to be consistent with any standard.
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Commenter 17886 also states that Table 5 specifies quantification of HF, but should not since there are

no limits given for HF.

Response to Comment 18: As explained elsewhere, the agency disagrees with the commenter, and the 

rule continues to require the use of Method 5, not 5B. The rule continues to contain an HF emissions 

limit for liquid oil-fired units, so the comment is moot.

Comment 19: Commenter 18498 states that Table 5 should be revised to include the following 

reference methods as an option for compliance demonstration:

 EPA Method 2H and Conditional Test Method 41 (wall effects adjustment for flow)

 EPA Method 26A (HCl- option for dry stacks)

 EPA Method 320 (HCl- FTIR option)

 EPA Method 5B, 17 (total, filterable PM)

Commenter states that the table should indicate that Method 2 (or equivalent) need only be used if 

necessary to calculate output-based emissions.

Response to Comment 19: The agency reviewed the commenter’s concerns, and the rule is revised to 

include Method 2H, 26A, and 320; other Methods did not meet this rule’s criteria and remain excluded.

Comment 20: Several commenters (17716, 17725, 18498) point out that the reference provided for 

Table 5 (Appendix A) does not address monitoring certification and ongoing monitoring requirements 

for PM and HCl CEMS.

Response to Comment 20: The agency reviewed the commenter’s concern, and the table now has 

appropriate monitoring certification and monitoring requirements.

Comment 21: Commenter 18034 states that the reference footnote 9 in Table 5 (section 63.10005(l)) 

does not address calculating emissions during startup and shutdown operations.

Response to Comment 21: The comment is moot because rule now requires work practice standards, 

not adherence to emissions limits, during periods of startup or shutdown.

Comment 22: Several commenters (17716, 17725, 18498) note that for the SO2 CEMS (Item 5) in the

“using” column for Item a, the table should include the alternative to use Part 75 requirements for 

“installation,” “operate,” and “maintain CEMS.” See Section 63.10010(e). Also, the table refers to 

Sections 4.1.3 and 5.3 of Appendix A to the subpart, but SO2 is never mentioned in Appendix A.

Response to Comment 22: The agency has reviewed the comments, and the table now references Part 

75 requirements and contains correct references.

Comment 23: Several commenters (17675, 17718, 17881) state that section 63.10010(h) discusses 

installing CPMS as specified in Table 5 of this subpart. This section should instead refer to Table 4 

which contains operational parameters rather than Table 5 which contains performance testing 

requirements. If the section is correctly referencing Table 5, then it is unclear what CPMS are required. 

Response to Comment 23: The comment is moot, as table 6 now contains operational parameter 

instructions for those EGU owners or operators who choose to use PM CPMS.
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Comment 24: Commenters 18498 and 17725 recommend that the EPA add the text below to Table 5, as 

applicable:

“Alternatively, for an affected source that is also subject to the O2or CO2 monitoring 

requirements of Part 75 of this chapter, the owner or operator may install, certify, 

maintain, operate and quality assure the data from an O2or CO2CEMS according to Part 

75 of this chapter in lieu of the procedures in paragraphs b(1) through b(3) of this 

section.”

Commenter 18498 also recommends Section 60.10010(b) should reference Part 75 in lieu of the 

alternate requirements specified in Appendix A to Subpart UUUUU with regard the O2and CO2 CEMS

requirements.

Response to Comment 24: The agency reviewed the commenters’ concerns, and the rule now 

references Part 75 requirements in both table 5 and in rule text.

Comment 25: Commenter 17881 states that exhaust flow and moisture should only need to be 

determined if you are complying with the lb/MWh limit. The O2/CO2 levels should only need to be 

determined if you are complying with the lb/MMBtu standard. The commenter recommends that the 

EPA clarify the language in Table 5 in order to prevent the collection of data which is not needed to 

assess compliance with the chosen emission limit form (i.e., heat input or electrical output basis).

Response to Comment 25: The agency has reviewed the commenter’s concern, but disagrees with the 

concern. The table is not changed, for an owner or operator need not provide the exhaust flow or 

moisture levels if his or her EGU complies with an electrical output based standard.

Comment 26: Commenters 18498 and 17725 request clarity regarding performance specification for 

HCI. Table 5 lists Performance Specification 6 but it does not apply since it is for systems that measure 

pollutant emissions in units of mass per unit of time. The EPA has developed no performance 

specification for non-FTIR based HCI CEMS. The commenters state that the lack of a performance 

specification for HCI (coupled with limited utility HCI operating experience, particularly for compliance 

near the detection limits of the systems) makes it difficult to provide meaningful comments.

Response to Comment 26: The agency disagrees with the commenter, for an FTIR CEMS, subject to 

PS 15, could be used for HCl CEMS. Should an owner or operator of an EGU not choose to use an FTIR 

CEMS to demonstrate compliance with HCl emissions, he or she could use quarterly emissions testing 

or wait and use non-FTIR HCl CEMS using the separate HCl CEMS performance specifications under 

development but expected to be promulgated before the rule’s compliance date.

Comment 27: Commenter 17881 states that bullet c. should read: “Determine oxygen OR carbon 

dioxide concentrations of the stack.”

Response to Comment 27: This change to the rule has been made.

Comment 28: Commenter 17881 states that the reference to a 30-day rolling average is not appropriate. 

Per 63.10005(k)(2), a 28-30 day integrated average value is being established, not a 30-day rolling 

average. 

Response to Comment 28: The comment is moot because rule now requires a 30-day integrated 
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average value. 

6. Table 6:

Comment 29: Commenter 17881 states that Table 6, which provides the fuel analysis requirements, 

does not address gaseous fuels at all even though gaseous fuel may be co-fired (for purposes other than 

startup and flame stabilization) with one or more fossil fuels which are regulated in the proposed EGU

MACT, particularly liquid oils.

Commenter 17881 states that in the requirements for HF, there is a typo in bullet f.; it should read 

“measure fluorine concentration in fuel sample” instead of chlorine.

Response to Comment 29: The comment is moot, for the rule no longer requires fuel analysis for 

pollutants. 

7. Table 7: 

Comment 30: Several commenters (17174, 17808, 17881) state that the reference provided in the table 

regarding emission operating limits through fuel analysis should be 63.10011(b) as opposed to 

63.10011(c).

Comment 31: Commenters 17775 and 17808 state that the table only lists the operating limits for ESPs 

for units that operate wet scrubbers, therefore conflicting with other provisions, including proposed 

section 63.10011(b)(6)(iii). The table does not include the operating parameters for a unit with an ESP, 

but no wet scrubber.

Comment 32: Commenter 17721 states that Table 7 should be revised to add operating limits for 

sources using dry scrubbers, DSI, or DLPS to comply with PM, Hg, or non-Hg HAP metals emission 

limits as follows:

1 Particulate matter (PM), mercury (Hg), or other non-Hg HAP metals:

d. Dry scrubber, DSI, or DLPS operating parameters

i. Establish a site specific minimum sorbent injection or addition rate operating limit according to 

§63.10011(c). If different Hg sorbents are used during the Hg performance test, the average value for 

each sorbent becomes the site-specific operating limit for that sorbent.

(1) Data from the sorbent injection or addition rate monitors and Hg performance test.

(a) You must collect sorbent injection or addition rate data every 15 minutes during the entire period 

of the performance tests;

(b) Determine the average hourly sorbent injection or addition rates of the three test run averages 

measured during the performance test.

Comment 33: Commenter 17721 states that Table 7 should be revised to add operating limits for 

sources using dry scrubbers, DSI, or DLPS to comply with HCl or HF emission limits as follows:
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2. “Hydrogen Chloride (HCL) or hydrogen fluoride (HF)

(b) Dry scrubber, DSI, or DLPS operating parameters

(1) Establish a site specific minimum sorbent injection or addition rate operating limit according to 

§63.10011

(c) If different Hg sorbents are used during the Hg performance test, the average value for each sorbent 

becomes the site-specific operating limit for that sorbent.

(1) Data from the sorbent injection or addition rate monitors and Hg performance test.

(a) You must collect sorbent injection or addition rate data every 15 minutes during the entire 

period of the performance tests;

(b) Determine the average hourly sorbent injection or addition rates of the three test run averages 

measured during the performance test.”

Response to Comments 30 - 33: The comments are moot, for the rule no longer requires establishment 

of operating parameters for pollutant control devices. 

8. Table 8:

Comment 34: Several commenters (17716, 17725, 17775, 18498) point out that Table 8 erroneously

refers to “QA Procedure 5” for the PM CEMS QA/QC requirements and should refer to “Procedure 2”

instead.

Comment 35: Commenter 17881 states that the references in the “you must” column should be rechecked, as there are several that are incorrect. For example, 7.a. should be QA Procedure 2, not 5, and 

7.b. should be “30 boiler operating day average mg/dscm values” rather than the current “30 boiler 

operating mg/dscm values.”

Comment 36: Commenters 17775 and 17808 state that references to section 63.1011(c) in Table 8 may

be intended to reference section 63.1011(b) instead.

Comment 37: Several commenters (17800, 17725, 18498) state that the method for calculating 30 

rolling averages in Table 8 is not consistent with the method in section §63.10010(g). Table 8 states that 

the source should convert “hourly emissions concentrations to 30 boiler operating mg/dscm values,”

which suggests that compliance is assess based on the average of 30 individual daily values. However, 

section 63.10010(g)(5) states that 30-day rolling average is calculated as “the average of all of the 

hourly particulate emissions data for the preceding 30 boiler operating days.” Commenter 17800 

recommends that the EPA consider changing this averaging time to a 12-month rolling average 

consistent with the Illinois MPS rule to help capture the variability associated with the operation of an 

EGU. If the 30-day average is not updated to be consistent with the Illinois MPS rule, the commenter 

suggests that the methodology in Table 8 be updated to be consistent with the other sections.

Comment 38: Commenters 18498 and 17725 note that Table 8 requires CPMS data to be reduced to 12-

hour block averages; however, this requirement is not specified in section 63.10010(h).
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Comment 39: Commenter 18539 states that Table 8 refers to opacity operating limits however it 

appears that no other references to opacity operating limits exist. The commenter requests that the EPA 

clarify whether the intent is to allow for opacity operating limits exist in the proposed rule. 

Comment 40: Commenter 17721 states that Table 8 should be revised as follows:

“4. Dry scrubber, DSI sorbent, DLPS sorbent, or carbon injection rate

a. Collecting the sorbent or carbon injection rate monitoring system data from the dry scrubber, DSI, 

or DLPS according to §63.10010 and §63.10020; and

b. Reducing the data to 12-hour block averages; and

c. Maintaining the 12-hour average sorbent or carbon injection rate at or above the operating limit 

established during the performance test according to §63.10011(c).”

Response to Comments 34 - 40: The agency finds the comments are moot, as table 8 has been revised 

to remove all requirements associated with developing and maintaining operating limits for pollution 

control devices. 

9. Table 9:

Comment 41: Several commenters (17913, 17915, 17174) request that the reference to startup, 

shutdown, and malfunction (SSM) plans in Table 9 should be removed because it conflicts with the text 

in Table 10 and the preamble that states SSM plans are not required.

Comment 42: Commenter 17775 indicates that the Table 9 should be evaluated for the following 

inconsistencies:

 The error, “information required in §63.10031(c)(1) through (11) through (11),” should be 

addressed. In addition, the EPA should review the text and consider referencing §63.10031(c) 

subsection (12) as well. Commenter 17881 notes this inconsistency as well.

 The table specifically requires submission of a startup, shutdown, and malfunction report containing 

the information in §63.10(d)(5)(i) at 1.d and 2, however, Table 10 states that §63.10(d)(5) does not 

apply. The EPA should address the inconsistency and correctly identify applicable reporting 

requirements.

Response to Comments 41 - 42: The Agency has reviewed the commenters’ concerns and revised the 

table by removing requirements to develop and submit a startup, shutdown, or malfunction plan and 

corrected the text cite language, as suggested by the commenter.

10. Table10:

Comment 43: Commenter 17775 states that section 63.1(a)(4)(i) requires each standard to “identify

explicitly whether each provision in this subpart A is or is not included” and that the EPA proposes to 

address applicability in Table 10. The commenter provides the following instances of inconsistencies in 

Table 10 with respect to applicability:

 EPA identifies §63.6(h)(2)-(9), and §63.9(f), and (g)(2) as applicable. Proposed §63.10030(a) 
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also requires compliance with §63.9(f). These provisions pertain solely to compliance with 

opacity and visible emission standards. Since the proposed rule does not include any applicable 

opacity or visible emission standards, these portions of the general provision do not apply and 

Table 10 should be revised accordingly.

 EPA fails to identify whether §63.6(e)(1)(iii) applies.

 EPA fails to identify whether §63.8(a)(1), (2), and (4), (b), (c)(2), (4)(i), (5), (6), (8), (d)(1), 

(d)(2), (f), or (g) apply. Sections (c)(1)(ii), (3), (4)(ii), (7)(i), (8), and (d) are referenced in 

proposed §63.10000(d)(4) and §63.8(e) is referenced in proposed §63.10030(a), but not in Table 

10. Some of these provisions apply solely to opacity monitoring, and should not apply, but the 

EPA must state whether or not they are included. The EPA should provide that CEMS meeting 

the requirements of Part 75 are exempt from the “performance evaluation” test plan and notices 

in §63.8(e). The EPA also should make clear that those requirements do not apply to “calibration 

error testing,” since “performance evaluation” is defined in §63.2 to include both relative 

accuracy testing and calibration error testing.

 EPA fails to identify whether §63.10(b)(2)(x)-(xiii) apply.

 EPA identifies §63.10(c) as applicable in its entirely, but later in the table separates out 

§63.10(c)(7) and (8) as applicable and §63.10(c)(10), (11), and (15) as not applicable. The EPA 

also cites §63.10(c) in its entirety as requirements of the site-specific monitoring plan in 

proposed §63.10000(d)(7). Note also that §63.10(c)(7) and (8), which specify recordkeeping for 

sources with continuous monitoring requirements, require reporting of “excess emissions” “as 

defined in the relevant standard(s), that occur during startups, shutdowns, and malfunctions of 

the affected source” and those that occur “during periods other than startups, shutdowns, and 

malfunctions.” Proposed subpart UUUUU does not define “excess emissions” for any standard 

and does not exempt periods of startup, shutdown, or malfunction.

 In determining whether the recordkeeping requirements in §63.10(b) and (c) apply, the EPA 

must ensure its compliance with the PRA. Under 5 C.F.R. §1320.5(d)(2), the EPA cannot require 

retention of such records for more than 3 years, unless the agency demonstrates in its OMB 

submission that that a longer retention period is necessary to “satisfy statutory requirements or 

other substantial need.”

 EPA fails to identify whether § 63.10(d)(3)-(4) are applicable.

Response to Comment 43: The agency reviewed the commenter’s concerns, and the rule and table have 

been revised, where appropriate, to remove inconsistencies. 

Appendix A:

Comment 44: Commenter 17775 points out the following inconsistencies in Appendix A:

 Appendix A §4.1.1.3 incorrectly refers to Table A-2 instead of Table A-1.

 The conversion factors used in Appendix A §6.2.1.2, Equation A-2 and Equation A-3 should be the 

consistent. Appendix A §6.2.1.2 includes a factor of 6.24x10-11 to convert Hg concentration from 

μg/scm to lb/scf whereas Equations A-2 and A-3 use a constant of 6.236x10-11.

 Appendix A says that quarterly reports must include the information in §§7.1.2-7.1.19, however 

§§7.1.11-7.1.19 do not exist.

Comment 45: Commenter 17881 suggests that the following changes be made regarding Hg Monitoring 

Provisions in order to harmonize Appendix A of the EGU MACT with the requirements of 40 CFR Part 

75, as most (if not all) units subject to the EGU MACT will also be subject to 40 CFR Part 75 emissions 

monitoring:
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 Table A-2, Flow Rate RATA Specifications: “40 CFR Part 75, App. A, Section 3.3.4 also provides 

an alternate performance specification of not > 2.0 feet per second (FPS) when the average RM 

value is ≤ 10.0 FPS.”

 Table A-3, Daily Calibration Error Test: The first bullet should read “use zero gas and either a midor high- level gas,” as daily calibration error tests are generally conducted using a zero and upscale 

calibration gas.

 Table A-4, Daily Calibration Error Test for O2 or CO2: The first bullet should read “use zero gas 

and either a mid- or high- level gas,” as daily calibration error tests are generally conducted using a 

zero and upscale calibration gas.

 Table A-4, Daily Interference Check for Flow Rate: “40 CFR Part 75, App. B, Section 2.1.4(a) 

allows ≤ 6.0% of the calibration span.”

 Table A-4, Flow Rate RATA: “The 40 CFR Part 75 App. B, Section 2.3.1.2(d) alternate 

specification for flow monitors of ± 1.5 FPS when the average RM value is ≤ 10 FPS should also be 

allowed.”

Commenter 17881 also asks if the EPA intends moisture monitoring systems consisting of wet and dry

O2 monitoring systems to be exempt from any sort of daily calibration error test requirement. For such 

moisture monitoring systems, the commenter states that 40 CFR Part 75 generally requires those same 

on-going quality assurance tests as are required for O2 diluent monitors however Appendix A of the 

proposed EGU MACT only appears to require a RATA test.

Response to Comments 44 and 45: The reference to Table A-2 in section 4.1.1.3 of Appendix A was a 

typographical error and has been corrected. The conversion factors in Equations A-2 and A-3 have been 

made consistent; both factors are now 6.24 x 10E-11. The reference in the quarterly reporting section of 

Appendix A to section 7.1.19 was a typographical error and has been corrected. 

The EPA has not incorporated the commenter’s suggestion to harmonize the information in Tables A-2 

and A-4 with Part 75, because Tables 2 and 4 have been deleted from Appendix A. The agency has 

decided against reproducing part 75 certification and QA specifications in Appendix A for the flow rate, 

diluent gas, and moisture monitoring systems that are used to convert Hg concentrations to units of the 

standard. Instead, section 3.2.3 of Appendix A simply states that these monitoring systems must be 

certified, operated, maintained, and quality-assured according to 40 CFR part 75. The EPA has 

incorporated the edit to Table A-3 (which has been renumbered as Table A-2) suggested by the 

commenter, i.e., that the daily calibration error tests of the Hg CEMS must be done with a zero gas and 

either a mid-level or high-level calibration gas. Finally, moisture monitoring systems consisting of wet 

and dry O2 analyzers are not exempted from daily calibration error tests. The O2 monitors in these 

systems must meet the daily calibration requirements of part 75.
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8D - Rule: Language

Commenters: 16513, 17174, 17191, 17254, 17386, 17622, 17623, 17655, 17656, 17675, 17677, 17681, 

17689, 17691, 17696, 17705, 17711, 17714, 17716, 17718, 17721, 17725, 17730, 17731, 17752, 17756, 

17758, 17775, 17781, 17795, 17796, 17800, 17801, 17808, 17821, 17843, 17848, 17870, 17881, 17909, 

17912, 18014, 18027, 18034, 18037, 18498, 19120, 19536/19537/19538, 18023

1. Clarifications.

Comment 1: Several commenters request that the language of the rule be updated to clearly state the 

requirements for each category, subcategory, pollutant and compliance option used at facilities. 

Commenter 18034 requests that the EPA clarify how to determine emission rates during a startup, 

shutdown, or malfunction situation.

Response to Comment 1: We believe that the final rule language is clear.

Comment 2: Multiple commenters (17677, 17730, 17758, 17909, 17912) request that the preamble 

should be updated and clarified to be consistent with the rule language. For example, Commenter 17912 

notes that the preamble to the proposed rule states the EPA’s intent to exclude stationary combustion 

turbines from this rule. However, the proposed rule text excludes only those stationary combustion 

turbines located at major sources. The commenter requests that the EPA revise the rule text to confirm 

its intent to exclude all stationary combustion turbines, including those located at minor source facilities.

Response to Comment 2: We do not believe that the regulatory language distinguishes between major 

and minor source facilities as the term “major source” is not used.

Comment 3: Commenter 17656 urges the EPA to make clear precisely what requirements apply to each 

category/subcategories and the different options for compliance that are available. Commenters 17677 

and 17730 both oppose leaving such clarification for follow-on guidance.

Response to Comment 3: We believe that the final rule clearly presents the compliance options as 

requested by commenters.

Comment 4: Commenter 17730 appreciates the variety of options that the EPA has provided for sources 

to demonstrate ongoing compliance, but states that several of the options will require clarification in 

order for facilities to understand the options, applicability, and to demonstrate compliance. The 

commenter recommends that the EPA revise the proposal to make clear exactly what requirements and 

rationale apply to each compliance option. The commenter points out that the EPA has the opportunity

to electronically publish each of the different subcategories and the different options in a clear, direct, 

and plain language fashion with a limited amount of references to other subsections, or mentions of “as 

applicable. The EPA has substantively failed to provide a clear and readily understandable set of 

requirements for sources in this proposed rulemaking.

Response to Comment 4: The agency believes thatthe final rule provides a clear and readily 

understandable set of requirements, and the rule contains clarifications where appropriate.

2. CEMS comments.

Comment 5: Multiple commenters (17623, 17655, 17716, 17681, 17800, 17821 and several others)
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request that the EPA review and update the language regarding CEMS, performance testing and 

operating limits.

Response to Comment 5: As mentioned earlier, the agency has reviewed the commenters’ concerns 

and revised the rule where appropriate.

Comment 6: Commenter 17716 states that the proposed rule should be clarified to explicitly exempt 

sources using a CEMS for compliance for a particular pollutant from all fuel sampling requirements for 

that pollutant. The commenter states that the fuel sampling requirements apply only to those units that 

demonstrate compliance through performance (i.e., stack) testing for a particular pollutant, but 

§63.10005(a) states that “performance testing” may also consist of CEMS operating data, thereby

creating ambiguity about whether units using a CEMS for compliance must also meet the fuel sampling 

requirements.

Comment 7: Commenters 18498 and 17725 recommend that the EPA revise §63.10007 to indicate that 

the fuel sampling and operating parameter limits are not required when the applicable HAP (or 

surrogates) are monitored using a CEMS.

Response to Comments 6 - 7: The agency agrees with the commenters, and the rule has been revised to 

not require fuel sampling of pollutants where CEMS are used for compliance purposes.

Comment 8: Commenter 17718 states that it is not clear that installing and operating CEMS for the 

regulated HAP and surrogates will relieve a source of the burden of also monitoring compliance with 

operating limits on control equipment based on a performance stack test. The commenter recommends 

that the EPA require no proof of compliance beyond a properly calibrated and installed CEMS, and that 

the EPA revise both the language and tables in the rule to clarify its intent as it relates to CEMS used for 

demonstrating compliance.

Comment 9: Several commenters (17655, 17696, 17716) state that the language regarding performance 

testing and compliance is unclear and should be revised so that facilities can clearly understand and 

follow regulations. Commenter 17655 specifically notes that Sections §63.10005(a), §63.10011(a), and 

§63.10011(b) are difficult to interpret. For example, it is unclear whether facilities using CEMS are also 

required to track performance parameters to show compliance. The commenter requests that the EPA 

use consistent and clear language to enumerate the requirements for facilities with and without CEMS.

Response to Comments 8 - 9: The comments are moot because rule no longer requires emissions 

control device operating parameters or limits when CEMS are used for compliance purposes.

Comment 10: Commenter 17821 states that the best method of determining initial compliance is with 

the applicable reference method. Reference methods are used to certify the CEMS on a source. The 

commenter recommends that the EPA specifically state in the rule that the use of Reference Methods are 

required to demonstrate initial compliance with the emission limitations in this rule.

Response to Comment 10: The methods suitable for conducting performance tests for this rule, or any

rule, are defined in large part by specified averaging time. In many cases, this final rule clarifies that the 

averaging time for initial and periodic compliance testing is the result of three relatively short term 

performance test runs and through the use of manually operated test methods found in Appendix A of 40 

CFR part 60 or 63. This approach to conducting initial and periodic performance tests applies to metal 

HAPs, PM, and HF and HCl, and is consistent with the commenter’s suggestion. On the other hand, for 
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sources who opt to use Hg or SO2 CEMS in lieu of manual performance testing, the averaging time of 

the rule is 30 unit operating days. This long averaging time precludes the use of manual performance test 

methods on a practical basis. The final rule specifies that CEMS or sorbent trap monitoring be the 

performance test method for determining initial and continuous compliance with limits expressed as a 

30-day average value.

Comment 11: Commenter 17623 requests that the language in both the preamble and the rule be 

updated to clarify that testing is not mandated for pollutants being controlled through a surrogate and 

performance standards are not required when a CEMS is employed. In the preamble, the commenter 

requests that the clause that states “and an operating limit would be established” should be removed 

because it is duplicative of the CEMS requirement.

Response to Comment 11: The agency has reviewed the commenter’s concern, and while the rule has 

been revised so that neither emissions testing other than RATAs (or initial calibration for PM CEMS) 

nor operating limits are required for EGUs that use CEMS for compliance purposes, the rule has not 

been revised to exclude the requirements of performance specifications when CEMS are used for 

compliance purposes.

Comment 12: Commenter 17696 states that sections 63.10000(c),(d), 63.10005, 63.10006, 63.10008, 

63.10011, and 63.10021 are complex and confusing and in some cases inconsistent with the preamble 

and examples in the rule. The commenter cites language on whether a coal-fired EGU without an HCl 

CEMS is required to conduct monthly fuel analysis for chlorine from sections 63.10005(a), 63.10006(s), 

and 76 FR 25,051 to illustrate the difficulty and contradictions contained in the rule.

Response to Comment 12: The agency has reviewed this concern, and the rule has been revised for 

consistency and clarity.

Comment 13: Commenter 17796 suggests that the Hg compliance metric be succinctly stated in section 

63.10010(1). The commenter states that although section 63.10010(g)(5) for PM CEMs discusses that 

compliance is based upon a 30 boiler operating day rolling average emissions rate on a daily basis, the 

commenter was unable to find this language for the Hg compliance limit. Section 63.10010(1) refers the 

reader to Appendix A but Appendix A does not state the compliance average.

Response to Comment 13: The agency disagrees with the commenter’s concern, for the rule states the 

initial Hg CEMS compliance requirement at §63.10005(a)(2) and the ongoing Hg CEMS compliance 

requirement at §63.10021(a).

Comment 14: Commenter 17718 notes that sections 63.10005(d)(3)-(6) state if CEMS are going to be 

used for initial compliance determinations then the average hourly concentrations obtained during the 

first 30-day operating period will be used “after the monitoring system is certified.” The commenter 

requests that the EPA clarify when the 30-day operating period begins if the systems are already 

certified (e.g., current SO2 or PM CEMS being used for 40 CFR Part 75 and/or 40 CFR Part 60 

monitoring programs).

Response to Comment 14: The Agency disagrees that any additional clarification is needed in the rule. 

Owners or operators of new EGUs have up until 60 days after the rule appears in the Federal Register or 

upon startup, whichever is later; or, for existing units, up to 3 years after promulgation to be in 

compliance with the emissions limits and standards.
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Comment 15: Commenter 17796 requests that the rule clearly state what the acceptable data capture 

percentage is for Hg, HCl and PM CEMs. The method of counting hours when a monitor is out of 

service, as hours of monitor down time and using this value to determine the % of monitor availability is 

consistent with NSPS requirement. For Hg, section 60.490a paragraph (p)(4) discusses the need for 75 

% data capture on a monthly basis for a monitor to achieve an acceptable % monitor availability and to 

be able to demonstrate consistent compliance. However, the commenter states that this whole section 

will become obsolete and removed from the NSPS if the proposed changes to the NSPS and NESHAP 

rules go into effect.

Response to Comment 15: The agency considered the commenter’s suggestion but made no change to 

the rule. The rule contains no minimum acceptable data capture percentage, for the rule at §63.10010(j) 

requires data to be collected at all times an EGU is combusting fuel except for periods of monitoring 

system malfunction, out-of-control operation, or quality assurance or control activities.

Comment 16: Commenter 17622 requests that the EPA clarify the statement “continuous compliance 

would be determined using a PM CEMS with an operating limit established based on the filterable PM 

values measured using Method 5.” (76 FR 25029/2). The commenter recommends that the EPA 

explicitly state if the PM CEMS would be correlated against the filterable PM fraction of total PM to 

avoid confusion.

Response to Comment 16: The agency considered this and other comments, and the rule has been 

revised to include a filterable PM, but not total PM, alternative emissions standard. The rule also allows 

use of PM CPMS, which would have an operating limit, as well as PM CEMS, which would allow direct 

measure of compliance, as compliance options.

Comment 17: Commenter 17675 further recommends that the wording in section 63.10010(a) should be 

updated to clearly state that Hg CEMS and/or sorbent traps can be used for Hg monitoring, rather than 

implying that both CEMS and sorbent traps are required. Similarly, Commenter 17821 recommends that 

the EPA clarify the term “demonstrate initial and continuous compliance through the use on a 

continuous...HCl...[and]...Hg CEMS or a sorbent trap...system” to indicate that a “certified CEMS”

must be used. The term “certified CEMS” means that all of the required testing outlined in this rule, or 

in applicable portions of 40 CFR parts 60 or 75, have been completed, and that the results of the testing 

met the requirements of the applicable rules. Without clarification, this section could be interpreted to 

mean that certification of the CEMS is not required before using it for purposes of demonstrating 

compliance.

Response to Comment 17: Although the agency appreciates the commenter’s concern, no change was 

made to the rule, for §63.10010(g) requires Hg CEMS or sorbent trap monitoring systems to be certified.

Comment 18: Commenter 17716 requests the following corrections and clarifications regarding CEMS:

 EPA should evaluate and revise the data reduction citations to be consistent throughout the rule. 

The commenter specifically provides the following example: sections 63.10010(b)(4); 

63.10010(c)(4); 63.10010(d)(4); 63.10010(e)(4); and 63.10010(g)(4) all state: “Reduce the 

CEMS data as specified in section 63.8(g)(2) and (4).” However, section 6.1.1 of appendix A 

relates data reduction from “Hg CEMS and (as applicable) flow rate, diluent gas, and moisture 

monitoring systems to hourly averages in accordance with section 60.13(h)(2) of this chapter.”

The commenter suggests that requirements in section 60.13(h)(2) are more complete since it 

addresses “partial operating hours” and other data needs. Commenters 18014-A2, 17725 and 
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18498 also make the same recommendation.

 For SO2 CEMS, section 63.10021(a)(13) does not include the option to use the Part 75 

certification and ongoing QA/QC requirements as allowed in section 63.10010(e). Commenter 

17725 also notes this issue.

 For Hg CEMS, section 63.10021(h)(ii) states the “Quarterly accuracy determinations and daily 

calibration drift tests shall be performed in accordance with procedure 5 in Appendix F of 40 

CFR Part 60.” This contradicts section 63.10010(f) which references appendix A of this subpart 

and should be revised to reference section 5 to appendix A. Commenter 17725 also notes this 

contradiction.

Comment 19: Commenter 17881 requests the following corrections and clarifications regarding CEMS:

 Section 63.10011(b)(6) should clarify how these requirements apply in cases where CEMs are 

used for compliance.

 The reference in section 63.10021(a)(10)(i) is inconsistent because section 63.10010(a) does not 

require the installation of O2 CEMS while section 63.10010(b) allows installation of CO2 or O2

CEMS.

 In sections 7.1.3.5 and 7.1.4.8, the EPA requires that hourly records of % monitor availability

(PMA) be maintained for Hg CEMS and sorbent trap monitoring systems. The PMA concept is 

employed in 40 CFR Part 75 in the context of determining appropriate missing data substitution 

procedures. As missing data substitution will not be allowed in the context of Hg monitoring, the 

commenter requests that these requirements should be deleted from proposed appendix A.

Response to Comments 18 - 19: The agency has reviewed and considered each of the commenters’

suggestions. The rule now uses Part 75 data reduction and quality assurance procedures for those CEMS 

also used in Part 75; Hg CEMS and sorbent traps are subject to the requirements of appendix A; HCl or 

HF CEMS are subject to the requirements of appendix B. The commenter’s concern over simultaneous 

control device operational parameter monitoring and CEMS is moot, for the rule no longer requires 

control device operational parameter monitoring. The inconsistency between the use of CO2 or O2

CEMS has been clarified; the rule now allows either type of CEMS. The rule retains the requirement to 

report Hg CEMS or sorbent trap monitoring data availability; although the Agency agrees that there is 

no minimum data availability requirement for these types of monitors, the Agency sees no inconsistency

between the monitoring operational and data availability reporting requirements.

Comment 20: Commenter 18498 states that as proposed, the EGU MACT Rule does not include 

provisions to use the Part 75 “conditionally valid data procedures.” For example, if a CEMS fails a 

linearity check the CEMS remains out-of control until the successful completion of a subsequent 

linearity check (reference section 60. 13(h)(2); section 63.8(g)(2) and (4)). This would require the 

operator to invalidate the Part 75 conditionally valid data (for SO2, CO2, O2 or flow monitors) for the 

EGU MACT recordkeeping and reporting purposes. The commenter recommends that the EPA allow 

quality assured data from a CEMS certified and operated in accordance to Part 75 to be used for EGU 

MACT compliance (with the exception of bias adjusted data and values derived from missing data 

substitution procedures).

Response to Comment 20: As mentioned elsewhere, the rule now allows use of Part 75 procedures for 

quality assurance and control activities for those monitors also used in Part 75.

Comment 21: Commenters18498 and 17725 note that section 63.10021(a)(10)(i) requires sources to 

“continuously monitor oxygen according to §§63.10010(a) and 63.10020” if you are required to install a 
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CEMS according to section 63.10010(a), however this contradicts the requirements in section 

63.10010(b) which allow the use of O2 or CO2. Also, the commenters note that the majority of Part 75 

affected coal-fired units utilize dilution extractive CEMS which are equipped with CO2 analyzers and 

CEMS cannot measure O2 as a diluent.

Comment 22: Commenter 17718 states that section 63.10021(a)(10)(i)and(ii)) references continuously

monitoring O2, but should also reference CO2 monitoring as a diluent as an alternative. The following 

specific language changes are suggested:

 Section 63.10021(a)(10)(i): “You must continuously monitor O2 or CO2 according to sections 

63.10010(a) and 63.10020.”

 Section 62.10021(a)(10)(ii): “Keep records of O2 or CO2 according to section 63.10032(b).”

Response to Comments 21 - 22: As mentioned elsewhere, the rule now allows O2 or CO2 CEMS to be 

used.

Comment 23: Commenter 17718 states that section 63.10021(a)(11)(v) requires all CEMS relative 

accuracy test audits (RATA) to be submitted electronically using the Electronic Reporting Tool. The 

commenter requests that the EPA clarify whether this requirement is only applicable to CEMS RATAs 

performed under the requirements of the rule. The commenter also requests that the EPA clarify whether 

only SO2 RATAs performed for the combined purposes of 40 CFR Part 75 and this regulation would be 

reported in ERT. Any annual NOX or flow monitor RATA performed for 40 CFR Part 75 requirements 

would not to be reported in the ERT even though it may have been performed concurrently.

Response to Comment 23: The agency reviewed the commenter’s concern and disagrees with the 

commenter’s assertion. The rule has not been changed, for the rule covers only those EGUs subject to 

the rule’s applicability. In the commenter’s example, no NOX CEMS RATA data would ever need to be 

reported electronically under this rule, but, as the commenter suggests, SO2 CEMS RATA data from 

those EGUs whose owners or operators choose to use SO2 CEMS as an alternative means of 

demonstrating compliance with acid gas emissions limits would need to submit those data electronically. 

3. IGCC comments.

Comment 24: Commenter 17801 recommends that the EPA provide further definition and clarification 

regarding air pollution control devices (APCD) to account for upstream fuel cleanup (e.g., removal of 

particulate, Hg, non-Hg metal HAPS, sulfur and/or chloride directly from the fuel stream of IGCC 

units). For example, for coal-fired units with add-on APCDs, it is unclear in section 63.10006 and/or 

Table 7 as to the testing program or operating limits to which IGCC would be subject. There is not an 

applicable combination of CEMS/APCD described that pertains to IGCC which could allow for 

emissions testing every five years for some coal-fired EGU sources instead of every other month for 

those sources without add-on controls. The EPA should consider any upstream gasification/fuel clean-up 

(e.g., AGR, SRU, PM scrubber) in the same way that coal-fired EGUs are credited for post-combustion 

or other APCD. IGCC should not be burdened with additional testing requirements if reduced testing 

programs are allowed for coal-fired units with add-on APCDs.

Response to Comment 24: The agency considered the commenter’s concerns, but the rule has not been 

changed. An IGCC unit can qualify for reduced frequency emissions testing under the existing rule’s 

LEE provisions, should an IGCC EGU owner or operator choose to use emissions testing as the means 

for demonstrating compliance with the emissions limits.
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Comment 25: Commenter 17191 notes that footnote number 206 appears to preclude the use of the SO2

monitoring option for IGCC units. The commenter suggests that this may be an unintentional 

consequence from carrying over language of other EGU category requirements for consistency and 

requests that either the footnote be removed or modified to state, “The alternate SO2 limit may not be 

used if your EGU does not have some form of pre- or post-combustion desulfurization system.” The 

commenter suggests that the modification is necessary because IGCC units do not require “flue gas 

desulfurization systems” as the sulfur is removed in the gasification phase (i.e., no post-combustion 

“flue gas” desulfurization is necessary). Instead, removing the reference to “flue gas” and replacing it 

with “pre- or post-combustion” accomplishes the objective of requiring desulfurization controls as a 

prerequisite for SO2 monitoring option without inadvertently preventing new and reconstructed IGCC 

units from pursuing the SO2 alternative.

Response to Comment 25: We believe that IGCC EGUs qualify for the use of SO2 monitoring as a 

surrogate for HCl. We have also clarified the definitions.

Comment 26: Commenter 17821 states that the EPA needs to revise the description and definitions of 

the IGCC APCD to account for upstream fuel cleanup and/or pollution prevention measures. For 

example, the technology used in IGCC units directly removes contaminants (such as particulate, Hg, 

non-Hg metal HAP, sulfur, chloride) directly from the fuel stream of IGCC units. In this respect, IGCC 

is more akin to a natural gas-fired combined cycle unit, since it burns a syngas, which is cleaner than the 

coal combusted in a pulverized coal unit. The EPA should reflect that IGCCs use upstream 

gasification/fuel clean-up (for example, AGR, SRU, PM scrubber) in the same way that coal-fired EGUs 

are credited for post-combustion or other air pollution control equipment such as SCR, ESP, and FGD. It 

makes no sense for IGCC to have additional testing burdens if reduced testing programs are allowed for 

coal-fired units with APCD. The EPA recognizes that an IGCC unit is a distinct type of electric 

generating unit by proposing a separate subcategory for IGCC units. The EPA needs to further 

acknowledge the process differences between IGCC units and PC units by providing clarification that 

for purposes of this MACT the affected facility is the combustion turbines and any emission limitations 

apply to the heat recovery steam generator HRSG stack. Commenter recommends that the EPA needs to 

provide further clarification that all upstream fuel clean-up in the IGCC process qualifies as control 

equipment, thereby not putting any additional testing burdens on IGCC units when reduced testing is 

allowed for coal-fired units with add-on pollution control equipment.

Response to Comment 26: As mentioned elsewhere, the agency considered the commenters’ concerns, 

but the rule has not been changed. An IGCC unit can qualify for reduced frequency emissions testing 

under the existing rule’s LEE provisions, should an IGCC EGU owner or operator choose to use 

emissions testing as the means for demonstrating compliance with the emissions limits. 

Comment 27: Commenter 19114 states that for IGCC units, the EPA should clarify the use of heat input 

and generation output terminology to account for (1) differences between coal-based (gasifier feedstock 

-based) and syngas-based heat input; and (2) differences between syngas-based and natural gas-based 

output during co-firing operations.

Response to Comment 27: The agency reviewed the commenter’s concern, and the rule now has 

differing filterable PM emissions limits for new syngas- and natural gas-fired IGCCs.

4. Fuel sampling and analysis.

Comment 28: Commenters 17716 and 17725 request that the EPA clarify whether units that fire a 
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single type of fuel (e.g., diesel oil) are exempt from all fuel sampling and analysis requirements. 

Although section 63.10005(c)(4) exempts units that fire a single fuel type from conducting fuel analysis 

as part of the initial compliance requirements, it does not address other fuel sampling requirements. 

Section 63.1001 states, “you must also conduct fuel analyses according to §63.10008 and establish 

maximum fuel pollutant input levels” and includes specifics for handling single-fuel units. The 

commenter questions whether the EPA intended to require single-fuel sources to conduct initial and 

ongoing fuel sampling like the IB MACT approach since other sections appear to only require fuel 

sampling when burning a new fuel type.

Comment 29: In addition to the fuel sampling clarification, commenter 17716 also recommends that the 

EPA expand the exemption in section 63.10005(c)(5) to cover units that fire multiple fuel types or 

blends in the final rule. The section states that, fuel sampling and analysis are not required for singlefuel units using supplemental fuels that are used only for startup, shutdown or for maintaining flame 

stability.

Comment 30: Commenter 17775 requests that the EPA review and update the language regarding fuel 

analysis tests in section 63.10008 and Table 6 to ensure clarity and consistency. Proposed section 

63.10008 requires fuel analysis tests according to the “procedures in paragraphs (b) through (e)” and 

Table 6. Paragraphs (c) and (d) specify minimum sampling procedure and compositing procedures. 

However, Table 6 also provides sampling methods that can be used in lieu of those in paragraph (c) and 

some of those procedures address compositing. The commenter requests that the language clearly state 

that any procedure identified in Table 6 can be used in lieu of procedures in paragraphs (c) and (d).

Comment 31: Commenter 17796 states that “What Are My General Requirements for Complying with 

this Subpart,” paragraph (c)(2), clearly states that liquid oil-fired EGUs can demonstrate initial and 

continuous compliance using fuel analysis for HCl, HF and total HAP metals but does not indicate that 

Hg can be used in the fuel analysis to demonstrate compliance. The commenter states that non-Hg HAP 

metals and Hg are generally segregated from other parameters for compliance determinations and 

requests that the EPA address these constituents clearly and cohesively.

Comment 32: Commenter 17386 states that the fuel analysis provision appears to be in direct 

contradiction to the discussion of this topic in the preamble of the rule (FR page 25053 Column1}, 

which states (after the initial compliance demonstration by fuel analysis), “We are proposing that a 

source be required to recalculate the fuel pollutant content only if it burns a new fuel type or fuel 

mixture...”

Comment 33: Commenter 17718 requests that the EPA clarify the frequency of ongoing fuel 

sampling/analysis required for purposes of comparison with “the maximum fuel input values calculated 

during the last performance tests (if demonstrating compliance through performance stack testing).”

Comment 34: Commenter 17718 states that the establishment of fuel limits appears applicable only to 

facilities that choose to comply via fuel analysis. If facilities apply CEMS, accurate compliance can be 

determined at the emission point and, therefore, the fuel input becomes irrelevant. Additionally, there 

are numerous inaccurate section/paragraph references within the proposed regulatory language of 40 

CFR 63.10011(b). The EPA should carefully review this section to properly link references to the 

appropriate sections and paragraphs.

Response to Comments 28 -34: The comments are moot because rule no longer requires fuel analysis 

for pollutants.
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5. Subcategory comments.

Comment 35: Commenter 17843 supports fuel-based testing for compliance demonstrations by liquid 

oil-fired units, but not stack testing every other month. The commenter notes the following 

inconsistencies and clarity issues regarding liquid oil-fired units sections:

 It is not clear that the language at section 63.10006(p) applies to low emitting EGUs and it is 

difficult to understand how the timing set out in section 63.10006(o) follows in section 

63.10006(p). The commenter suggests that sections 63.10006(f) and (g) should refer to Table 6 

(Fuel Analysis Requirements), not 5 (Performance Stack Testing Requirements), which would 

have more clearly allowed liquid oil-fired units to use fuel analysis to demonstrate compliance. 

Commenter 16513 also states that this section is unclear and adds that it is unclear what the term 

“continue to meet” in section 63.10006(p) means in the context of section 63.10006(o).

 In section 63.10006(s), the opportunity to demonstrate compliance with the Hg, individual or 

total non-Hg HAP metals, HCl, or HF emissions limit based on fuel analysis seems broader than 

the liquid oil-fired limited use subcategory, but the description in the preamble (see (d) above) 

appears to limit the fuel analysis compliance option to liquid oil-fired units that operate a limited 

amount of time per year on oil and are inoperative the remainder of the year.

 Commenters 17843 and 17796 both note that under section 63.10006 “When must I conduct 

subsequent performance tests, fuel analysis or tune-ups?,” it is clear that affected EGUs firing 

solid oil-derived fuel and coal-fired must demonstrate continuous compliance with either CEMS, 

or stack testing based upon the methodologies in Table 5, stack testing. It is not clear in this 

section what is required for liquid oil-fired EGUs. In subdivisions (f) and (g), based upon EGUs 

with or without non-Hg HAP metal controls, continuous compliance is demonstrated by either 

every other month or monthly, respectively, performance testing (stack testing) based upon Table 

5. In the same section 63.10006 subdivision (s), continuous compliance can be based upon fuel 

analysis, which contradicts subdivisions (f) and (g). The general requirements state fuel analysis 

is acceptable for liquid oil-fired EGUs for the initial and continuous compliance options these 

issues and request continuous monitoring requirements for liquid oil-fired EGU should be 

rewritten for parity and clarity.

Response to Comment 35: The comments concerning fuel analysis for pollutants are moot because rule 

no longer contains this requirement. The rule has been revised to clarify compliance options for liquid 

oil-fired EGUs, and the rule continues to allow an EGU owner or operator to choose a compliance 

option, including quarterly emissions testing, use of CEMS, or, in certain circumstances, tune-ups or 

fuel moisture analysis.

Comment 36: Commenter 17843 requests that the language in sections 63.10006(o), (p) and (s) be 

updated to clearly state the monitoring requirements for oil-fired EGUs and to indicate that stack testing 

is not intended to be conducted every two months.

Comment 37: Commenter 17718 recommends that the EPA clarify whether the fuel analyses and 

procedures in section 63.10008 are only applicable to liquid oil-fired EGUs that desire to meet their 

applicable emission limits through fuel sampling.

Comment 38: Commenter 17796 recommends that the requirements for the oil-fired units subcategory

be evaluated and revised for clarity with regard to initial and continuous monitoring parameters. For 

example, although section 63.10005, Testing, Fuel Analysis and Initial Compliance Requirements, 

subdivision (b) is clear that affected EGUs must demonstrate initial compliance with each of the 
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applicable emission limits in Tables 1 and Tables 2 by conducting performance tests according to 

section 63.10007 and Table 5 and either conduct fuel analysis, set operating limits or conduct 

Continuous Monitoring System evaluations. It is not clear in subdivision (c) that liquid oil-fired EGUs 

may choose to demonstrate compliance with fuel analysis. Subdivision (c) begins with compliance that 

can be demonstrated by fuel analysis “except for those affected EGUs that meet the exemption in (c)(4) 

and (c)(5) and those affected EGUs that opt to comply with individual or Total HAP metals limits in 

Tables 1 and 2 which must comply by conducting a fuel analysis as described in paragraph (c)(1).” No 

mention is made to paragraph (c)(2) which refers to HF or (c)(3). The commenter requests that 

subdivision (c) and continuous monitoring requirements be rewritten for clarity, and that all language 

regarding oil-fired units be evaluated for consistency and clarity.

The commenter states that section 63.10006(s), the opportunity to demonstrate compliance with the 

mercury, individual or total non-mercury HAP metals, HC1, or HF emissions limit based on fuel 

analysis seems broader than the liquid oil-fired limited use subcategory. The commenter recommends 

that if it is not the EPA’s intention to allow units other than liquid oil-fired limited use units to utilize a 

fuel analysis compliance mechanism, the EPA should clarify the language.

Comment 39: Commenter 17718 states that section 63.10011(b) makes reference to conducting fuel 

analyses and establishing maximum fuel pollutant input levels .” .as applicable.” The commenter 

requests that the EPA clarify that the fuel sampling, analyses, and maximum input levels are only 

applicable to liquid oil-fired EGUs that choose to meet their emission limits through fuel sampling 

methodologies.

Comment 40: Commenter 17881 states that if compliance via fuel sampling and analysis is only

available to liquid oil-fired units, then section 63.10021(a)(3) only applies to liquid oil-fired units, and 

the rule should clarify this point. Additionally, the commenter requests that the provisions of sections 

63.10011(c), 63.10021 (a)(6) and 63.10022(a)(6) should also specify that the paragraph applies only to 

liquid oil fired units or possibly LEE.

Response to Comments 36 - 40: As mentioned elsewhere, the comments concerning fuel analysis for 

pollutants are moot because rule no longer contains this requirement. The rule has been revised to clarify

compliance options for liquid oil-fired EGUs, and the rule continues to allow an EGU owner or operator 

to choose a compliance option, including quarterly emissions testing, use of CEMS, or, in certain 

circumstances, tune-ups or fuel moisture analysis.

Comment 41: Commenter 17174 states that the language in section 63.9983(b) for the natural gas-fired 

EGU exemption contradicts the preamble of the rule. The commenter suggests that EPA use the 

language in the preamble for the natural gas-fired EGU exemption in section 63.9983(b). Furthermore, 

the commenter states that the language does not clearly state the types of fuel-fired EGUs which are 

subject to this subpart. The commenter recommends that should be rewritten for clarity.

Comment 42: Similarly, Commenter 17881 notes that the preamble discussion is confusing and sheds 

no light on the purpose of section 63.9983(b). The preamble discussion could lead one to the conclusion 

that the proposed rule applies to all units other than natural gas-fired units (i.e., those units for which at 

least 90 % of the annual average heat over a 3-year period, or more than 85 % of the annual heat input in 

at least one year, is derived from natural gas).

Comment 43: Commenter 17881 states that the provisions of section 63.9983(b) are confusing because 

rule only applies to coal- and oil-fired EGUs, and the percentage of heat input supplied by natural gas is 
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not relevant if the unit is not classified as a coal- or oil-fired EGU. The provisions of section 63.9983(b) 

state that EGUs which are not coal-fired or oil-fired EGUs and which combust natural gas for certain 

minimum percentages of the annual average (i.e., > 15 %) or 3-year average heat input (i.e., > 10 %) are 

exempt from the rule. In cases where coal-fired or oil-fired EGUs co-fire such fuels with other fuels, 

section 63.9983(c) already contains provisions on the relative amount of coal and/or oil firing (on a heat 

input basis) which would subject the unit to the requirements of the rule.

Response to Comment 41 - 43: We believe that the definitions in the final rule along with other edits 

related to situations where sources may “switch” source categories make the clarifications suggested by

the commenter.

Comment 44: Commenter 17758 recommends that the language for coal-based compliance should be 

clarified. The commenter states that the most likely coal-based configurations able to comply with the 

EPA’s proposed rule will 1) opt for the total PM limit and utilize PM CEMS for continuous filterable 

PM measurements; 2) employ some combination of wet or dry scrubbing, and/or DSI, for acid gas 

control and elect to use already installed SO2 CEMS; and 3) directly monitor mercury using either a Hg 

CEMS or a sorbent trap monitoring system. For the above-described scenario in which either all of the 

regulated HAP or their surrogates are continuously monitored, the commenter states that no additional 

burdens (e.g., coal sampling, operating parameter limits, etc.) should be imposed. Although the 

commenter believes that the EPA does not intend to create additional burdens, the proposed rule is 

drafted is unclear and it is recommended that the language be updated for clarity.

Response to Comment 44: Although the agency is appreciative of the commenter’s view that the 

agency does not intend to create additional burdens, the rule must be written with all EGUs in mind, not 

just the majority. As mentioned elsewhere, the rule has been revised not to require additional 

compliance information from those EGU owners or operators who choose to use CEMS or sorbent trap 

monitoring as the means for compliance determination.

Comment 45: Commenter 17881 recommends that section 63.10006(e) be updated to reduce 

confusion. The paragraph pertains to those solid oil-fired and coal-fired EGUs without either a PM 

CEMS or PM control device. On the surface, it is hard to imagine any coal or petroleum coke fired 

boilers being operated without PM controls, so it is assumed that this paragraph must apply exclusively

to IGCC units. To eliminate any possible confusion, the commenter suggests that the EPA replace the 

term “solid oil-fired and coal-fired EGUs” with “IGCC unit” (Note that the definition of IGCC unit at 

section 63.10042 already incorporates the concept of solid oil or coal being used in the gasification 

process).

Response to Comment 45: The agency disagrees with the commenter, noting that the rule must be 

written to cover all possible control device scenarios, not just the ones believed to exist at the present 

time. As a result, no change to the rule has been made.

6. Operating limits comments.

Comment 46: Several commenters (17752, 17725, 17800) note that the rule contains conflicting 

language regarding how operating limits are established. Section 63.10011(d) refers to the average of 

three runs, while Table 4 of the proposed rule refers to the highest hourly average during the 

performance test. Commenter 17800 states that use of the “highest hour” makes no sense if the EPA is 

referring to Method 5 data, since runs are not measured in hours but in sample volume (and runs will be 

more than one hour). Both commenters recommend that the EPA provide a rationale for how a three-run 
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performance test is sufficient to capture operational variability of a unit and revise the operating limits 

language to be consistent across both sections, as opposed to allowing for a 30 boiler operating days as 

done for the other HAP. Commenter 17725 recommends establishing a FPM limit as a surrogate for 

non-Hg metal HAP instead of TPM, which would do away with the need for a PM “operating limit.”

Comment 47: Commenters 17681 and 17800 state that operating limits, including operating load limits 

and fuel limits, should not be established for units using CEMS for compliance because requirements to 

measure operating parameters are unnecessary and overly burdensome. For facilities using stack tests for 

compliance, the commenter recommends that the EPA allow sources to develop a CAM plan as an 

alternative to mandating operating limits, including operating load limits and fuel limits.

Comment 48: Commenter 17881 states that the procedures in Table 7 are not consistent with the 

provisions of section 63.10011(b)(6) or the definitions in section 63.10042. The commenter requests 

that, for Table 7, the EPA clarify that operating limits only apply in cases where CEMS are not used and 

does not apply for HF/HCl/Metals when you are demonstrating compliance with the surrogate standards. 

The commenter requests that consideration be given to the form of the DSI or ACI rates as an absolute 

mass will not work at reduced loads. For ACI, the rate has often been specified as lb ACI/mmACFM of 

flue gas.

Comment 49: Several commenters (17881, 17725, 18498) state that the limits for other operating 

parameters are inconsistent. Section 63.10042 defines the minimum operating parameters limits 

(minimum scrubber effluent pH, minimum pressure drop, minimum scrubber flow rate, minimum 

sorbent injection rate and minimum voltage or amperage) as 90 % of average value measured during the 

most recent performance test. However, Table 4 states that the parameters must be maintained “at or 

above the lowest 1-hour average” from the performance test. Commenter 18498 states that the “onesize-fits all” operating parameter limit approach should be revised to allow sources greater flexibility in 

defining representative operating parameters. Commenter 17881 requests the EPA must provide 

clarification as to how the operating limits are to be established.

Comment 50: Commenter 17718 states that the regulatory language seen in 40 CFR 63.10006 (a), (b), 

(d), (h) and (i) does not seem to allow for process improvements. As written, subsequent performance 

tests must be conducted “during the same compliance test period and under the same process (e.g., fuel) 

and control device operating conditions.” Process improvements discovered after initial compliance 

testing could potentially allow for the same or better control of emissions yet move the control device 

operating conditions outside of what was established as the “operating limits” established per Tables 4 

and 7 of the proposed rule. The commenter suggests that the “same process and control device operating 

conditions” language be removed from these regulatory sections to be similar to language proposed in 

40 CFR 63.10006 (e), (f), (g), (j), (k), (l), and (m) where testing under those “same conditions” is not 

required.

Comment 51: Commenter 17718 notes that section 63.10022(a)(6) states that existing units with an 

ESP in an emission averaging option must “maintain the monthly fuel content values at or below the 

operating limit established during the most recent performance test. The commenter requests that the 

EPA clarify why the presence of an ESP would require monthly fuel content determinations and 

suggests that the reference should be removed from the proposed regulation.

Response to Comments 46 - 51: As mentioned elsewhere, the comments concerning control device 

operating parameters and fuel analysis for pollutants are moot because rule no longer requires them. In 

addition, the Agency agrees that EGU owners or operators who choose to use CEMS as a compliance 
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option need not conduct other monitoring, that the use of continuous operating parameters in existing 

CAM plans or due to permitting or other program requirements is an appropriate means of assuring 

compliance with this rule’s emissions limits between emissions testing, and that a clarification on 

establishment of operating parameters for those EGU owners or operators who choose to use PM CPMS 

as a compliance option is needed; the rule now addresses each of those items.

7. Normal operating load.

Comment 52: Commenter 17174 states that section 63.10009(e) requires performance tests to be 

conducted at “maximum normal operating load.” However, section 63.10009(g)(2)(vii) requires 

demonstration of compliance with each of the applicable emission limit(s) to be achieved under 

“representative operating conditions.” The commenter requests that the EPA clarify this discrepancy and 

clearly define in section 63.10042 what constitutes maximum normal operating load or representative 

operating conditions.

Comment 53: Commenter 17731 states that the term “maximum normal operating load,” section 

63.10007(c), should be clarified and distinguished from “representative normal operating load.”

Response to Comments 52 - 53: The agency has reviewed the commenters’ concerns and revised the 

rule such that emissions testing is to occur at normal operating conditions. Moreover, if an EGU owner 

or operator wishes to demonstrate compliance under other than normal operating conditions, the rule 

requires emissions testing at those other conditions.

8. 30-day rolling averages.

Comment 54: Commenter 17821 has the following recommendations regarding 30-day rolling 

averages:

 Section 63-10010(b)(5) contains language that could be interpreted to mean that an O2

monitoring system is required for compliance with these regulations. The last sentence of this 

paragraph references developing 30-day rolling averages from “hourly oxygen emissions data.”

Paragraph (b) of this section references using CO2 monitoring. The commenter recommends that 

paragraph (5) of this section be modified to reference averaging either O2 or CO2 emissions data, 

if the EPA believes that O2 andCO2 are necessary.

 Section 63.10010(b)(5) also references using “all the hourly...emissions data” to develop 30-day

rolling averages. This language could be construed to mean that both valid and invalid data 

should be used to develop long-term averages. The commenter recommends that paragraph (5) 

be modified to include language to specify that only valid hourly data should be used to develop 

30-day rolling averages.

 Section 63.10010(c)(5)indicates that a 30-day rolling average for HCl should be developed; 

however the applicable engineering units are not specified. The commenter recommends that the 

EPA specify the engineering units that apply to the 30-day rolling average. Furthermore, this 

paragraph also references using “all the hourly HCl emissions data” to develop 30-day rolling 

averages. This language could be construed to mean that both valid and invalid data should be 

used to develop long-term averages. The commenter recommends that paragraph (5) be modified 

to include language to specify that only valid hourly data should be used to develop 30-day

rolling averages.

 Section 63.10010 (e)(5) indicates that sources should develop 30-day rolling average for SO2 but 

it does not specify the applicable engineering units. The commenter recommends that the EPA 
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specify the engineering units that apply to the 30-day rolling average. Furthermore, this 

paragraph also references using “all the hourly SO2 emissions data” to develop 30-day rolling 

averages. This language could be construed to mean that both valid and invalid data should be 

used to develop long-term averages. The EPA should modify this paragraph to include language 

to specify that only valid hourly data should be used to develop 30-day rolling averages.

 Section 63.10010 (g)(5) indicates that a 30-day rolling average for particulate emissions should 

be developed; however, the applicable engineering units are not specified. The commenter 

recommends that the EPA specify the engineering units that apply to the 30-day rolling 

average. Furthermore, this paragraph also references using “all the hourly particulate emissions 

data” to develop 30-day rolling averages. This language could be construed to mean that both 

valid and invalid data should be used to develop long-term averages. The EPA should modify

this paragraph to specify that only valid hourly data should be used to develop 30-day rolling 

averages.

Comment 55: Commenter 17681 notes an inconsistency between section 63.10010(g)(5) and Table 8. 

Section 63.10010(g)(5) states that 30-day rolling average is calculated as “the average of all of the 

hourly particulate emissions data for the preceding 30 boiler operating days.” In contrast, Table 8 states 

that the source is to convert “hourly emissions concentrations to 30 boiler operating mg/dscm values,”

which suggests that compliance is assessed on the average of 30 individual daily values. Commenter 

17681 also notes that the methods to calculate the 30-day rolling average is unclear and requests that the 

EPA clarify that a 30-operating day is based on the average of all applicable hours in the 30-day period.

Response to Comments 54 - 55: As mentioned elsewhere, the rule now allows CO2 or O2 CEMS to be 

used, clarifies that only valid hours are to be included in the 30 boiler operating day rolling average, 

identifies the reporting units as either pounds per heat input or pounds per electrical output, and clarifies 

that the 30 boiler operating day rolling average is based on the average of all valid hours in the 

preceeding 30 days of boiler operation.

9. Fuel mixtures and switches.

Comment 56: Commenter 17696 recommends that the EPA clearly state that performance testing on a 

“fuel mixture” does not require performance testing using coal of the same classification/common name 

that is provided by different suppliers, different mines or different seams. The commenter states that the 

proposal’s references to “fuel mixture” leave room for confusion even though the definition of “fuel 

type” (section 63.10042) is clear that individual fuel types received from different suppliers are not 

considered new fuel types. The EPA should clarify that, for example, if a subbituminous coal-fired unit 

has different suppliers of subbituminous coal, then the unit can conduct performance tests while burning 

any one of its suppliers’ subbituminous coal (or mixture of the different supplier’s subbituminous coals) 

and is not required to conduct performance tests using each supplier’s coal or to test using a blend of 

subbituminous coal from each of its different suppliers.

Response to Comment 56: The agency considered the commenter’s concern and disagrees with the 

commenter’s suggestion that the rule needs to offer additional clarification with respect to fuel switching 

with the same fuel type. The rule maintains that EGU owners or operators are to operate at normal 

operating conditions using normal fuels; if fuel conditions change, the rule requires the EGU owner or 

operator to conduct additional emissions testing. If an EGU owner or operator wishes to avoid having to 

be concerned about retesting based on fuel switching, he or she could use a CEMS option, rather than 

the emissions testing option, to demonstrate compliance.
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Comment 57: Commenter 18034 requests that the rule should articulate which standard applies when a 

unit fuel switches or when a unit burns blends of different fuels. Although units may have been designed 

to burn coal with a heat content of less than 8,300 Btu/lb, several units can and may switch to coal with 

a heat content greater than 8,300 Btu/lb. Fuel blending and fuel switching are common practices utilized 

to minimize SO2 emissions and the commenter recommends that the EPA take into consideration and 

encourage environmentally beneficial practices such as fuel blending and fuel switching.

Comment 58: Commenter 17781 recommends that the EPA clarify section 63.9982(d) regarding 

switching coal rank or fuel type by revising the language as follows:

“An existing electric utility steam generating unit that has switched completely to burning 

a different coal rank or fuel type is considered to be an existing affected source under this 

subpart.”

Response to Comments 57 - 58: The agency considered the commenters’ concerns and disagrees with 

the commenters’ suggestions. As mentioned elsewhere, the rule maintains that EGU owners or operators 

are to operate at normal operating conditions using normal fuels; if fuel conditions change, the rule 

requires the EGU owner or operator to conduct additional emissions testing. If an EGU owner or 

operator wishes to avoid having to be concerned about retesting based on fuel switching, he or she could 

use a CEMS option, rather than the emissions testing option, to demonstrate compliance. Moreover, the 

Agency sees no need to include the commenter’s suggested language changes in the rule because such 

changes could be misconstrued as changing the current definition of modification.

Comment 59: Commenters 17808 and 17870 seek clarification on the compliance requirements for 

units that may change from being “natural gas-fired” to “fossil fuel-fired.” A natural gas-fired 

generating unit may be forced to combust oil to maintain electric system reliability, and could suddenly

change from being an unregulated natural gas-fired unit to a regulated fossil fuel-fired generating unit (if 

the EPA does not adopt the above-proposed definition for curtailment). Outside of curtailment 

situations, a dual-fired unit may also burn oil if prices are competitive relative to natural gas or for other 

reasons. The proposed rule is unclear with regard to how much time the EPA would allow a newlydesignated fossil fuel-fired unit to schedule and perform its initial performance tests to demonstrate

compliance with the applicable standards. Commenter 17870 recommends a period of 180 days from the 

date that a unit newly meets the definition of an affected fossil fuel-fired unit subject to the rule.

Response to Comment 59: Although the agency has considered the commenter’s suggestions, the rule 

remains unchanged. An EGU owner or operator must remain cognizant of the definitions in the rule, 

especially, for this instance, the definitions of natural gas-fired electric utility steam generating unit and 

of oil-fired electric utility steam generating unit, along with rule requirements that trigger applicability 

and compliance dates. Generally, the modification of an existing unit renders the unit a new unit that is 

subject to its emissions limits upon startup.

10. SO2 comments.

Comment 60: Commenter 18498 notes that for SO2 CEMS, section 63.10021(a)(13) does not include 

the option to use the Part 75 certification and ongoing QA/QC requirements as allowed in section 

63.10010(e). Commenter 17705 suggests that section 63.10021(a)(13)(ii) should include a crossreference to section 63.10010 allowing use of 40 CFR Part 75 certified monitors to conduct SO2

monitoring, with exceptions listed in section 63.10010 (e)(6). This cross-reference will help clarify that 

monitors following the requirements of 40 CFR Part 75 can be used in lieu of monitors following 40 
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CFR Part 60.

Comment 61: Commenter 17716 recommends that the EPA use the Part 75 text on linear check tests 

instead of the text section 63.10010(e)(6)(ii), which states that one “must perform the linearity check test 

required in appendix A to Part 75 on the SO2 CEMS whether or not it has a span of 30 ppm or less.” The 

Part 75 exemption was developed on the basis that a linearity check “begins to lose its significance” at 

span values less than or equal to 30 ppm (63 FR 28032/28061 (May 21, 1998)).

Comment 62: Commenter 17714 requests that the EPA clarify the language placement of the SO2

monitor at the outlet of the EGU in section 63.10010(e) to definitively state that it refers to placing the 

monitor in the stack downstream of the SO2 control device for the EGU.

Comment 63: Commenter 17821 notes an unintended conflict between sections 63.10010 (e) and (e)(1). 

In paragraph (e), the EPA clearly states that sources operating an SO2 monitoring system for purposes of 

compliance with 40 CFR Part 75 may continue to do so under these proposed rules. However, in 

paragraph (e)(1), the rule defines and limits the operation and quality assurance to specific sections of 40 

CFR Part 60 without referencing the prior alternative to operate an SO2 CEMS under 40 CFR Part 75. 

The commenter recommends that the EPA modify paragraph (e)(1) of this section to clearly state the 

EPA’s intended use of 40 CFR Part 75 for applicable sources.

Response to Comments 60 – 63: As mentioned elsewhere, the rule has been clarified to allow use of 

Part 75 procedures for those CEMS subject to the rule and used in the Acid Rain Program. Moreover, 

the rule has been clarified so that CEMS are to be placed at the outlet of an EGU.

Comment 64: Commenter17881 states that none of the definitions for the term Er (regarding rolling 

emission averages in Equations 1 through 5) mention SO2, but there do not seem to be any prohibitions 

from averaging SO2 emission rates (assuming that all units included in the averaging plan would need to 

be eligible to use the SO2 surrogate). The commenter suggests that SO2 be added to the list of pollutants 

included in the term Er.

Comment 65: Commenters 18498 and 17725 recommend that the EPA add a subsection to section 

63.10010(e), which clarifies that bias adjusted data and Part 75 missing data shall not be used in 

calculating the 30 boiler operating day average SO2 emission rate. Although this is discussed in 

appendix A to subpart UUUUU for Hg CEMS (Reference appendix A sections 1.4 and 4.1.2.4), this data 

exclusion is not clearly stated for SO2 CEMS.

Response to Comments 64 - 65: The agency agrees with the commenter that SO2 should be included in 

all equations with the term Er, and the rule has been revised to correct that omission. The agency

disagrees with the commenter that additional language concerning acid rain program requirements is 

necessary for this rule. Should an EGU owner or operator lack SO2 hourly emissions data, no other data 

would be valid and thus eligible for inclusion in a 30 boiler operating day rolling average. Moreover, the 

EGU owner or operator would have to report the period of missing data to the Agency for further review 

and potential enforcement action.

11. Testing guidelines and timeline comments.

Comment 66: Commenter 17821 recommends that the EPA review the inconsistencies regarding 

section 63.10030(a) and section 63.10030(d). Section 63.10030(a) requires submission of all of the 

notifications in section 63.7(b) and section 63.9(e). Proposed Table 10 also identifies section 63.7(b) and 
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section 63.9 as applicable. Sections 63.7(b) and 63.9(e) require notification of “intent to conduct a 

performance test at least 60 calendar days before the performance test” is initially scheduled to begin. 

However, proposed section 63.10030(d) requires submission of a “Notification of Intent” to conduct a 

performance test, but “at least 30 days before the performance test is scheduled to begin.” Requiring 

submission of two identical notices at different times makes no sense. If the EPA intends to allow 

submission of the notice only 30 days before the test, the EPA should identify as “inapplicable” the 

inconsistent notice requirements. If the EPA intends to require submission 60 days before the test, the 

EPA must remove the redundant requirement in section 63.10030(d).

Response to Comment 66: The agency agrees with the commenter’s concerns, and the rule will be 

revised to have a consistent submission date for the notification of intent to conduct performance testing.

Comment 67: Commenter17758 requests that the EPA specify whether the time ranges provided for 

testing guidelines in section 63.10006(n) refer to calendar or operating days to avoid confusion. The 

commenter recommends that the preferred option should be in terms of operating days or operating 

quarters since these terms are used routinely by utilities to manage emissions program schedules and 

give utilities the flexibility necessary for performing the required tests.

Response to Comment 67: The time ranges in the rule refer to calendar, not operating, days.

Comment 68: Commenter 17821 requests that the EPA either identify when EGUs are not required to 

submit a Notice of Compliance Status or revise the section to make clear that all EGUs must submit 

such a Notice. Proposed section 63.10031(e) requires EGUs to submit a “Notification of Compliance 

Status” according to section 63.9(h)(2)(ii), “[i]f you are required to conduct an initial compliance 

demonstration as specified in § 63.10011(a).” However, under proposed section 63.10005(a) all EGUs 

“must demonstrate initial compliance with each of the applicable emission limits in Tables 1 or 2”

Moreover, section 63.9(h) on its face applies to each affected source when it becomes subject to a 

relevant standard.

Response to Comment 68: The agency disagrees with the commenter’s suggestion that an EGU owner 

or operator is unable to determine whether or not he or she will need to provide notice of compliance 

status based on the results of initial performance testing, whether for CEMS or for stack tests. The rule 

language has not been revised.

Comment 69: Commenter 17821 requests that the EPA issue a rule that clearly articulates the various 

compliance demonstration options. The commenter also notes that under paragraph (3), the Notification 

of Compliance Status must include “[i]dentification of whether you plan to demonstrate compliance 

with each applicable emission limit through performance testing and fuel analysis; performance testing 

with operational limits (e.g., CEMS for surrogates or CPMS); CEMS; or sorbent trap monitoring 

system.” The listed options do not appear to correspond with the rest of the proposed rule. For example, 

proposed section 63.10011(b) appears to require all EGUs that conduct performance testing to perform 

fuel analysis and to set operational limits.

Response to Comment 69: As mentioned elsewhere, much of the commenter’s concern is moot 

because rule no longer requires fuel analysis for pollutants or operational limits for control device 

parameters. Although the Agency disagrees with the commenter’s assertion that the rule is unclear with 

respect to compliance demonstration options, the rule has been revised to further clarify the options 

available to EGU owners or operators.
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Comment 70: Commenter 17881 states that the language in section 63.10009(j)(2) regarding each 

affected and non-affected unit meeting the most stringent emission limit is confusing, as non-affected 

units do not have any applicable emission limits under the proposed rule. The commenter questions 

whether the intent is to simply allow the common stack to comply with the most stringent emission limit 

that applies to any of the affected EGUs that exhaust to the common stack. If so, the commenter 

recommends that the regulatory language should more clearly reflect this intent.

Response to Comment 70: The agency disagrees with the commenter’s concern that the language 

regarding appropriate emissions limits from differing units sharing a common stack is confusing. The 

rule retains language requiring an EGU owner or operator who chooses to use emissions averaging to 

shut down units not subject to the rule during performance testing or to operate all units sharing a 

common stack at or below the most stringent emissions limit to which any individual EGU is subject, 

whether or not such individual EGU is subject to this rule. Should an EGU owner or operator remain 

concerned about meeting the rule’s requirements, he or she could choose not to use emissions averaging.

Comment 71: Commenter 17881 requests that section 63.10021(a)(4) be revised for clarity because 

EGUs without HCl CEMS are required to test monthly or bimonthly. Thus, the tests would already be 

conducted within the frequency (60 days) specified in the paragraph.

Response to Comment 71: The comment is moot, for the rule now requires EGU owners or operators 

who choose to use emissions testing as the compliance option for acid gas emissions limitations to 

conduct testing every quarter.

Comment 72: Commenter 17718 requests the following modifications to improve the clarity regarding 

performance testing:

 Section 63.10006(o) states that the ability to decrease the frequency of performance testing from 

annual (or more frequent) is available if testing shows emissions at or below 50 % of the 

emission limit and if there are “no changes in the operation of the affected source or air pollution 

control equipment that could increase emissions.” The commenter requests that the EPA provide 

clarification on what constitutes “no change” and what information would be needed to 

successfully pass these criteria. For example, it is unclear whether the “no change” provision 

applies to the affected unit and is not inclusive of the entire facility.

 Section 63.10007(c) requires performance tests to be conducted “while burning the type of fuel 

or mixture of fuels that has the highest content...” The commenter recommends that the EPA 

clarify whether reference to “type of fuel” simply means that if bituminous coal is typically

burned, then bituminous coal is to be used during the test. This section does not appear to require 

a determination that the highest chlorine (or other constituent) content bituminous coal be used 

during the test. The commenter also suggests a clarification that “special fuels” are not required 

or expected for the performance test.

 Section 63.10007(f) states that “(p)erformance tests shall be conducted under such conditions as 

the EPA Administrator specifies to the owner or operator....” The commenter recommends that 

the EPA clarify whether it will specify when and how performance testing is to be completed, 

beyond what is already proposed in other sections of the regulatory language. If the 

specifications are the same the commenter recommends that section 63.10007(f) should be 

removed.

Response to Comment 72: The agency disagrees with the commenter’s suggestion that specific criteria 

be enumerated concerning possible impacts of EGU operation on emissions for those EGU owners or 
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operators who choose to seek LEE status. Those EGU owners or operators are in the best position to 

understand what changes could cause impacts on emissions and remain responsible for EGU emissions; 

should an EGU owner or operator be uncomfortable meeting the LEE eligibility requirements, he or she 

need not apply. As mentioned elsewhere, the comment concerning highest pollutant content in fuel is 

moot, as fuel analysis for pollutants is no longer required. Finally, as mentioned elsewhere, the rule now 

requires emissions testing be performed at normal operating conditions.

Comment 73: Commenter 17718 requests that EPA clarify whether section 63.10009(c) requires that a 

“pre-test” be conducted so that a comparison can be made between a “30 day after” value and the initial 

compliance test. Section 63.10009(c) states that, “...the emission rate achieved during the initial 

compliance test for the HAP being averaged must not exceed the emission level that was being achieved 

on [...] or the control technology employed during the initial compliance test must not be less effective 

for the HAP being averaged than the control technology employed on....” If a pre-test is required, the

EPA should specify the notification and submittal requirements for such a test. 

Response to Comment 73: The rule has been revised so that an EGU owner or operator who chooses to 

use emissions averaging must be able to demonstrate compliance on a quarterly basis, which means that 

those owners or operators will need to ensure their existing units have at least three consecutive sets of 

30 boiler operating day average values if CEMS are used for compliance determination and at least one 

completed emissions test with test results if emissions testing is used for compliance determination by 

180 days after the effective date of this rule. Should an EGU owner or operator find these requirements 

to be of concern, he or she should choose not to use the emissions averaging option.

12. Other comments.

Comment 74: Commenter 17711 states that the word “sources” as used in the last clause of sections 

112(d)(3)(A) and (B) is ambiguous and, therefore, susceptible to reasonable interpretation. As the EPA 

explains in the preamble, the word “sources” might be construed to refer to all sources in the given 

category or subcategory. However, the word “sources” in the first clause of sections 112(d)(3)(A) and 

(B) clearly refers to the sources for which the EPA has emissions information. Notably, the second use 

of the word “sources” in section 112(d)(3)(A) also clearly is a reference to sources for which the EPA 

has emissions information. So, it is reasonable to conclude that Congress intended the word “sources” to 

have a consistent meaning for all purposes under these provisions. In other words, the reference “30 or 

more sources” at the end of section 112(d)(3)(A) and “fewer than 30 sources” at the end of section 

112(d)(3)(B) reasonably should be construed as a reference to sources for which the EPA has emissions 

information. This interpretation avoids the “absurd results” described above and allows for the EPA to 

naturally reconcile the application of sections 112(d)(2)(A) and (B) such that the number of sources for 

which the EPA has emissions information in a given category or subcategory dictates whether sections 

112(d)(2)(A) or (B) should apply.

Response to Comment 74: The EPA does not agree with the commenter’s interpretation. When 

Congress qualifies a word in one place but not others in the same section, the more reasonable inference 

is that it intended the qualification to apply only to that one instance.

Comment 75: Commenter 18034 supports the proposed emissions averaging approach; however, the 

EPA uses the term “applicable regulatory authority” exclusively in the context of submission, review, 

and approval of the emissions averaging implementation plan, such as in section 63.10009. Sources may

incorrectly believe that the state regulatory authority is responsible for review and approval the 

emissions averaging plans even if the state has not received delegation from the EPA for the specific 
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NESHAP rule. The commenter states that it is unnecessary for the EPA to use a separate term within the 

emissions averaging section. If a state accepts delegation of the final version of the proposed new 

subpart UUUUU, using the term “administrator” would apply equally for the emissions averaging 

provisions as it does to the other provisions of the rule. If a state has not received delegation for the 

NESHAP rule, not only would the state have no authority to issue an approval under section 

63.10009(g), the state is under no obligation to review the plans on the EPA’s behalf. The commenter 

recommends that the EPA should use the standard term of “the administrator” used elsewhere in the 

proposed rule to avoid confusion.

Response to Comment 75: The agency agrees with the commenter’s suggestion and has revised the 

rule.

Comment 76: Commenter 17174 suggests the following areas which would benefit from additional 

review and clarity.

 Section 63.10009(a) states “you may demonstrate compliance by emission averaging among the 

existing EGUs in the same subcategory, if your averaged emissions for such EGUs are equal to 

or less than the applicable emission limit” However, section 63.10009(e)(l) states, “You must use 

equation 1 of this section to demonstrate that the PM, HF, SO2, HCl, non-Hg HAP metals, or Hg 

emissions from all existing units participating in the emissions averaging option do not exceed 

the emission limits in Table 2.” The commenter recommends that the same wording be used in 

both sections in order to avoid confusion.

 Section 63.10009(e)(1) requires a facility to use Equation 1 to demonstrate compliance with PM, 

HF, SO2, HCl, non-Hg HAP metals or Hg emissions, by using the emission rate as determined 

during the most recent performance test and the maximum rated heat input capacity. The 

commenter requests that the EPA clarify what constitutes the maximum rated heat input capacity 

of a utility boiler due to the variability in reported heat input ratings for utility boilers.

 Section 63.10009(g)(2) states that, “If affected units from nonaffected units vent to the common 

stack, the units from nonaffected units must be shut down or vented to a different stack during 

the performance test.,” however it is unclear as to how one can have “affected units from 

nonaffected units.” The commenter suggests the phrase be evaluated and rewritten for clarity.

 Although section 63.10009(g)(1) states that implementation plan “must” be submitted no later 

than 180 days before the facility intends to implement the plan, section 63.10009(g) indicates 

that implementation plan submittal is only necessary “upon request.” The commenter 

recommends that the requirement to submit an implementation plan for emission averaging 

compliance should be evaluated and edited for consistency across sections. Commenter 17821 

also seeks clarification regarding the discrepancy between sections.

 Section 63.10021(a)(16)(vii) should clarify whether performance tune-ups needs to be submitted 

electronically to the EPA’s Central Data Exchange (CDX) by using the Electronic Reporting 

Tool (ERT), as required in other parts of this section (63.10021(a)(11) and (17)).

Response to Comment 76: Although the agency notes that the applicable emissions limit is the limit 

obtained from Table 2, the rule has been revised to be consistent. The agency does not agree that 

additional clarification on maximum rated heat input capacity is needed; EGU owners or operators 

should use the values submitted as part of the ICR process or as part of the acid rain program. The rule 

has been revised such that the sentence of concern now begins as “If emissions from affected units and 

from nonaffected units...” The rule has been clarified so that an averaging plan need only be submitted 

if requested by the Administrator. As a performance tune-up is a performance test, and the rule already

requires performance test results to be submitted electronically using the CDX, no additional 
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clarification language is needed.

Comment 77: Commenter 17716 requests the following corrections and clarifications:

 The rule does not include the equations for calculating PM or HCl mass emissions. Appendix A 

only includes equations for Hg. Commenter 17725 also notes this issue.

 Section 63.10009 (j)(3) references opacity requirements, however no opacity operating limits 

have been introduced as part of the rule. Commenters 17725, 17775, 18498-A2, 19120-A1and 

18014 also took notice and have requested that the issue be addressed.

 Section 63.10010(b)(5) should be revised to include CO2. For example, “... the average of all of 

the hourly oxygen or carbon dioxide emissions data for the preceding 30 boiler operating days.”

Response to Comment 77: As mentioned elsewhere, Table 5 describes how mass emissions can be 

calculated. The rule no longer contains opacity requirements, which were included in the proposal in 

error. As mentioned elsewhere the rule has been revised to include CO2 as well as O2 measurements.

Comment 78: Commenters 17675 and 17718 request that the reference in section 63.10010(a)(4) to 

“paragraph 2.1 of this section” does not specify if it is referring to appendix A or another paragraph 2.1. 

The commenter s recommends that the rule clearly state the proposed monitoring methods for stacks on 

units with main and bypass stacks.

Response to Comment 78: The agency agrees with the commenter, and the rule has been revised to 

clarify installation requirements.

Comment 79: Commenter 17681 requests that the EPA further explain what constitutes sufficient 

monitoring for control devices in section 63.10009(g)(2)(vi)(B).

Response to Comment 79: As mentioned elsewhere, this comment is moot for the rule no longer 

requires monitoring of control device operational parameters.

Comment 80: Commenter 17730 states that the requirement to optimize the flame in the boiler and 

optimize the emissions of CO and NOX lacks definition and needs explanation prior to the rule being 

finalized in order to comment.

Response to Comment 80: Although the agency disagrees with the commenter’s suggestion that the 

flame optimization requirements need additional explanation, the rule has been clarified with respect to 

these requirements.

Comment 81: Commenter 17756 requests that the EPA clarify the language regarding “dry flue gas 

technology.” The commenter states that the rule does not clearly indicate whether “dry flue gas 

technology” includes both dry scrubbers and dry sorbent injection. The commenter recommends that the 

EPA revise the language to specify that dry sorbent injection is an acceptable dry desulfurization 

technology.

Response to Comment 81: We believe that the definition in the final rule clearly indicates that both 

“dry scrubbers” and “dry sorbent injection” are included in “Dry flue gas desulfurization technology.”

Comment 82: Commenter 18023 states that to provide efficient application of the proposed rule, 4.1.3 

Diluent Gas, Flow Rate, and/or Moisture Monitoring Systems should state that “Monitors that have been 
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certified and quality assured to meet the requirements of 40 CFR Part 60 and/or 40 CFR Part 75 are 

acceptable for the purpose of calculating and reporting emissions without any additional certification or 

quality assurance.”

Response to 82: In the final rule, section 4.1.3 of Appendix A states that the flow rate, diluent gas, and 

moisture monitoring systems that are used to convert Hg concentrations to units of the standard must be 

certified according to 40 CFR Part 75. This is necessary, since all of the CEMS data will be collected 

using the ECMPS system. Section 63.10005(d) specifies that if a continuous monitoring system has been 

previously certified under another State or Federal program and is continuing to meet the on-going QA 

requirements of that program, no additional performance evaluations of the monitoring system are 

required for Subpart UUUUU, provided that the applicable requirements of §§63.10010(b) through (h) 

are met.

Comment 83: Additionally, commenter 18023 states that section 3.2.1.4.2 is in conflict with section 

3.1.7 where span value is defined but does allow rounding off the span value to the next highest integer 

multiple of 10. This would essentially restrict the span value to either 2 μg/m3 or 10 μg/m3. The rule 

should allow the user to set the span value anywhere between 2 and 10 μg/m3 as long as that range falls 

within acceptable limitations of the NIST traceable calibrator.

Response to Comment 83: The final rule provides sources with greater flexibility in setting the span 

value of the Hg monitor. The Hg concentration corresponding to the standard is doubled and then 

rounded off to either: (a) the next highest integer; (b) the next highest multiple of 5 μg/m3or; or (c) the 

next highest multiple of 10 μg/m3.

Comment 84: Commenter 17881 states that section 63.10011(c)(5) should clarify whether compliance 

can be based on all HAP metals in aggregate or individual metals.

Response to Comment 84: As mentioned elsewhere, this comment is moot for the rule no longer 

requires fuel analysis of pollutants.

Comment 85: Commenter 17718 states that within the proposed regulatory language seen in 40 CFR 

63.10005(l), it is mentioned that a “default diluents gas concentration value of 10.0 % O2 or the 

corresponding fuel-specific CO2 concentration” are to be used during periods of startup or shutdown 

when calculating emissions in units of “lb/MMBtu” or “lb/TBtu.” The EPA should clarify how to 

calculate the “corresponding fuel-specific CO2 concentration.”

Response to Comment 85: As mentioned elsewhere, this comment is moot for the rule no longer 

requires emissions limits during periods of startup or shutdown.

Comment 86: Commenter 17795 requests that the EPA make the following revisions:

 In section 63.10005(k) on start-up and shutdown default values, the commenter requests the 

following language be added: “For those CEM systems that measure on a wet basis use of the 

moisture estimation as specified in 40 CFR 75 §75.11 (b) shall be acceptable for this provision.”

 Also in section 63.10005(k) on start-up and shutdown default values, the commenter requests the 

following reference equations be added: 40 CFR 75, Appendix F, equations F-14a and F-14b.

 In section 63.10010 (b), the commenter requests the following language be added: 40 CFR 75 

QA/QC is sufficient to meet the CO2/O2 requirements of this regulation.

 In section 63.10010 (e)(6)(iii), the commenter requests that the reference to a fourth level needs 
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to be removed because there is no additional benefit or reason to run four gases during a 

linearity. This additional calibration level will not make the system any more accurate.

Response to Comment 86: As mentioned elsewhere, the comments are moot, for the rule no longer 

requires emissions limits during periods of startup or shutdown, the rule allows use of Part 75 quality

assurance requirements for those monitors that are also used in the acid rain program, and the reference 

to a fourth level was removed from the rule, even though it was an optional requirement.

Comment 87: Commenter 17714 recommends that the definitional language regarding “monitoring 

system malfunction” be moved into the definition area of the rule identified as section 63.10042 since it 

appears to be more of a definition than a requirement.

Response to Comment 87: The final rule will include a definition of monitoring system malfunction in 

the definitions section of the rule. That definition will mirror the definition for monitoring system 

malfunctions found in the proposed rule.

Comment 88: Commenter 17881 requests the following clarifications and revisions:

 Information regarding the unit or stack operating time [7.1.2.2] is not needed in order to calculate 

the Hg emission rate in units of lb/GWh, nor is it needed to calculate the lb/TBtu emission rate. 

Thus, the commenter requests that the requirement to collect this data be deleted.

 The commenter also requests that the EPA clarify that the hourly gross unit load [7.1.2.3] is only

needed for those units which are attempting to demonstrate compliance with a lb/GWh Hg 

emission limit.

 Information regarding the hourly heat input rate [7.1.2.4] is not needed to support the lb/GWh 

Hg emission rate calculations. The use of fuel factors in conjunction with the Method 19 

equations allow the determination of a lb/TBtu emission rate without the need to determine the 

hourly heat input rate. Thus, the requirement to collect this data should be deleted.

 In the context of the lb/TBtu Hg emission rate determination, the F-factor is not used to calculate 

the heat input rate. Thus, the commenter requests that section 7.1.2.6 should be revised as 

follows: “The F-factor used to calculate the lb/TBtu Hg emission rate, consistent with section 

6.2.1.2.” Further, the EPA should clarify that this information is only needed for those units 

which are attempting to demonstrate compliance with a lb/TBtu Hg emission limit (i.e., it is 

totally unnecessary for lb/GWh calculations).

 The commenter disagrees with the assertion in section 7.1.5 that volumetric flow rate records are 

required for purposes of determining lb/TBtu emission rates pursuant to section 6.2.1. None of 

the referenced Method 19 Equations (i.e., 19-1 – 19-9) rely on volumetric flow rate; rather, these 

equations rely on pollutant and diluent concentrations, fuel factors, and in some cases, flue gas 

moisture content. Thus, the EPA should clarify that volumetric flow rate measurements are only 

required for those units relying on sorbent trap monitoring systems and/or conducting lb/GWh 

mercury emission rate calculations.

 Section 7.1.5.2.5 requires the reporting of hourly PMA, however the commenter states that the 

requirement is not appropriate when missing data substitution is being prohibited. 

 Section 7.1.7 contains provisions related to diluent gas records in cases where compliance is 

being demonstrated on a lb/TBtu basis. Section 7.1.7.1 currently states that CO2 or O2

concentrations are needed “in order to calculate hourly heat input values.” The commenter states 

that the preceding statement is incorrect, as the diluent gas values are being used to allow the 

direct calculation of lb/TBtu emission rates based upon additional Hg concentration data and 

appropriate fuel factors. The cited text in section 7.1.7.1 should be deleted. As noted for similar 
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provisions within appendix A, section 7.1.7.2.5 relates to hourly PMA records and should be 

deleted.

 The monitoring plan reporting time lines also do not align with the related reporting provisions 

in 40 CFR Part 63, subparts A and UUUUU. The EPA must carefully review the two sets of 

reporting provisions and clearly reconcile any differences between the provisions. 

Response to Comment 88: The agency has reviewed the commenter’s suggestions and in some cases 

revised Appendix A of the rule. The rule retains requirements for collecting operating time and gross 

unit load; EGU owners or operators who do not need these values to determine their unit’s compliance 

need not collect these data. Rule text has been revised to remove hourly heat input rate from section 

7.1.2.4, as well as section 7.1.2.6. The rule has been revised so that section 7.1.5 refers only to 

volumetric flow from EGUs that use sorbent trap monitoring systems and that percent monitoring 

availability (PMA) is no longer included. The language in section 7.1.7.1 has been revised “...to convert 

Hg concentrations to units of the standard.” Finally, the agency believes the reporting time lines are now 

consistent.

Comment 89: Commenter 18034 states that section 63.10005(l) addresses the use of default O2 and CO2

concentrations for input-based emissions calculations and the default power production rate for outputbased emissions calculations but does not explain what pollutant concentrations should be used. The 

commenter requests that the pollutant concentrations be clearly stated. The commenter also requests that 

the EPA revise the rule to address the calculation of emissions during a malfunction.

Response to Comment 89: As mentioned elsewhere, this comment is moot for the rule now requires 

work practice standards, not emissions limitations, during periods of startup or shutdown.

Comment 90: Commenter 18034 states that provisions in the affirmative defense rules need 

clarification or appear to be contradictory:

 Section 63.10001(a)(4) unnecessarily requires additional conditions to meet an affirmative 

defense to bypass a control device. In some circumstances, the bypass may be the most 

appropriate temporary implementation while correcting or repairing a condition of upset, since 

the upset may be with the control device itself. All actions required to meet an affirmative 

defense are sufficiently listed in the other provisions of section 63.10001(a) and must be met, 

including those actions designed to minimize emissions.

 Section 63.10001(a)(7) lists a requirement that “All actions in response were properly 

documented by properly signed contemporaneous operating logs,” but does not define or 

accurately describe what would fulfill that requirement.

 Section 63.10001(a)(9) requires “a written root cause required to determine, correct, and 

eliminate the primary cause of the malfunction.” This inevitably leads to an owner or operator 

attempting to describe a preventative action to an event that (by definition of one of the criteria) 

was not preventable.

Response to Comment 90: We believe the language is clear, not contradictory in nature, and provides 

an owner or operator a systematic and thorough approach for establishing an affirmative defense in the 

event of a malfunction that results in an exceedance of a standard. Many of the conditions were modeled 

after the conditions of the affirmative defense in the EPA‘s SIP SSM policy, which several states have 

adopted into their SIPs. We do not have any indication that parties to enforcement proceedings have had 

any significant difficulties applying the terms of these SIP affirmative defenses. (See, e.g., State 

Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and 
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Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and 

Malfunctions (Feb. 15, 1983)). Other conditions were modeled after a Federal Implementation 

promulgated by EPA. ((40 CFR 50.1312). The EPA‘s view is that use of consistent terms in establishing 

affirmative defense regulations and policies across various CAA programs will promote consistent 

implementation of those rules and policies. The EPA notes that the purpose of the root cause analysis is 

to determine, correct, and eliminate the primary cause of the malfunction and that the root cause analysis 

itself does not necessarily require that the cause be determined, corrected or eliminated. However, in 

most cases, the EPA believes that a properly conducted root cause analysis will have such results.

Comment 91: Commenter 18498 states that section 63.10010(b)(5) should be revised to include CO2. 

For example, the commenter recommends that the language be amended to state:

“ ... the average of all of the hourly oxygen or carbon dioxide emissions data for the 

preceding 30 boiler operating days.”

Comment 92: Commenter 18498 notes that section 63.10021 (a)(10)(ii) does not include a reference to 

CO2 records.

Response to Comments 91 - 92: As mentioned elsewhere, the rule now includes carbon dioxide as well 

as oxygen, where oxygen is referenced.

Comment 93: Several commenters (17730, 17758, 17800) state that several provisions indicate that the 

requirements apply “as applicable,” but few provisions clearly state to which EGU subcategory or to 

which option the requirement applies. For example, the overuse of ‘‘as applicable” makes it difficult for 

the regulated source, or the state agency that will likely implement the program, to fully understand the 

requirements or demonstrate compliance with the chosen option. Commenter 17758 recommends that 

the EPA update the regulatory language to be consistent with its intent (e.g., unnecessary parameter 

limits which are not meant to apply when CEMS are used). The commenter further states that requiring 

excessive testing is inconsistent with EO 13563, as discussed elsewhere in these comments, which 

requires agencies to tailor regulations to impose the least burden on society, consistent with obtaining 

regulatory objectives.

Response to Comment 93: The agency disagrees with the commenters’ suggestions. An EGU owner or 

operator who does not have applicable requirements is not subject to the provisions of the rule, e.g., an 

owner or operator who chooses to use CEMS as the compliance demonstration method is not subject to 

the frequent emissions testing compliance demonstration method. Apart from some clarification, the rule 

remains unchanged. As mentioned elsewhere, the rule no longer requires separate operating parameter 

monitoring from emissions control devices if CEMS are used as the compliance demonstration method. 

Although the emissions testing frequency has been reduced to quarterly, it remains consistent with 

supplying the information necessary to show compliance with the emissions standard. Should an EGU 

owner or operator find the emissions testing compliance method too burdensome, he or she should 

choose from among the other options for demonstrating compliance with the emissions limits.

Comment 94: Similarly, commenter 17800 states that due to the incorrect references to sections, 

incorrect citations and many other inconsistencies and misstatements within the proposed rule, it is 

difficult for the commenter to evaluate what is needed to comply and determine the best plan for 

compliance with this rule. The commenter requests that remove the many inconsistencies noted before 

sources are expected to justify the expenditures associated with compliance to its shareholders, its rate 

payers and its regulators such as the public service commission.
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Response to Comment 94: As mentioned elsewhere, the rule has been revised to remove 

inconsistencies based on the Agency’s review and commenter’s suggestions.

Comment 95: Commenter 17909 states that the non-Hg metal HAP rules and compliance provisions 

portion of the proposed rule are indiscernible. Despite diligent, protracted study of the rule, participation 

in many, many conference calls and discussions with consultants, lawyers and the EPA staff, the 

commenter is unable to follow the rationale in the rule and therefore cannot apply the requirements to 

our affected source, plan for compliance or effectively comment on the proposed rule.

Response to Comment 95: Although the agency remains concerned that an EGU owner or operator 

claims difficulty understanding non-Hg metals rule options, the rule’s flexibility in that regard appears 

to be understood, if not welcomed, by a large majority of commenters. Basically, an EGU owner or 

operator chooses a PM emissions limit, or individual non-Hg metals emissions limits, or a total non-Hg 

metals emission limit and demonstrates compliance based on that choice. Depending on the emissions 

limit, compliance options range from frequent emissions testing to use of PM CPMS to use of PM 

CEMS. Notwithstanding a few clarifications as discussed elsewhere, the rule maintains this flexibility. 

The commenter should contact the Agency if he or she remains confused as to the rule requirements.

Comment 96: Commenter 17254 urges the EPA to re-propose the rule to address statistical errors in the 

calculation of the proposed emission standards for Hg. Commenter cannot comment meaningfully on the 

rules until we know what standard the agency ultimately will propose.

Response to Comment 96: We have corrected the errors noted during the public comment period as 

soon as they were brought to our attention and believe that commenters had sufficient review time with 

the corrected values to provide meaningful comment. Consequently, the EPA does not believe that 

reproposal is necessary or required.

Comment 97: Commenter 17689 states that the EPA construes “the requirements of the act” to mean 

only acid rain control when evaluating effects of other CAA program EGU emission reductions on EGU 

HAP emissions. The language here is clear and unambiguous: “requirements of the act” cannot be read 

to include only acid rain control.

Response to Comment 97: To the extent that EGUs are subject to other control requirements 

established by states and tribes as part of their strategies to attain the NAAQS, these are not 

“requirements of the act.” Similarly, requirements established as a result of specific new source 

permitting are in compliance with CAA-mandated programs but are not requirements of the act. When 

the CAA is examined to identify specific requirements that mandate emission reductions from EGUs, 

only Title IV, the acid rain provisions, can clearly be construed to establish such requirements.

13. Reference and numerical corrections.

Comment 98: Commenter17796 notes that the Hg limit in the preamble is a typo and should read 

0.0007 lb/GWh.

Response to Comment 98: The limits in the final rule have been reanalyzed and corrected.

Comment 99: Commenter17848 notes that the preamble contains an error in the output-based limit for 

Hg. The rule text indicates that the emission limit should be 0.008 lb/GWh, [however Table 1 indicates 

that it is 0.0008lb/GWh].
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Response to Comment 99: The limits in the final rule have been reanalyzed and corrected.

Comment 100: Commenter 17881 agrees with the intent of section 63.10005(l) but notes that the 

proposed rule erroneously identifies this paragraph as 63.10005(1).

Response to Comment 100: The comment is moot because the rule now requires work practice 

standards, not emissions limitations.

Comment 101: Commenter17655 recommends that the paragraphs (p) and (q) in section 63.10006 be 

renumbered as (o)(1) and (o)(2) because they are not free-standing but instead within the context of (o). 

The commenter also recommends that if these changes are made, the references to paragraphs (p) and 

(q), such as section 63.10006(n) be updated for consistency.

Response to Comment 101: The rule has been revised to consolidate the LEE requirements.

Comment 102: Several commenters (17696, 17718, 18037, 17821) note incorrect cross references in 

the text of the proposed rule. For example, section 63.10006(r) states “If you are required to meet an 

applicable tune-up work practice standard, you must conduct a performance tune-up according to 

§63.10007. Each performance tune-up specified in § 63.10007 must be no more than 18 months after the 

previous performance tune-up.” Section 63.10007 addresses only performance testing. Commenter 

17718 states that if “performance tune-ups” is the correct term, it appears that section 63.10021(a)(16) 

would be the more accurate section reference.

Response to Comment 102: Although the agency believes a tune-up serves as the performance test for 

certain EGUs for certain pollutants, the rule has been revised to describe the tune-up as a performance 

tune-up.

Comment 103: Commenter17174 notes the following editorial issues:

 The last paragraph of section 63.10005(k) on start-up and shutdown default values for calculations is 

numbered as (1).30 but should be labeled as (4) to continue the numbering of the section. 

Commenters 17775 and 17795 also note this incorrect numbering.

 The word “limit” is missing at the end of the last sentence of section 63.1 0011(b)(6)(iv).

 Section 63.10011 (c) states “and follow the procedures in paragraphs (c)(1) through (c)(7) of this 

section.” however there are only 6 paragraphs in section 63.10011 (c). Commenter 17881 also notes 

this inconsistency.

Response to Comment 103: As mentioned elsewhere, the comments are moot because rule no longer 

requires emissions limitations during periods of startup or shutdown, monitoring of control device 

operational parameters, or fuel analysis for pollutants.

Comment 104: Commenter17718 states that the reference in section 63.10010(b) to appendix A .”..in 

lieu of procedures in paragraphs (a)(1) through (a)(3) below....” is inaccurate because they do not pertain 

to O2 and CO2 monitors. The EPA likely needs to correct this reference to (b)(1) through (b)(5).

Response to Comment 104: The cross-reference to paragraphs (a)(1) through (a)(3) was clearly 

incorrect, and should have been (b)(1) through (b)(5), as noted by the commenter. Note, however, that in 

the final rule, the Agency has removed the Part 60 certification and QA alternative for diluent gas 

monitors, since all of the CEMS data will be collected using the ECMPS system. Section 63.10010(b) of 
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the final rule specifies that the CO2 or O2 monitors must be certified and quality-assured according to 

Part 75.

Comment 105: Commenters 17705 and 17775 note the following reference inconsistencies:

 Section 63.10021 (a)(10) references compliance with paragraphs (a)(10)(i) through (iii), but 

subsection (iii) is missing. Commenters 17821 and 17881 also note this inconsistency.

 Section 63.10021 (a)(11) references compliance with paragraphs (a)(11)(i) through (iv), yet the 

rule text includes additional paragraphs (v) and (vi).

 Section 63.10021 (a)(12) references compliance with paragraphs (a)(12)(i) through (iii), but 

subsection (iii) is missing. Commenter 17881 also notes this inconsistency.

 Section 63.10021 (a)(13) references compliance with paragraphs (a)(13)(i) through (iii), but 

subsection (iii) is missing.

 Section 63.10021 (a)(14) references compliance with paragraphs (a)(14)(i) through (iii), but 

subsection (iii) is missing.

Response to Comment 105: The agency appreciates the comments, and the rule has been revised to 

remove these inconsistencies.

Comment 106: Several commenters (19536, 19537, 19538) state that although the default diluents 

language can be found in section 63.10005(k), Low Emitting EGUs, in the second numbered paragraph 

(1), this appears to be a location error. The commenter states that it is not obvious where this paragraph 

should be located. Commenter 17718 states that within the proposed regulatory language seen in 40 

CFR 63.10005(k), the reference to performance test data requirements of “paragraph (l) of this section”

does not seem appropriate. The reference to “paragraph (l)” seems to point to “63.10005(l)” which 

discusses default diluents gas concentrations to be used for calculating emissions during startup and 

shutdown events and does not seem pertinent to “performance testing” mentioned in proposed 

63.10005(b). The commenter requests that the EPA clarify or provide guidance on how these two 

sections are to be used to aid qualification of LEE status.

Response to Comment 106: As mentioned earlier, these comments are moot, for the rule no longer 

requires emissions limitations during periods of startup or shutdown.

Comment 107: Commenter-17775 notes the following incorrect or missing references:

 Section 63.10005(k)(3) refers to section 63.10010(k)(3) however, there is no such provision. 

Commenter 17696 also notes this inconsistency.

 Section 63.10010(e) refers to procedures in (g)(1) through (g)(3) and (g)(6) however the EPA 

may have meant (e)(1) through (3) and (e)(6). Commenters 17714, 17795, 17718 and 17881 also 

note this inconsistency.

 Section 63.10010(h) refers to CPMS “as specified in Table 5.” Table 5 addresses “Performance 

Stack Testing Requirements.” Commenters 17752 and 17718 also note this incorrect reference. 

Commenter 17718 states that it appears that the EPA should have referenced Table 4 or Table 7 

instead.

 The reference in section 63.10011(b) to paragraph (c)(6) should most likely be section 

63.10011(b)(6). Commenter 17752 also notes this incorrect reference.

 The numbering of paragraph in section 63.10011(b) is not sequential. There is no section (b)(5) 

between (b)(4) and (b)(6). Commenter 17881 also notes this inconsistency.

 Section 63.10021(a)(8) refers to “maximum Hg input using Equation 9 of § 63.10011.” The 
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section and Equation 9 address non-Hg metals. Commenter 17752 also notes this incorrect 

reference.

 Table 4 states “If you demonstrate compliance using ... Fuel Analysis, you must “[m]aintain the 

fuel type or fuel mixture such that the applicable emission rate calculated according to 

§63.10011(d)(3), (4) and/or (5).

Response to Comment 107: The comments are moot, as described elsewhere the rule no longer 

requires operating parameter monitoring along with sorbent tube monitoring system monitoring, requires 

the use of Part 75 monitoring for those sources that also use monitors for the acid rain program, requires 

the establishment or monitoring of control device operating parameters, or requires fuel analysis of 

pollutants.

Comment 108: Commenter 17752 notes an incorrect reference in section 63.10031 (c).

Response to Comment 108: Although the comment lacks specificity, the agency has reviewed the 

section and revised the rule to correct references.

Comment 109: Commenter 17821 notes that appendix A, section 7.2.5.3.3 refers to paragraphs 7.1.2 

through 7.1.19. Section 7.1 ends with paragraph 7.1.10.8. The EPA should modify this paragraph to 

correct the misidentified range of paragraph numbers.

Response to Comment 109: The reference to section 7.1.19 was a typographical error, which has been 

corrected in the final rule.

Comment 110: Commenters 17881 and 17718 note that paragraph (a)(4) of section 63.10010 references 

“systems described in paragraph 2.1 of this section,” but there is no paragraph 2.1. The commenter 

suggests that it is likely that the EPA meant to reference section 2.1 in appendix A of proposed 40 CFR

Part 63, subpart UUUUU instead.

Response to Comment 110: The reference in §63.10010(a)(4) to “paragraph 2.1 of this section” was 

clearly an error and has been removed from the rule.

Comment 111: Commenter 17881 notes that in paragraph 63.10021(a)(14)(ii), the reference should 

likely be “Appendix A of this part.”

Response to Comment 111: The reference in §63.10021(a)(14)(ii) to “procedure 5 in Appendix F of 40 

CFR Part 60” was incorrect and should have been “Appendix A to this subpart”, as suggested by the 

commenter. However, note that in the final rule, all CEMS certification and QA requirements have been 

removed from §63.10021 and have been consolidated in §§63.10010 (b) through (h).

Comment 112: Commenter17821 recommends that the EPA revise the reference in section 

63.10021(a)(16)(vi) to reflect the language in section 63.10006(r) which states that each performance 

tune-up must be no more than 18 months after the previous tune-up.

Response to Comment 112: The agency has revised the rule so that the performance tune-up testing 

frequency is consistent.

Comment 113: Commenter 18498 suggests that section 63.10021 (h)(ii) should be revised to reference 

appendix A or more specifically, section 5 to appendix A. The commenter states that for Hg CEMS, 
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section 63.10021 (h)(ii) states the “Quarterly accuracy determinations and daily calibration drift tests 

shall be performed in accordance with procedure 5 in Appendix F of 40 CFR Part 60.” and contradicts 

section 63.10010(f) which references appendix A of this subpart.

Response to Comment 113: Section 63.10021 does not have a paragraph (h)(ii). The commenter is 

probably referring to §63.10021(a)(14)(ii), which references Procedure 5 in Appendix F of Part 60. See

the response to Comment 113, above.

Comment 114: Commenter 17881 notes that the following references and sections are wrong:

 reference to section 63.10021(a)(10) in section 63.10031(g)(1)

 reference to section 63.10032(b) and (c) in section 63.10032(d)(5)

Response to Comment 114: The rule has been revised to correct the cross references.

Comment 115: Commenter 17718 states that that the reference in section 63.10021(a)(2) to section 

63.10031(c) for keeping records of fuels should be section 63.10032(d) which outlines what fuel records 

are to be kept.

Response to Comment 115: The comment is moot, for the rule no longer requires fuel analysis of 

pollutants.

Comment 116: Commenter 17881 notes typographical errors in second sentence of section 

63.10009(j)(2). The commenter recommends that the sentence be revised as follows:

“If affected units and nonaffected units vent to the common stack, the nonaffected units 

must be shut down or vented to a different stack during the performance test or each 

affected and each nonaffected unit must meet the most stringent emissions limit”

Response to Comment 116: As mentioned elsewhere, the rule has been revised to clarify the language.

Comment 117: Commenter 17691 notes the following typographical errors in the rule:

 At 76 FR 25036, ECPMS could be modified [ .. .], ECPMS should be ECMPS.

 At 63.9990, “(2) EGUs designed for coal< 8,300 Btu/lb. (b) Oil-fired EGUs are [ ... ], 40 CFR 63 

.9990(b) should begin on the next line for better understanding. 76 FR 25103

 At 63.10005, the numbering of the 63.10005(k) is out of sequence. The last paragraph, (1) 

Startup and Shut down default [ .. .],should be numbered (4) instead of (1). 76 FR 25106

 At 63.10011, the numbering of the proposed 40 CFR 63 .1 0011 (b) is out of sequence. The 

numbering skips (5). 76 FR 25114

Response to Comment 117: The agency agrees with the commenter’s first two suggestions, and the 

preamble and rule have been revised. No changes to the rule were made for the last two suggestions 

since the rule no longer requires default values for calculations during periods of startup or shutdown 

and since the rule no longer requires establishment of maximum pollutant fuel input levels.

Comment 118: Commenter 17691 states that the rule refers back to a site-specific monitoring plan 

required by section 63.10000(d) in several places, however, section 63.10000(d) says there is an 

exemption in which some sources will not need a site-specific monitoring plan (i.e., facilities with 
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existing monitoring plans that meet the requirements of section 63.10010). Then, the proposed section 

63.10010 refers back to 40 CFR 63.10000(d). The commenter states that this circular reference causes 

confusion, makes the regulation difficult to follow, and should be eliminated. The commenter suggests 

that for each instance where the text refers back to the proposed 40 CFR 63.10000(d), there should be 

additional language to address the exemption.

Response to Comment 118: Although the agency disagrees with the commenter’s assertions, the rule 

has been revised so that only those EGUs without existing site-specific monitoring plans are required to 

submit those plans.
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8E - Rule: Other Language Corrections

Commenter: 17851

Comment 1: Commenter 17851 states that it is impossible to eliminate the causes for certain 

malfunctions, such as lightning strikes. The commenter also recommends that the EPA allow 

notification by email or other electronic means in addition to faxing to make the rule more modern and 

useful. The commenter requests that the rule be modified to include these notification methods.

Response to Comment 1: The agency agrees that some causes for malfunctions may be difficult to 

eliminate, which is why the rule offers EGU owners or operators the ability to describe the 

circumstances concerning a malfunction in a report. The agency understands and appreciates the 

commenter’s suggestion regarding use of electronic mail, but at this time the rule has not been changed 

to allow it for notification purposes. As the agency works through security and routing issues, the rule 

may be revised in the future to allow for electronic mail notification.

Comment 2: Commenter 17691 requests an inclusion of an equation in 40 CFR 63.10009 to provide a 

compliance demonstration method for each individual affected unit exhausting through a common stack.

Response to Comment 2: The EPA disagrees with the commenter’s suggestion. As mentioned 

elsewhere, the rule contains instructions on how EGUs sharing a common stack and subject to an 

emissions averaging program meet eligibility requirements and demonstrate compliance. No changes 

have been made to the rule.
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CHAPTER 9: GENERAL SUPPORT AND GENERAL OPPOSITION

9A - General Support

Comment 1: The EPA received 677,132 mass-mail and form letters expressing general support for the 

EGU NESHAP. Due to the high number of such comments for this proposed rule, these comments were 

categorized and sorted according to the group that organized the mass-mailing.

The U.S. Docket office identified 664,695 mass-mail comment letters and assigned them to 65 DCNs. 

These mass-mail DCNs are listed in Table 9A-1 of this section with the count of comment letters and the 

associated organization.

More mass-mail comment letters were identified from the remaining comment letters and are listed in 

Tables 9A-2 through 9A-20 in this section.

Three thousand and fifty (3,050) letters expressing general support that are not associated with any 

mass-mail campaign are listed in Table 9A-21 in this section.

Many organizations provided members with form letters. Form letters containing substantive comments 

had a few representative letters excerpted and summarized for the Response to Comments document, 

and the remaining letters are listed here.

Many commenters representing the American Lung Association (18576, 18590, 18707, 18716, 18721, 

18749, 18750, 18751, 18823, 18897, 18898, 18899, 18900, 18901 and 18930) wrote in support of the 

proposed mercury and air toxics standards, particularly in regard to the standards’ effect on human 

health. Further comments from the American Lung Association can be found in the document in 

comments from commenters 16826 and 18445.

Commenters (19111, 19210, 19225) representing chapters of the National Audubon Society, wrote to 

support the proposed rule and its reduction of mercury impacts on wildlife. Other Audubon Society 

commenters in this document are 17278, 17279, 17405 and 19101.

Commenters (16844, 17278, 17279, 17291, 17294, 17625, 18248, 18431, 18666, 19225) also expressed 

general support for the proposed rule, citing benefits to human health and the environment, particularly

due to controls on Hg emissions. Commenters 17291, 17294 and 19225 encourage the EPA to make the 

standard more stringent.

Comment 2: Commenter 18025 owns and operates four coal units and is part owner of four additional 

units ranging in size from small to large, anticipates the units will achieve the proposed standards, and 

therefore supports the proposed subcategories and emissions standards for coal-fired EGUs and agrees 

that they are consistent with requirements in the CAA.

Response to Comments 1 - 2: The EPA appreciates the commenters’ support for the Mercury and Air 

Toxics Standards. 
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Section 9A Tables

Mass Mailings - General Support for the Proposed Rule

Table 9A-1. Mass mail comments identified by the U.S. Docket Office

DCN Docket Entry Count

3084

Early Mass Comment Campaign sponsored by National Wildlife Federation 

(NWF) 10,845 

3085

Early Mass Comment Campaign sponsored by Environmental Defense Fund 

(EDF) 66,532 

3086

Early Mass Comment Campaign sponsored by League Of Conservation 

Voters 65,149 

3087 Early Mass Comment Campaign sponsored by Sierra Club 27,019 

3088

Early Mass Comment Campaign sponsored by Union of Concerned 

Scientists 10,872 

3089

Early Mass Comment Campaign sponsored by American Lung Association 

Action Network 2,116 

3090 Early Mass Comment Campaign sponsoring organization unknown 3,053 

3091

Early Mass Comment Campaign sponsored by Union of Concerned 

Scientists 47 

6638 Mass Comment Campaign sponsored by Greenpeace 4,685 

11053 Mass Comment Campaign sponsored by Earthjustice 8,704 

12055 Mass Comment Campaign sponsored by Earthjustice (Part 1 of 2) 3,112 

12056 Mass Comment Campaign sponsored by Earthjustice (Part 2 of 2)

13059 Mass Comment Campaign sponsored by the League of Conservation Voters 593 

13060 Mass Comment Campaign sponsoring organization unknown 78 

13061

Mass Comment Campaign sponsored by Citizens for Pennsylvania’s Future 

(PennFuture) 172 

13062 Mass Comment Campaign sponsoring organization unknown 202 

13063 Mass Comment Campaign sponsored by Sierra Club 27,255 

13421 Mass Comment Campaign sponsoring organization unknown 4,258 

16530 Mass Comment Campaign sponsoring organization unknown 95 

16531 Mass Comment Campaign sponsored by Environment Florida 43 

16546 Mass Comment Campaign sponsored by Earthjustice 29 

16547 Mass Comment Campaign sponsoring organization unknown 220 

16553

Mass Comment Campaign sponsored by Natural Resources Defense Council 

(NRDC) 9,678 

16554 Mass Comment Campaign sponsoring organization unknown 513 

16562 Mass Comment Campaign sponsoring organization unknown 73 

16565 Mass Comment Campaign sponsored by Physicians for Social Responsibility 2,607 

16566 Mass Comment Campaign sponsoring organization unknown 42 

16567 Mass Comment Campaign sponsored by National Audubon Society 5,279 

17007 Mass Mail Campaign sponsored by Alliance for Climate Protection 47,525 

17030 Mass Mail campaign sponsored by First Congregational Church of Sonoma 28 

17058 Mass Comment campaign sponsored by Environmental Defense Fund (EDF) 18,425 
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17059 Mass Comment campaign sponsored by Natural Resources Council of Maine 123 

17060

Mass Comment campaign sponsored by National Wildlife Federation Action 

Fund 9,106 

17802

Mass comment Campaign sponsored by Kentucky Environmental 

Foundation 12 

18190 Mass comment campaign sponsored by Sierra Club 9,440 

18490 Mass Comment Campaign sponsored by Ohio Citizen Action 1,405 

18491 Mass Comment Campaign sponsored by Fair Climate Project 52 

18492 Mass Comment Campaign sponsored by Clean Air Council 49 

18493 Mass Comment Campaign sponsoring organization unknown 39 

18494 Mass Comment Campaign sponsored by Interfaith Power & Light 643 

18495 Mass Comment Campaign sponsoring organization unknown 2,181 

18496 Mass Comment Campaign sponsored by Restoring Eden 11,819 

18546

Mass Comment Campaign sponsored by National Wildlife Federation 

(NWF) 433 

18638 Mass Comment Campaign sponsoring organization unknown 58 

18639

Mass Comment Campaign sponsored by Citizens Campaign for the 

Environment 33,165 

18640 Mass Comment Campaign sponsoring organization unknown 67 

18641 Mass Comment Campaign sponsoring organization unknown 29 

18642 Mass Comment Campaign sponsoring organization unknown 105 

18643 Mass Comment Campaign sponsoring organization unknown 2,611 

18965 Mass Comment Campaign sponsored by CREDO Action 136,779

18979 Mass Comment Campaign sponsored by GASP (formerly Alabama First) 94 

18986 Mass Comment Campaign sponsored by NC Conservation Network 904 

18988

Mass Comment Campaign sponsored by One Million Calls For Clean 

Energy 4,481 

19112 Mass Comment Campaign sponsored by Greenpeace 77,844 

19113 Mass Comment Campaign sponsoring organization unknown 20 

19125

Mass Comment Campaign sponsored by Respiratory Health Association of 

Metropolitan Chicago 94 

19150 Mass comment campaign sponsored by Earthjustice 37,286 

19550

Mass Comment Campaign sponsored by Fall-line Alliance for a Clean 

Environment (FACE) 130 

19573 Mass Comment Campaign sponsoring organization unknown 23 

19615

Mass Comment Campaign sponsored by GreenFaith, Interfaith Partners in 

Action for the Earth 13,074 

19632 Mass Comment Campaign sponsoring organization unknown 25 

19643 Mass Comment Campaign sponsored by Moms Clean Air Force 95 

19644 Mass Comment Campaign sponsoring organization unknown 2,959 

19647 Mass Comment Campaign sponsoring organization unknown 32 

19648

Mass Comment Campaign sponsored by Environmental Defense Fund 

(EDF) 269 

Total: 664,695
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In addition to the mass mailings identified by the Docket Office, 12,437 mass mail comments were also 

identified by RTI International. Not all of the comments can be linked to a specific organization.

Table 9A-2. American Lung Association

3328 5122 5212 5216 7582 7583 7586 7587 7588 7658 7659 7662

7663 7664 7665 7666 7667 7668 7669 7670 7671 7673 7674 7675

7747 7828 7859 8287 8434 8520 8521 8579 8958 8961 9022 9072

9112 9154 9159 9172 9376 9790 11314 11915 12384 12409 12411 12418

12425 12430 12431 12439 12467 12508 12521 12589 12630 12639 12675 12676

12715 12716 12720 12768 12801 13099 13539 14288 14303 14345 14347 14844

14901 14952 14965 14969 14972 14973 15020 15171 15209 15230 15280 15387

15457 15525 16054 16073 16214 16215 16217 16228 16241 17075 17076 17080

17081 17082 17086 17146 17147 18531 18559 18663 18676 18678 18679 18680

18688 18698 18914 18945 19203 19250

Total: 114

Table 9A-3. National Audubon Society

14180 14186 14191 14227 14228 14230 14233 14235 14239 14243 14258 14259

14265 14266 14269 14270 14273 14276 14277 14278 14285 14289 14290 14291

14292 14293 14294 14295 14296 14297 14298 14302 14304 14305 14306 14307

14308 14320 14321 14322 14323 14324 14326 14351 14352 14353 14355 14356

14357 14360 14361 14362 14363 14364 14383 14384 14385 14387 14389 14396

14401 14412 14415 14438 14439 14452 14453 14454 14455 14456 14457 14458

14459 14727 14767 14768 14778 14779 14791 14793 14805 14841 14843 14846

14853 14902 14903 14950 14951 14953 14962 14963 14964 14966 14970 14974

14975 15003 15006 15016 15017 15019 15042 15044 15050 15060 15165 15166

15167 15168 15194 15195 15196 15198 15211 15244 15252 15264 15265 15267

15268 15275 15277 15278 15279 15289 15290 15291 15292 15293 15294 15295

15296 15297 15298 15299 15324 15325 15326 15327 15333 15334 15340 15342

15343 15346 15386 15346 15389 15390 15391 15399 15400 15401 15405 15406

15407 15409 15419 15420 15421 15422 15423 15461 15494 15498 15532 15681

15683 15684 15891 15895 15913 16011 16049 16060 16064 16065 16066 16067

16068 16069 16072 16080 16081 16083 16084 16092 16100 16104 16117 16218

16282 16312 16528 16587

Total: 196

Table 9A-4. Care2Address

13791 13863 13864 13867 13869 13873 13874 13876 13880 13881 13882 13883

13888 13923 13983 17987 17988 17989 17990 17991 17992 17993 17994 17995

17996 17997 17998 18000 18001 18002 18003 18004 18005 18006 18007 18008

18010 18011 18012 18013 18050 18064 18069 18070 18071 18072 18073 18074

18075 18076 18077 18078 18079 18080 18081 18082 18083 18084 18085 18086
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18087 18088 18089 18090 18091 18092 18093 18094 18095 18096 18097 18098

18099 18100 18101 18102 18103 18105 18106 18107 18108 18109 18110 18113

18114 18115 18117 18118 18120 18121 18122 18124 18126 18127 18128 18129

18130 18131 18132 18133 18135 18136 18138 18140 18141 18142 18143 18144

18145 18146 18148 18149 18150 18151 18152 18154 18155 18156 18159 18161

18162 18163 18164 18165 18166 18167 18168 18169 18170 18171 18173 18175

18178 18179 18180 18181 18182 18183 18184 18187 18339 18340 18342 18343

18344 18345 18347 18345 18349 18350 18464 18466 18469 18470 18471 18473

18474 18578 18579 18587 18588 18589 18591 18592 18593 18594 18595 18596

18598 18629 18648 18651 18652 18656 18685 18691 18715 18717 18722 18723

18724 18725 18726 18727 18728 18766 18767 18781 18797 18798 18799 18800

18801 18802 18824 18825 18826 18827 18836 18851 18880 18881 18882 18883

18884 18976 18977 18978 18980 18982 18983 18984 18985 18989 18990 18992

18993 18994 18995 18996 18997 18998 18999 19000 19001 19002 19003 19031

19043 19044 19045 19046 19047 19048 19049 19050 19051 19052 19054 19055

19056 19058 19059 19060 19061 19062 19063 19064 19065 19066 19067 19068

19069 19070 19071 19072 19073 19074 19086 19087 19088 19092 19093 19106

19108 19110 19115 19116 19132 19133 19134 19136 19138 19139 19180 19181

19182 19183 19184 19186 19187 19190 19191 19306 19307 19333 19334 19335

19336 19337 19338 19339 19340 19341 19342 19343 19344 19345 19346 19347

19348 19349 19350 19351 19352 19353 19354 19355 19356 19357 19358 19359

19360 19361 19362 19363 19364 19365 19366 19367 19368 19369 19370 19371

19372 19373 19374 19375 19376 19377 19378 19379 19380 19381 19382 19383

19384 19385 19386 19387 19388 19389 19390 19391 19392 19393 19394 19395

19396 19397 19398 19399 19400 19401 19402 19403 19404 19405 19406 19407

19408 19409 19410 19411 19412 19413 19414 19415 19416 19417 19418 19419

19420 19421 19422 19423 19424 19425 19426 19427 19428 19429 19430 19431

19438 19439 19440 19441 19442 19443 19444 19445 19446 19447 19448 19449

19450 19451 19452 19453 19454 19455 19456 19457 19458 19459 19460 19462

19464 19465 19466 19467 19468 19470 19471 19472 19473 19474 19475 19476

19477 19478 19479 19480 19481 19482 19487 19492 19495 19499 19500 19501

19502 19503 19504 19505 19544 19567 19568 19569 19593 19608

Total: 443

Table 9A-5. Change.org

3640 3656 3657 3665 3666 3686 3687 3688 3698 3700 3703 3735

3736 3737 3738 3739 3793 3794 3795 3823 3907 3941 3942 3943

4001 4002 4003 4004 4005 4006 4007 4008 4009 4010 4011 4012

4014 4015 4016 4017 4018 4019 4020 4021 4022 4023 4024 4025

4026 4247 4250 4251 4253 4254 4255 4256 4257 4258 4259 4260

4261 4262 4263 4282 4284 4285 4287 4288 4289 4290 4303 4304

4305 4307 4308 4309 4310 4311 4312 4314 4315 4320 4347 4348

4349 4350 4351 4392 4393 4394 4395 4429 4430 4431 4454 4783
12/09/11 DRAFT

776

4825 4999 5000 5014 5042 5053 5054 5065 5082 5097 5138 5182

5183 5190 5191 5203 5204 5264 5280 5348 5349 5350 5351 5352

5353 5354 5355 5356 5369 5413 5414 5415 5416 5691 5701 5702

5703 5704 5705 5706 5707 5708 5709 5710 5711 5712 5713 5750

5751 5752 5753 5752 5852 5854 5856 5857 6113 6114 6494 6495

6496 6497 6500 6508 6509 6514 6517 6518 6519 6523 6524 6525

6526 6527 6530 6531 6532 6533 14776

Total: 175

Table 9A-6. EarthJustice

12116 12117 12118 12119 12120 12121 12122 12134 12135 12136 12137 12138

12139 12140 12141 12143 12144 12157 12158 12159 12160 12161 12162 12163

12164 12165 12166 12167 12168 12169 12179 12180 12181 12182 12183 12188

12189 12194 12196 12197 12198 12199 12200 12212 12213 12214 12215 12217

12218 12219 12220 12291 12292 12293 12294 12300 12302 12303 12304 12305

12315 12318 12319 12320 12321 12322 12323 12324 12325 12326 12327 12328

12329 12330 12331 12333 12338 12340 12343 12346 12347 12348 12349 12350

12351 12352 12353 12354 12357 12358 12360 12361 12362 12363 12364 12365

12366 12367 12368 12370 12371 12372 12373 12679 13700 13712 13733 13767

13768 13769 13770 13771 13772 13773 13774 13775 13777 13778 13779 13780

13781 13782 13783 13784 13786 13787 13788 13789 13790 13792 13810 13811

13812 13813 13814 13815 13816 13861 13862 13865 13866 13870 13875 13878

13961 14034 14424 14034 14507 14508 14515 14516 14517 14518 14600 14601

14602 14603 14604 14605 14606 14607 14608 14609 14611 14615 14622 14623

14626 14627 14632 14633 14650 14653 14655 14663 14670 14676 14677 15792

15828 15867 15873 15875 15915 15917 15918 15919 15921 15922 15923 15933

15954 15960 15985 15999 16000 16383 16413 17327 17328 17491 17981 17999

18104 18111 18112 18125 18139 18147 18172 18177 18189 18250 18251 18252

18253 18255 18256 18257 18258 18264 18271 18273 18275 18351 18352 18355

18358 18359 18461 18462 18586 18597 18650 18653 18657 18658 18713 18718

18789 18834 18842 18847 19104 19105 19107 19137 19305

Total: 249

Table 9A-7. Environmental Defense Fund (EDF)

3092 3093 3094 3095 3096 3097 3098 3099 3100 3101 3102 3103

3104 3105 3138 3139 3140 3141 3142 3143 3144 3145 3146 3147

3148 3149 3150 3151 3152 3153 3154 3155 3156 3157 3158 3159

3160 3188 3223 3224 3246 3247 3248 3249 3250 3251 3252 3253

3254 3255 3256 3258 3259 3260 3261 3262 3263 3264 3265 3266

3267 3268 3269 3270 3275 3276 3277 3278 3279 3280 3281 3282

3283 3284 3285 3286 3287 3288 3289 3290 3291 3292 3293 3294

3295 3296 3297 3298 3299 3300 3301 3302 3303 3304 3305 3306
12/09/11 DRAFT

777

3307 3308 3309 3315 3316 3317 3318 3319 3320 3321 3322 3323

3324 3325 3326 3327 3329 3330 3331 3334 3335 3336 3358 3361

3364 3366 3367 3371 3372 3373 3375 3378 3379 3380 3381 3383

3384 3389 3390 3392 3397 3398 3399 3400 3401 3402 3403 3404

3405 3406 3407 3406 3409 3410 3411 3412 3413 3414 3415 3416

3417 3418 3419 3420 3436 3437 3438 3439 3440 3441 3442 3443

3444 3454 3455 3456 3457 3458 3459 3460 3461 3494 3495 3496

3497 3498 3499 3500 3501 3502 3503 3504 3505 3506 3510 3512

3513 3515 3516 3517 3518 3519 3549 3550 3551 3552 3553 3554

3555 3556 3557 3558 3567 3569 3570 3571 3572 3573 3574 3575

3576 3577 3578 3579 3580 3581 3582 3583 3584 3585 3586 3587

3592 3593 3594 3595 3596 3597 3598 3599 3600 3601 3602 3603

3604 3605 3606 3607 3608 3609 3610 3611 3612 3613 3614 3615

3616 3617 3618 3619 3620 3621 3622 3623 3624 3625 3626 3627

3628 3629 3630 3631 3632 3633 3634 3635 3636 3637 3638 3639

3641 3642 3643 3644 3645 3646 3647 3648 3649 3650 3651 3652

3653 3654 3655 3658 3659 3660 3661 3662 3663 3664 3667 3668

3669 3670 3671 3672 3673 3674 3675 3676 3677 3678 3679 3680

3681 3682 3683 3684 3685 3689 3692 3693 3694 3695 3696 3697

3699 3701 3702 3704 3706 3707 3708 3709 3710 3711 3712 3713

3714 3715 3716 3717 3718 3719 3720 3721 3722 3723 3724 3725

3726 3727 3728 3729 3730 3731 3732 3733 3734 3741 3742 3743

3744 3745 3746 3747 3756 3757 3758 3759 3760 3761 3762 3763

3764 3765 3766 3767 3768 3769 3773 3774 3775 3776 3777 3778

3779 3780 3781 3782 3783 3784 3785 3786 3787 3788 3789 3790

3791 3792 3805 3806 3807 3808 3809 3810 3811 3812 3813 3814

3817 3818 3819 3820 3821 3822 3827 3828 3829 3830 3833 3834

3835 3836 3838 3839 3840 3841 3842 3843 3847 3848 3849 3853

3854 3855 3856 3861 3862 3863 3864 3869 3870 3871 3875 3876

3877 3878 3879 3884 3885 3886 3890 3895 3900 3908 3921 3922

3923 3924 3925 3938 3939 3944 3945 3946 3947 3949 3950 3951

3952 3953 3954 3955 3956 3957 3958 3959 3960 3961 3962 3963

3964 3965 3966 3967 3968 3969 3970 3971 3972 3973 3974 3975

3976 3977 3978 3979 3980 3981 3982 3983 3984 3985 3986 3987

3988 3989 3990 3991 3992 3993 3994 3995 3996 3997 3998 3999

4000 4013 4027 4028 4029 4030 4032 4033 4034 4035 4036 4037

4038 4039 4040 4041 4042 4043 4044 4045 4046 4047 4049 4074

4075 4076 4099 4100 4101 4102 4103 4104 4105 4106 4107 4108

4109 4110 4111 4112 4113 4114 4115 4116 4117 4118 4119 4120

4121 4122 4123 4124 4125 4126 4127 4128 4129 4137 4138 4140

4141 4142 4143 4144 4145 4146 4147 4148 4162 4167 4168 4169

4170 4171 4172 4171 4174 4175 4176 4177 4178 4179 4180 4181

4182 4183 4184 4185 4186 4187 4188 4189 4190 4191 4192 4193

4194 4196 4200 4216 4217 4218 4219 4220 4221 4222 4223 4224
12/09/11 DRAFT

778

4225 4226 4227 4228 4229 4230 4231 4232 4233 4234 4235 4236

4238 4241 4242 4243 4244 4245 4246 4248 4249 4252 4264 4265

4266 4268 4274 4275 4276 4277 4278 4279 4280 4281 4283 4286

4291 4292 4293 4295 4296 4298 4299 4300 4301 4302 4306 4313

4316 4317 4318 4319 4321 4322 4323 4324 4325 4326 4327 4328

4329 4330 4331 4332 4333 4334 4335 4336 4337 4338 4339 4340

4345 4346 4352 4353 4354 4355 4356 4357 4358 4359 4360 4361

4362 4377 4378 4379 4380 4381 4382 4383 4384 4385 4386 4387

4388 4389 4390 4391 4396 4397 4398 4399 4400 4402 4403 4404

4405 4406 4407 4408 4409 4410 4412 4413 4414 4415 4416 4417

4418 4419 4420 4421 4422 4423 4424 4425 4426 4427 4428 4433

4435 4436 4437 4438 4442 4443 4444 4445 4446 4447 4450 4451

4452 4453 4455 4456 4457 4458 4459 4460 4461 4463 4464 4465

4466 4467 4468 4469 4470 4471 4472 4473 4474 4475 4476 4477

4478 4479 4480 4481 4482 4484 4485 4486 4489 4490 4491 4492

4493 4497 4498 4499 4500 4501 4503 4504 4505 4506 4507 4508

4509 4510 4511 4512 4513 4514 4515 4516 4517 4518 4519 4520

4521 4527 4528 4529 4530 4531 4532 4533 4534 4537 4538 4539

4540 4542 4543 4546 4547 4548 4549 4550 4551 4552 4553 4555

4556 4558 4559 4560 4561 4562 4564 4566 4567 4568 4569 4570

4572 4573 4574 4575 4576 4577 4578 4579 4581 4582 4583 4584

4585 4586 4587 4588 4589 4590 4591 4592 4593 4594 4595 4596

4597 4598 4599 4602 4603 4604 4605 4606 4608 4609 4610 4611

4612 4613 4614 4616 4617 4619 4620 4621 4622 4623 4624 4625

4626 4628 4629 4630 4631 4632 4633 4634 4635 4636 4637 4638

4639 4640 4641 4643 4646 4647 4648 4649 4650 4651 4652 4653

4655 4656 4657 4658 4659 4660 4661 4663 4664 4669 4670 4675

4676 4679 4680 4681 4682 4683 4691 4692 4693 4694 4695 4696

4698 4699 4700 4701 4702 4703 4704 4707 4708 4709 4710 4711

4712 4713 4714 4715 4716 4717 4719 4720 4722 4723 4724 4725

4726 4727 4728 4729 4731 4733 4734 4735 4736 4737 4738 4739

4740 4741 4742 4743 4744 4745 4746 4747 4748 4749 4750 4752

4753 4754 4755 4756 4757 4758 4759 4760 4761 4762 4763 4764

4765 4766 4767 4768 4769 4784 4785 4786 4787 4788 4789 4795

4796 4798 4804 4798 4809 4810 4811 4812 4818 4819 4820 4821

4822 4823 4824 4920 4922 4924 4926 4927 4928 4931 4933 4942

4982 4983 4993 5005 5006 5007 5026 5027 5028 5029 5030 5031

5085 5098 5142 5158 5159 5174 5175 5192 5193 5205 5206 5207

5245 5247 5267 5268 5269 5295 5305 5318 5321 5330 5331 5345

5346 5446 5447 5448 5449 5450 5452 5453 5454 5455 5456 5457

5458 5459 5460 5517 5518 5560 5562 6112 6115 6116 6117 6118

6119 6120 6121 6122 6123 6124 6125 6126 6127 6128 6129 6130

6131 6132 6133 6134 6135 6136 6137 6139 6140 6141 6142 6143

6144 6145 6146 6147 6148 6149 6150 6151 6152 6153 6154 6155
12/09/11 DRAFT

779

6156 6157 6158 6159 6160 6161 6162 6163 6164 6165 6166 6167

6168 6169 6170 6171 6172 6173 6174 6175 6176 6178 6179 6180

6181 6182 6183 6184 6185 6186 6187 6188 6189 6190 6191 6192

6193 6194 6195 6196 6197 6198 6199 6200 6201 6202 6203 6204

6205 6206 6207 6208 6209 6210 6211 6212 6213 6214 6215 6216

6217 6218 6219 6220 6221 6222 6223 6224 6225 6226 6227 6228

6229 6230 6231 6232 6233 6234 6235 6236 6237 6238 6239 6240

6241 6242 6243 6244 6245 6246 6247 6248 6249 6250 6251 6252

6253 6254 6255 6256 6257 6258 6259 6260 6261 6262 6263 6264

6265 6266 6267 6268 6269 6270 6271 6272 6273 6274 6275 6276

6277 6278 6279 6280 6281 6282 6283 6284 6285 6286 6287 6288

6289 6290 6291 6292 6293 6294 6295 6296 6297 6298 6299 6300

6301 6302 6303 6304 6305 6306 6307 6308 6309 6310 6311 6312

6313 6314 6315 6316 6317 6318 6319 6320 6321 6322 6323 6324

6325 6326 6327 6328 6329 6330 6331 6332 6333 6334 6335 6336

6337 6338 6339 6340 6341 6342 6343 6344 6345 6346 6347 6348

6349 6350 6351 6352 6353 6354 6355 6356 6357 6358 6359 6360

6361 6362 6363 6364 6365 6366 6367 6368 6369 6370 6371 6372

6373 6374 6375 6376 6377 6378 6379 6380 6381 6382 6383 6384

6385 6386 6387 6388 6389 6390 6391 6392 6393 6394 6395 6396

6397 6398 6399 6400 6401 6402 6403 6404 6405 6406 6407 6408

6409 6410 6411 6412 6413 6414 6415 6416 6417 6418 6419 6420

6421 6422 6423 6424 6425 6426 6427 6428 6429 6430 6431 6432

6433 6434 6435 6436 6437 6438 6439 6440 6441 6442 6443 6444

6445 6446 6447 6448 6449 6450 6451 6452 6453 6454 6455 6456

6457 6458 6459 6460 6461 6462 6463 6464 6465 6466 6467 6468

6469 6470 6471 6472 6473 6474 6475 6476 6477 6478 6479 6480

6481 6482 6483 6482 6485 6486 6487 6488 6489 6490 6491 6492

6493 6498 6499 6501 6502 6503 6504 6505 6506 6507 6510 6511

6512 6513 6515 6516 6520 6521 6522 6528 6529 6534 6535 6536

6537 6538 6539 6540 6541 6542 6544 6545 6546 6547 6548 6549

6550 6551 6552 6553 6554 6555 6556 6557 6558 6559 6560 6561

6562 6563 6564 6565 6566 6567 6568 6569 6570 6571 6572 6573

6574 6575 6576 6577 6578 6579 6580 6581 6582 6583 6585 6586

6587 6588 6589 6590 6591 6592 6593 6594 6595 6596 6597 6598

6599 6600 6601 6602 6603 6604 6605 6606 6607 6608 6609 6610

6611 6612 6613 6614 6615 6616 6617 6618 6619 6620 6621 6622

6623 6624 6625 6626 6627 6628 6629 6630 6631 6632 6633 6634

6636 6664 6665 6666 6667 6668 6669 6670 6671 6672 6673 6674

6675 6676 6677 6678 6679 6680 6681 6682 6683 6684 6685 6686

6687 6688 6689 6690 6691 6692 6693 6695 6696 6697 6698 6699

6700 6701 6702 6703 6704 6705 6706 6707 6708 6709 6710 6711

6712 6713 6714 6715 6716 6717 6718 6719 6720 6721 6722 6723

6724 6725 6726 6727 6728 6729 6730 6731 6732 6733 6734 6735
12/09/11 DRAFT

780

6736 6737 6738 6739 6740 6741 6742 6743 6744 6745 6746 6747

6748 6749 6750 6751 6752 6753 6754 6755 6756 6757 6758 6759

6760 6761 6762 6763 6764 6765 6766 6767 6768 6769 6770 6771

6772 6773 6774 6775 6776 6777 6778 6779 6780 6781 6782 6783

6784 6785 6786 6787 6788 6789 6790 6791 6792 6793 6794 6795

6796 6797 6798 6799 6800 6801 6802 6803 6804 6805 6806 6807

6808 6809 6810 6811 6812 6813 6814 6815 6816 6817 6818 6819

6820 6821 6822 6823 6824 6825 6826 6827 6828 6829 6830 6831

6832 6833 6834 6835 6836 6837 6838 6839 6840 6841 6842 6843

6844 6845 6846 6847 6848 6849 6850 6851 6852 6853 6854 6855

6856 6857 6858 6859 6860 6861 6862 6863 6864 6865 6866 6867

6868 6869 6870 6871 6872 6873 6874 6875 6876 6877 6878 6879

6880 6881 6882 6883 6884 6885 6886 6887 6888 6889 6890 6891

6892 6893 6894 6895 6896 6897 6898 6899 6900 6901 6902 6903

6904 6905 6906 6907 6908 6909 6910 6911 6912 6913 6914 6915

6916 6917 6918 6919 6920 6921 6922 6923 6924 6925 6926 6927

6928 6929 6930 6931 6932 6933 6934 6935 6936 6937 6938 6939

6940 6941 6942 6943 6944 6945 6946 6947 6948 6949 6950 6951

6952 6953 6954 6955 6956 6957 6958 6959 6960 6961 6962 6963

6964 6965 6966 6967 6968 6969 6970 6971 6972 6973 6974 6975

6976 6977 6978 6977 6980 6981 6982 6983 6984 6985 6986 6987

6988 6989 6990 6991 6992 6993 6994 6995 6996 6997 6998 6999

7000 7001 7002 7003 7004 7005 7006 7007 7008 7009 7010 7011

7012 7013 7014 7015 7016 7017 7018 7019 7020 7021 7022 7023

7024 7025 7026 7027 7028 7029 7030 7031 7032 7033 7034 7035

7036 7037 7038 7039 7040 7041 7042 7043 7044 7045 7046 7047

7048 7049 7050 7051 7052 7053 7054 7055 7056 7057 7058 7059

7060 7061 7062 7077 7078 7079 7080 7081 7082 7083 7084 7085

7086 7087 7088 7198 7199 7200 7201 7202 7203 7204 7205 7206

7207 7208 7209 7210 7211 7212 7213 7214 7215 7216 7217 7218

7219 7220 7221 7222 7223 7224 7225 7226 7227 7228 7229 7230

7231 7232 7233 7234 7235 7236 7237 7238 7239 7240 7241 7242

7243 7244 7254 7255 7256 7302 7303 7304 7305 7346 7347 7348

7349 7350 7351 7352 7353 7354 7355 7356 7357 7358 7496 7499

7500 7501 7502 7503 7504 7505 7506 7507 7508 7509 7510 7511

7512 7513 7514 7515 7516 7517 7518 7519 7520 7521 7522 7523

7524 7525 7526 7527 7528 7529 7530 7531 7532 7533 7534 7538

7539 8256 8257 8300 8301 8580 8581 8582 8583 8584 8585 8586

8587 8588 8877 8878 8879 9268 9269 9270 9271 9272 9273 9274

9275 9276 9518 9519 9520 9521 9522 9524 9525 9526 9527 9528

9529 9530 9531 9532 9533 9534 9535 9536 9537 9538 9539 9540

9542 9543 9544 9545 9546 9547 9548 9550 9551 9552 9553 9554

9555 9556 9557 9558 9559 9560 9561 9562 9563 9564 9565 9566

9567 9568 9570 9571 9572 9573 9574 9576 9577 9578 9579 9580
12/09/11 DRAFT

781

9581 9582 9583 9584 9585 9586 9587 9588 9589 9590 9591 9592

9593 9594 9595 9596 9597 9598 9599 9600 9601 9602 9603 9604

9605 9606 9607 9608 9609 9610 9611 9612 9613 9614 9617 9618

9619 9620 9621 9622 9623 9624 9625 9626 9627 9628 9629 9630

9631 9632 9633 9634 9635 9636 9637 9638 9639 9640 9641 9642

9643 9644 9645 9646 9647 9648 9650 9651 9652 9653 9654 9655

9656 9657 9658 9659 9660 9661 9662 9663 9664 9666 9667 9668

9669 9670 9671 9672 9673 9674 9675 9676 9677 9678 9679 9680

9681 9682 9683 9684 9685 9686 9687 9688 9689 9690 9691 9692

9693 9694 9695 9696 9697 9698 9699 9701 9702 9703 9704 9705

9706 9707 9708 9709 9711 9712 9713 9714 9716 9718 9719 9720

9721 9722 9723 9724 9725 9726 9727 9765 9766 9767 9768 9769

9770 9860 9963 9964 9965 9966 9967 9968 9969 9970 9971 9972

9973 9974 9975 9974 9978 9979 9980 9981 9982 9983 9984 9985

9986 9987 9988 9989 9990 9991 9992 9993 9994 9995 9996 9997

9998 9999 10000 10002 10003 10004 10005 10006 10007 10008 10009 10011

10012 10013 10014 10015 10016 10017 10018 10019 10020 10021 10022 10023

10024 10025 10026 10027 10029 11064 11065 11066 11067 11108 11109 11110

11111 11112 11113 11114 11115 11116 11117 11118 11119 11120 11121 11122

11123 11124 11125 11126 11127 11128 11129 11130 11131 11132 11133 11134

11135 11136 11137 11139 11140 11141 11142 11143 11144 11145 11146 11147

11148 11149 11150 11151 11152 11153 11154 11155 11156 11157 11158 11159

11160 11161 11162 11163 11164 11165 11166 11167 11168 11169 11170 11171

11172 11173 11174 11175 11176 11177 11178 11179 11180 11181 11182 11183

11184 11185 11186 11187 11188 11189 11190 11191 11192 11193 11194 11195

11196 11197 11198 11199 11200 11201 11202 11203 11204 11205 11206 11207

11208 11209 11210 11211 11212 11213 11214 11215 11216 11217 11218 11219

11220 11221 11222 11223 11224 11225 11226 11227 11228 11229 11230 11231

11232 11233 11234 11235 11236 11237 11238 11239 11240 11241 11242 11243

11244 11245 11246 11247 11248 11249 11250 11251 11252 11253 11254 11255

11256 11257 11258 11259 11260 11261 11262 11263 11264 11265 11266 11267

11268 11269 11270 11271 11272 11273 11274 11275 11276 11277 11278 11279

11280 11281 11285 11286 11287 11288 11298 11351 11352 11403 11404 11439

11440 11441 11442 11443 11444 11446 11447 11448 11711 11712 11757 11772

11784 11785 11793 11794 11795 11810 11811 11812 11813 11814 11815 11816

12077 12078 12079 12080 12101 12102 12103 12105 12106 12107 12108 12110

12112 12113 12114 12115 12173 12174 12175 12176 12177 12185 12190 12191

12195 12203 12204 12205 12206 12207 12208 12209 12210 12211 12225 12234

12235 12236 12237 12241 12268 12269 12270 12271 12272 12273 12274 12275

12276 12277 12285 12286 12306 12309 12310 12311 12313 12317 12337 12342

12359 13696 13699 13701 13707 13709 13716 13801 13868 13871 13877 13879

14187 14422 14423 14425 14648 14657 15444 15668 15669 15671 15672 15673

15674 15675 15677 15774 15775 15776 15777 15778 15784 15787 15788 15789

15791 15852 15865 15866 15876 15930 15951 15952 15953 15955 15984 16377
12/09/11 DRAFT

782

16378 16382 16386 16387 16388 16389 16390 16391 16392 16393 16394 16395

16396 16397 16398 16399 16400 16401 16418 16448 16452 16453 16454 16455

16456 16457 16458 16459 16460 16462 16463 16464 16465 16466 16467 16468

16476 16477 16478 16480 16481 16482 16483 16484 16485 16486 16500 16978

16979 16980 16981 16982 17047 17048 17050 17051 17229 17230 17232 17235

17236 17252 17253 17256 17272 17288 17301 17302 17311 17312 17313 17326

17392 17394 17410 17394 17412 17413 17414 17415 17416 17417 17418 17419

17420 17421 17422 17423 17424 17425 17426 17427 17428 17429 17430 17431

17432 17433 17434 17435 17436 17437 17438 17439 17440 17441 17442 17443

17444 17446 17447 17448 17449 17450 17451 17452 17453 17454 17455 17456

17458 17459 17460 17461 17462 17464 17467 17468 17469 17474 17475 17476

17477 17478 17479 17480 17481 17482 17483 17484 17485 17487 17488 17492

17493 17494 17495 17497 17498 17499 17500 17501 17502 17503 17504 17505

17506 17507 17508 17509 17510 17511 17512 17513 17514 17515 17516 17517

17518 17519 17520 17521 17522 17523 17524 17525 17526 17527 17528 17529

17530 17531 17532 17533 17534 17535 17536 17537 17538 17539 17540 17541

17542 17543 17544 17545 17546 17547 17548 17549 17550 17551 17552 17553

17554 17555 17556 17557 17558 17559 17560 17561 17562 17563 17564 17565

17566 17567 17568 17569 17570 17571 17572 17573 17574 17575 17576 17577

17578 17579 17580 17581 17582 17583 17584 17585 17586 17587 17588 17589

17590 17591 17592 17593 17594 17595 17596 17597 17598 17599 17600 17601

17602 17603 17604 17605 17606 17607 17609 17610 17611 17612 17613 17614

17615 17616 17617 17618 17619 17630 17631 17632 17633 17634 17635 17636

17642 17643 17644 17645 17646 17647 17664 17665 17666 17667 17668 17669

17670 17671 17672 17673 17858 17859 17860 17861 17864 17865 17954 17955

17956 17957 17958 17959 17960 17961 17962 17963 17964 17965 17966 17967

17968 17969 17970 17971 17972 17976 17977 17978 17979 17980 17982 17983

17984 17985 17986 18009 18053 18054 18055 18056 18057 18058 18059 18060

18061 18062 18063 18066 18067 18068 18116 18119 18123 18134 18137 18153

18157 18158 18160 18174 18176 18185 18188 18191 18192 18193 18194 18195

18196 18197 18198 18199 18200 18201 18202 18203 18204 18205 18206 18207

18208 18209 18210 18211 18212 18213 18214 18215 18216 18217 18218 18219

18220 18221 18222 18223 18224 18225 18226 18227 18228 18229 18230 18231

18232 18233 18234 18235 18236 18237 18238 18239 18240 18241 18242 18243

18244 18245 18246 18247 18254 18259 18261 18262 18263 18265 18266 18268

18269 18270 18272 18274 18276 18277 18278 18329 18330 18331 18332 18333

18334 18335 18336 18337 18338 18341 18346 18353 18354 18356 18360 18451

18452 18453 18454 18455 18456 18457 18458 18459 18460 18463 18465 18467

18468 18472 18475 18476 18536 18577 18580 18581 18582 18583 18584 18585

18625 18626 18627 18628 18630 18632 18633 18645 18647 18649 18654 18655

18677 18684 18702 18709 18710 18711 18714 18729 18730 18731 18732 18733

18734 18735 18736 18737 18738 18739 18740 18741 18742 18752 18753 18754

18755 18756 18757 18758 18768 18769 18770 18771 18772 18773 18774 18775

18777 18778 18779 18778 18783 18786 18787 18788 18790 18791 18792 18793
12/09/11 DRAFT

783

18794 18795 18796 18803 18804 18805 18806 18807 18808 18809 18810 18811

18812 18813 18814 18816 18817 18818 18819 18821 18822 18829 18830 18832

18833 18837 18838 18839 18840 18843 18844 18845 18846 18852 18853 18854

18855 18856 18857 18858 18859 18860 18861 18862 18885 18886 18888 18889

18890 18891 18892 18902 18903 18904 18905 18906 18923 18931 18941 18942

18943 18948 18981 18991 19017 19018 19019 19020 19021 19022 19053 19057

19126 19127 19128 19129 19130 19131 19135 19146 19147 19151 19152 19157

19169 19170 19171 19185 19192 19263 19267 19268 19269 19270 19272 19288

19289 19291 19292 19297 19298 19299 19303 19304 19310 19311 19312 19313

19314 19315 19316 19317 19318 19319 19321 19322 19323 19324 19325 19326

19327 19329

Total: 3,386

Table 9A-8. Persons of Faith

11377 11378 11379 11380 11383 11384 11386 11387 11388 11389 11391 11392

11394 11395 11413 11414 11415 11416 11417 11421 11422 11423 11424 11425

11427 11532 11536 11882 11884 11885 11886 11887 11888 11996 11997 11998

12000 12001 12004 12065 12066 12068 12090 12093 12129 12132 12171 12417

12464 12719 12836 13537 13640 14027 16094 16095 16096 16097 16098 16099

16101 16102 16114 16115 16116 16126 16166 16213 16225 16231 16311 16323

16352 16555 16556 16557 16558 16559 16561 16564 16569 16584 16585 16586

16588 16589

Total: 86

Table 9A-9. Green Peace

5911 5913 6639 10646 10651 10758 10766 10767 10811 10813 10847 10848

10849 10850 10851 10852 10853 10854 10855 10856 10857 10858 10859 10860

10861 10862 10869 10870 10871 10872 10873 10874 10875 10876 10877 10878

10879 10880 10881 10882 10883 10884 10885 10886 10887 10888 10889 10890

10891 10892 10893 10894 10895 10896 10897 10898 10899 10900 10901 10903

10904 10905 10907 10908 10909 10910 10911 10912 10913 10915 10916 10917

10918 10919 10920 10921 10922 10923 10924 10925 10926 10927 10928 10929

10930 10931 10932 10933 10934 10935 10936 10937 10938 10939 10940 10941

10945 10946 10947 10948 10949 10950 10951 10952 10953 10954 10955 10956

10957 10958 10959 10960 10961 10962 10963 10964 10965 10966 10967 10968

10969 10970 10971 10972 10973 10974 10975 10976 10977 10978 10979 10980

10981 10982 10983 10984 10985 10986 10988 10989 10990 10991 10992 10993

10994 10995 10996 10995 10998 10999 11000 11001 11002 11003 11004 11005

11006 11007 11008 11009 11010 11011 11012 11013 11014 11015 11016 11017

11018 11019 11020 11021 11022 11023 11024 11025 11026 11027 11028 11029

11030 11031 11032 11033 11034 11035 11036 11037 11038 11039 11040 11041

11042 11043 11044 11045 11046 11047 11048 11049 11050 11051 11052 11054
12/09/11 DRAFT

784

11055 11057 11058 11059 11060 11061 11062 11063 11068 11069 11070 11071

11072 11073 11074 11075 11076 11077 11078 11079 11080 11081 11088 11089

11090 11091 11092 11093 11094 11095 11097 11098 11099 11100 11101 11102

11103 11709 12625 12674 12890 13052 14001 14002 14246

Total: 249

Table 9A-10. Full Support

16177 16220 16242 16319 17151 18659 18665 18667

Total: 8

Table 9A-11. League of Conservation Voters

5465 9382

Total: 2

Table 9A-12. Natural Resources Council of Maine

4077 4078 4079 4080 4081 4082 4083 4084 4085 4086 4195 4197

4198 4199 4201 4202 4203 4204 4205 4206 4207 4208 4209 4213

4239 4240 4267 4269 4270 4271 4272 4273 4374 4462 4554 5146

5163 5432 6635 12287 12355 12356 13697 14669 15676 15926 16439 16440

16441 16442 16443 16444 16445 16446 16447 16449 16451 16470 16471 16472

16473 16474 16475 16479 16541 16545 17231 17284 17285 17286 17287 17314

17322 17325

Total: 74

Table 9A-13. Natural Resources Defense Council (NRDC)

12645 12875 13084 13085 13089 13090 13091 13092 13093 13097 13100 13101

13105 13106 13148 13150 13190 13191 13192 13193 13255 13256 13264 13265

13266 13272 13273 13299 13300 13301 13331 13332 13336 13337 13347 13348

13349 13350 13351 13352 13354 13355 13356 13357 13359 13360 13361 13362

13366 13367 13368 13369 13370 13371 13372 13373 13374 13376 13377 13378

13379 13384 13386 13387 13388 13389 13390 13391 13392 13393 13394 13395

13396 13397 13401 13406 13407 13408 13412 13413 13414 13415 13416 13417

13418 13427 13428 13429 13430 13431 13444 13445 13446 13447 13459 13464

13465 13468 13496 13497 13508 13509 13510 13511 13517 13536 13538 13540

13541 13547 13564 13566 13569 13570 13572 13573 13603 13604 13605 13606

13609 13611 13612 13613 13614 13621 13622 13623 13624 13629 13630 13631

13632 13635 13639 13644 13672 13673 13674 13690 13691 13693 13694 13796

13797 13798 13799 13798 14019 14025 14033 14046 14047 14071 14077 14122

14135 14139 14140 14144 14149 14160 14170 14171 14202 14394 14721 14804

15173 15197 15281 15285 15321 15339 15341 15914 16522 16525 17144 17145

17149 17150 18396 18398 18403 18407 18412 18635 18636 18913
12/09/11 DRAFT

785

Total: 190

Table 9A-14. National Wildlife Federation (NWF)

3852 3860 3868 3882 3883 3894 3899 4087 4088 4089 4090 4091

4092 4093 4094 4095 4096 4097 4098 4154 4155 4156 4157 4158

4159 4160 4161 4163 4164 4165 4166 4210 4211 4212 4214 4215

4237 4297 4366 4367 4368 4369 4370 4371 4372 4373 4375 4376

4401 4411 4434 4439 4440 4441 4448 4449 4494 4495 4496 4502

4525 4526 4535 4536 4541 4544 4545 4563 4565 4571 4580 4600

4601 4607 4615 4618 4627 4642 4644 4645 4665 4666 4667 4668

4672 4674 4678 4688 4689 4690 4697 4732 4826 4827 4923 4925

4932 4959 4971 5001 5002 5003 5004 5019 5020 5021 5022 5023

5024 5025 5056 5057 5068 5076 5077 5078 5084 5102 5103 5104

5120 5140 5141 5176 5184 5242 5243 5244 5246 5265 5266 5281

5282 5286 5294 5303 5304 5317 5319 5320 5329 5428 5429 5430

5431 5433 5434 5433 5436 5437 5438 5439 5440 5441 5442 5443

5444 5445 5451 5469 5470 6177 6694 9710 9976 10001 10010 10028

11056 11138 11445 11533 12100 12109 12111 12142 12178 12184 12186 12187

12193 12216 12289 12299 12301 12308 12332 12341 12344 13698 13710 13803

13884 13885 13886 13887 13889 13890 13891 13892 13893 13894 13895 13896

13897 13898 13899 13900 13901 13903 13904 13905 13906 13909 13910 13911

13912 13913 13914 13915 13916 13917 13918 13920 13921 13922 13924 13925

13926 13927 13928 13929 13930 13931 13933 13934 13935 13936 13937 13938

13939 13940 13941 13942 13943 13944 13945 13946 13947 13948 13949 13950

13951 13952 13953 13954 13955 13956 13957 13958 13959 13960 13962 13963

13964 13984 13985 13986 13987 13988 13989 13990 13991 13992 13993 13994

13995 13996 13997 13998 13999 14000 14421 14426 14435 14436 14437 14462

14463 14464 14465 14466 14467 14468 14469 14470 14471 14472 14473 14474

14475 14476 14477 14479 14502 14505 14510 14661 14665 15402 15433 15434

15435 15436 15437 15438 15440 15441 15442 15443 15445 15446 15514 15515

15516 15517 15518 15548 15549 15550 15551 15552 15557 15558 15559 15786

15813 15920 15931 15932 15934 15956 15959 15961 16380 16384 16551 17234

17324 17653 19606 19612

Total: 352

Table 9A-15. Ohio Citizens Action

17239 17240 17245 17257 17258 17259 17260 17261 17262 17263 17264 17266

18309 18310 18312 18314 18318 18321 18322 18328 18373 18374 18378 18380

18383 18384 18386 18387 18393 18402 18404 18408 18542 18549 18564 18602

18603 18605 18607 18617 18619 18660 18681 18848 18863 18864 18866 18868

18870 18872 18873 18876 18877 19005 19007 19034 19038 19197 19200 19208

19218 19219 19222 19230 19231 19235 19243 19251 19254 19520 19522 19526
12/09/11 DRAFT

786

19533 19535 19542 19545 19547 19548 19551 19555 19558 19587

Total: 82

Table 9A-16. Our Families

4149 5214 5241 5576 5648 7063 7064 7065 7066 7067 7068 7069

7070 7071 7072 7073 7074 7075 7076 7089 7090 7091 7092 7093

7094 7095 7096 7097 7098 7099 7100 7101 7102 7103 7104 7105

7106 7107 7108 7109 7110 7111 7112 7113 7114 7115 7116 7117

7118 7119 7120 7121 7122 7123 7135 7136 7245 7246 7247 7248

7249 7250 7251 7252 7253 7257 7258 7259 7260 7261 7262 7263

7264 7265 7266 7267 7268 7269 7270 7271 7272 7273 7274 7275

7276 7277 7278 7279 7280 7281 7282 7283 7284 7285 7286 7287

7288 7289 7290 7291 7292 7293 7294 7295 7296 7297 7298 7299

7300 7301 7306 7307 7308 7309 7310 7311 7312 7313 7314 7315

7316 7317 7318 7319 7320 7321 7322 7323 7324 7325 7326 7327

7328 7329 7330 7331 7332 7333 7334 7335 7336 7337 7338 7339

7340 7341 7342 7341 7344 7359 7360 7361 7362 7363 7364 7365

7366 7367 7368 7369 7370 7371 7372 7373 7374 7375 7376 7377

7378 7379 7380 7381 7382 7383 7384 7385 7386 7387 7388 7389

7390 7391 7392 7393 7394 7395 7396 7397 7398 7399 7400 7401

7402 7403 7404 7405 7406 7407 7408 7409 7410 7411 7412 7413

7414 7415 7416 7417 7418 7419 7420 7421 7422 7423 7424 7425

7426 7427 7428 7429 7430 7431 7432 7433 7434 7435 7436 7437

7438 7439 7440 7441 7442 7443 7444 7445 7446 7447 7448 7449

7450 7451 7452 7453 7454 7455 7456 7457 7458 7459 7460 7461

7462 7463 7464 7465 7466 7467 7468 7469 7470 7471 7472 7473

7474 7475 7476 7477 7478 7479 7480 7481 7482 7483 7484 7485

7486 7487 7488 7489 7490 7491 7492 7493 7494 7495 7535 7536

7537 7540 7541 7542 7543 7544 7545 7546 7547 7548 7549 7550

7551 7552 7553 7554 7555 7556 7557 7558 7559 7560 7561 7562

7563 7564 7565 7566 7567 7568 7569 7570 7571 7572 7573 7574

7575 7576 7577 7578 7579 7580 7581 7632 7633 7634 7635 7636

7637 7638 7639 7640 7641 7642 7643 7644 7645 7646 7647 7648

7649 7650 7651 7652 7660 7672 9102 9158 9325 9349 9505 9508

9510 9649 9730 9736 9737 9742 9807 10065 10160 11878 12406 12803

13617

Total: 385

Table 9A-17. Physicians for Social Responsibility

13107 13149 13315 13317 13322 13365 13375 13383 13411 13492 13493 13494

13555 13575 13578 13580 13600 13627 13636 13692 13695 14123 14132 15220

15227 15229 15250 15251 15253 15286 15320 15322 15345 15347 15348 15349
12/09/11 DRAFT

787

15350 15351 15495 15496 15526 15527 15528 15529 15530 15531 15533 15534

15831 16006 16026 16209

Total: 52

Table 9A-18. Salsa Labs

7129 9575 9733 10172 10194 10200 10201 10213 10214 10215 10659 10736

11299 11359 11364 11366 11368 11370 11371 11390 11402 11410 11411 11418

11419 11546 11547 11549 11550 11552 11554 11555 11556 11557 11558 11559

11560 11561 11562 11563 11564 11565 11566 11567 11569 11570 11571 11572

11573 11574 11576 11577 11578 11580 11581 11582 11583 11584 11585 11586

11588 11589 11590 11591 11592 11639 11640 11641 11642 11643 11651 11659

11660 11661 11665 11666 11702 11725 11763 11764 11790 11791 11832 11834

11835 11836 11837 11840 11841 11842 11858 11860 11865 11877 11891 11892

11894 11901 11902 11903 11904 11905 11914 11916 11917 11924 11927 11928

11935 11963 11967 11999 12002 12023 12049 12094 12151 12284 12416 12421

12438 12440 12441 12442 12443 12448 12449 12450 12457 12463 12466 12468

12474 12495 12507 12512 12519 12537 12539 12540 12551 12556 12573 12574

12584 12599 12609 12599 12624 12644 12654 12677 12678 12712 12714 12717

12718 12727 12769 12770 12772 12791 12802 12812 12815 12828 12891 12892

12894 12901 12979 13194 13326 13353 13382 13385 13400 13404 13435 13442

13443 13458 13475 13477 13483 13563 13568 13576 13579 13601 13615 14028

14029 14051 14052 14053 14054 14055 14056 14057 14058 14059 14060 14061

14063 14064 14067 14068 14074 14079 14080 14081 14082 14088 14097 14098

14099 14105 14108 14112 14113 14114 14121 14124 14136 14137 14150 14153

14154 14156 14157 14173 14174 14175 14176 14177 14181 14182 14183 14185

14190 14206 14207 14208 14209 14210 14211 14212 14213 14214 14215 14216

14217 14218 14219 14220 14221 14222 14223 14224 14225 14229 14231 14232

14234 14236 14237 14238 14240 14241 14242 14244 14245 14247 14248 14249

14250 14251 14252 14253 14254 14260 14261 14262 14263 14264 14267 14268

14271 14272 14274 14275 14301 14309 14310 14311 14312 14313 14314 14315

14316 14317 14318 14319 14325 14327 14328 14329 14330 14331 14332 14333

14334 14335 14336 14337 14338 14339 14340 14341 14342 14343 14344 14346

14348 14349 14350 14354 14358 14359 14365 14366 14367 14376 14377 14378

14379 14380 14381 14382 14386 14388 14395 14397 14398 14399 14400 14402

14403 14406 14407 14408 14409 14410 14411 14416 14429 14430 14440 14451

14460 14461 14486 14521 14522 14523 14524 14525 14526 14527 14528 14529

14530 14531 14532 14533 14534 14535 14536 14537 14538 14539 14540 14678

14725 14726 14763 14764 14765 14766 14792 14794 14796 14797 14798 14799

14800 14801 14806 14810 14811 14812 14833 14834 14835 14836 14837 14838

14839 14840 14842 14847 14848 14849 14850 14851 14852 14854 14904 15007

15009 15011 15018 15021 15022 15023 15043 15045 15046 15048 15049 15052

15053 15054 15056 15057 15058 15059 15061 15080 15082 15164 15170 15172

15174 15176 15212 15214 15217 15219 15221 15224 15225 15249 15273 15283
12/09/11 DRAFT

788

15335 15337 15344 15403 15408 15425 15448 15449 15450 15458 15460 15465

15483 15484 15485 15486 15487 15488 15489 15490 15491 15492 15519 15520

15523 15553 15570 15682 15685 15686 15687 15688 15689 15690 15691 15790

15892 15893 15910 15911 15912 15949 16005 16007 16008 16009 16010 16012

16013 16014 16024 16025 16027 16028 16030 16031 16032 16046 16047 16052

16053 16055 16075 16164 16165 16226 16227 16229 16230 16233 16236 16237

16238 16281 16297 16304 16306 16320 16515 16516 16518 16526 16527 16538

16539 16540 16552 16560 16568 16591 17073 17089 17142 17143 17148 17152

17374 17404 18280 18281 18282 18283 18284 18285 18289 18290 18291 18292

18293 18294 18295 18296 18297 18298 18299 18300 18303 18304 18305 18307

18308 18311 18315 18316 18317 18320 18323 18324 18325 18326 18327 18371

18372 18375 18376 18375 18381 18382 18385 18388 18389 18390 18391 18392

18394 18395 18397 18399 18400 18405 18409 18410 18411 18508 18509 18510

18512 18513 18514 18515 18516 18517 18518 18519 18520 18521 18522 18523

18524 18525 18526 18527 18528 18529 18530 18532 18533 18534 18535 18537

18543 18544 18545 18550 18555 18560 18561 18563 18567 18569 18573 18574

18599 18600 18601 18604 18606 18608 18609 18610 18611 18612 18613 18614

18618 18624 18634 18637 18673 18674 18675 18687 18701 18704 18744 18760

18761 18762 18763 18764 18765 18865 18875 18895 18896 18908 18909 18910

18911 18912 18915 18916 18919 18920 18921 18922 18938 18939 18946 18947

18949 18950 18951 18952 18953 18954 18956 18958 18967 18968 18970 19006

19008 19011 19012 19014 19015 19035 19036 19037 19188 19189 19193 19194

19201 19204 19207 19232 19234 19237 19245 19252 19253 19525 19530 19552

19553 19583 19585 19586

Total: 736

Table 9A-19. Sierra Club

3106 3107 3108 3109 3110 3111 3112 3113 3114 3115 3116 3117

3118 3119 3120 3183 3187 3189 3190 3191 3192 3193 3194 3195

3196 3197 3198 3200 3201 3204 3205 3206 3207 3209 3210 3211

3212 3214 3216 3218 3219 3221 3257 3342 3343 3344 3345 3346

3347 3348 3351 3352 3354 3355 3357 3363 3368 3369 3376 3377

3387 3394 3395 3396 3421 3422 3423 3445 3446 3447 3448 3449

3450 3451 3475 3479 3480 3481 3482 3483 3484 3485 3486 3487

3507 3589 3590 3591 3690 3691 3705 3748 3749 3752 3753 3754

3755 3770 3771 3796 3800 3801 3803 3804 3815 3816 3824 3825

3826 3831 3832 3837 3844 3850 3851 3857 3858 3867 3872 3873

3874 3880 3881 3892 3896 3898 3901 3902 3905 3906 3911 3912

3914 3916 3917 3918 3928 3929 3930 3931 3932 3940 4050 4051

4052 4054 4055 4054 4061 4062 4064 4066 4068 4069 4070 4072

4073 4130 4131 4132 4133 4134 4135 4136 4151 4152 4153 4344

4363 4364 4365 4523 4524 4557 4671 4684 4706 4718 4730 4770
12/09/11 DRAFT

789

4771 4772 4773 4774 4775 4776 4777 4778 4779 4780 4781 4782

4790 4791 4792 4793 4794 4799 4800 4801 4802 4803 4805 4806

4807 4813 4814 4815 4816 4817 4828 4829 4830 4831 4832 4833

4834 4835 4836 4837 4838 4839 4840 4841 4842 4843 4844 4845

4846 4847 4848 4849 4850 4851 4852 4853 4854 4855 4856 4857

4858 4859 4860 4861 4862 4863 4864 4865 4866 4867 4868 4869

4870 4871 4872 4873 4874 4875 4876 4877 4878 4879 4880 4881

4882 4883 4884 4885 4886 4887 4888 4889 4890 4891 4892 4893

4894 4895 4896 4897 4898 4899 4900 4901 4902 4903 4904 4905

4906 4907 4908 4909 4910 4911 4912 4913 4914 4915 4916 4917

4918 4919 4929 4934 4935 4936 4937 4938 4939 4940 4941 4943

4944 4945 4946 4947 4948 4949 4950 4951 4952 4953 4954 4955

4956 4957 4958 4960 4961 4962 4963 4964 4965 4966 4967 4968

4969 4970 4974 4975 4976 4977 4978 4979 4980 4981 4987 4988

4989 4990 4991 4992 4996 4997 4998 5008 5009 5010 5011 5012

5013 5015 5017 5018 5032 5033 5034 5035 5036 5037 5038 5039

5040 5041 5043 5044 5045 5046 5047 5048 5049 5050 5051 5052

5055 5058 5059 5060 5061 5062 5063 5064 5066 5067 5069 5070

5071 5072 5073 5074 5075 5079 5080 5081 5083 5088 5089 5090

5091 5092 5093 5094 5095 5096 5099 5100 5101 5109 5110 5111

5112 5113 5114 5115 5116 5117 5118 5119 5121 5123 5124 5126

5127 5128 5129 5130 5131 5132 5133 5134 5135 5136 5137 5139

5147 5148 5149 5150 5151 5152 5153 5154 5155 5156 5157 5160

5161 5164 5165 5166 5167 5168 5169 5170 5171 5172 5173 5177

5178 5179 5180 5181 5185 5186 5187 5188 5189 5194 5195 5197

5198 5199 5200 5201 5202 5208 5209 5210 5211 5213 5217 5218

5219 5220 5221 5222 5223 5224 5225 5226 5227 5228 5229 5230

5231 5232 5233 5234 5235 5236 5237 5238 5239 5240 5249 5250

5251 5252 5253 5254 5255 5256 5257 5258 5259 5260 5261 5262

5263 5270 5271 5272 5273 5274 5275 5276 5277 5278 5279 5283

5284 5285 5287 5288 5289 5290 5291 5292 5293 5296 5297 5298

5299 5300 5301 5302 5306 5307 5308 5309 5310 5311 5312 5313

5314 5315 5316 5322 5323 5324 5325 5326 5327 5328 5332 5333

5334 5335 5336 5337 5338 5339 5340 5341 5342 5343 5344 5347

5357 5358 5359 5358 5361 5362 5363 5364 5365 5366 5367 5368

5370 5371 5372 5373 5374 5375 5376 5377 5378 5379 5380 5381

5382 5383 5384 5385 5386 5387 5388 5389 5390 5391 5392 5393

5394 5395 5396 5397 5398 5399 5400 5401 5402 5403 5404 5405

5406 5407 5408 5409 5410 5411 5412 5417 5418 5419 5420 5421

5422 5423 5424 5425 5426 5427 5461 5462 5463 5464 5466 5467

5468 5471 5472 5473 5474 5475 5476 5477 5478 5479 5480 5481

5482 5483 5484 5485 5486 5487 5488 5489 5490 5491 5492 5493
12/09/11 DRAFT

790

5494 5495 5496 5497 5498 5499 5500 5501 5502 5503 5504 5505

5506 5507 5508 5509 5510 5511 5512 5513 5514 5515 5516 5519

5520 5521 5522 5523 5524 5525 5526 5527 5528 5529 5530 5531

5532 5533 5534 5535 5536 5537 5538 5539 5540 5541 5542 5543

5544 5545 5546 5547 5548 5549 5550 5551 5552 5553 5554 5555

5556 5557 5558 5561 5563 5564 5565 5566 5567 5568 5569 5570

5571 5572 5573 5574 5575 5577 5578 5579 5580 5581 5582 5583

5584 5585 5586 5587 5588 5589 5590 5591 5592 5593 5594 5595

5596 5597 5598 5599 5600 5601 5602 5603 5604 5605 5606 5607

5608 5609 5610 5611 5612 5613 5614 5615 5616 5617 5618 5619

5620 5621 5622 5623 5624 5625 5626 5627 5628 5629 5630 5631

5632 5633 5634 5635 5636 5637 5638 5639 5640 5641 5642 5643

5644 5645 5646 5647 5649 5650 5651 5652 5653 5654 5655 5656

5657 5658 5659 5660 5661 5662 5663 5664 5665 5666 5667 5668

5669 5670 5671 5672 5673 5674 5675 5676 5677 5678 5679 5680

5681 5682 5683 5684 5685 5686 5687 5688 5689 5690 5692 5693

5694 5695 5696 5697 5698 5699 5700 5714 5715 5716 5717 5718

5719 5720 5721 5722 5723 5724 5725 5726 5727 5728 5729 5730

5731 5732 5733 5734 5735 5736 5737 5738 5739 5740 5741 5742

5743 5744 5745 5746 5747 5748 5749 5754 5755 5756 5757 5758

5759 5760 5761 5762 5763 5764 5765 5766 5767 5768 5769 5770

5771 5772 5773 5774 5775 5776 5777 5778 5779 5780 5781 5782

5783 5784 5785 5786 5787 5788 5789 5790 5791 5792 5793 5794

5795 5796 5797 5798 5799 5800 5801 5802 5803 5804 5805 5806

5807 5808 5809 5810 5811 5812 5813 5816 5817 5818 5819 5821

5822 5823 5824 5825 5826 5827 5828 5829 5830 5831 5832 5833

5834 5835 5836 5837 5841 5842 5843 5844 5845 5846 5849 5850

5851 5853 5862 5863 5864 5865 5866 5867 5868 5869 5870 5871

5872 5873 5874 5875 5876 5877 5878 5879 5880 5881 5882 5883

5884 5885 5886 5885 5888 5889 5890 5891 5892 5893 5894 5895

5896 5897 5898 5899 5900 5901 5902 5903 5904 5905 5906 5907

5908 5909 5910 5912 5914 5915 5916 5917 5918 5919 5920 5921

5922 5923 5924 5925 5926 5927 5928 5929 5930 5931 5932 5933

5934 5935 5936 5937 5938 5939 5940 5941 5942 5943 5944 5945

5946 5947 5948 5949 5950 5951 5952 5953 5954 5955 5956 5957

5958 5959 5960 5961 5962 5963 5964 5965 5966 5967 5968 5969

5970 5971 5972 5973 5974 5975 5976 5977 5978 5979 5980 5981

5982 5983 5984 5985 5986 5987 5988 5989 5990 5991 5992 5993

5994 5995 5996 5997 5998 5999 6000 6001 6002 6003 6004 6005

6006 6007 6009 6010 6011 6012 6013 6014 6015 6016 6017 6018

6019 6020 6021 6022 6023 6024 6025 6026 6027 6028 6029 6030

6031 6032 6033 6034 6035 6036 6037 6038 6039 6040 6041 6042
12/09/11 DRAFT

791

6043 6044 6045 6046 6047 6048 6049 6050 6051 6052 6053 6055

6056 6057 6058 6059 6060 6061 6062 6063 6064 6065 6066 6067

6068 6069 6070 6071 6072 6073 6074 6075 6076 6077 6078 6079

6080 6081 6082 6083 6084 6085 6086 6087 6088 6089 6090 6091

6092 6093 6094 6095 6096 6097 6098 6099 6100 6101 6102 6103

6104 6105 6106 6107 6108 6109 6110 6111 6641 6642 6643 6644

6645 6646 6647 6648 6649 6650 6651 6652 6653 6654 6655 6656

6657 6658 6659 6660 6661 6662 6663 7124 7125 7126 7127 7128

7130 7131 7132 7133 7134 7137 7138 7139 7140 7141 7142 7143

7144 7145 7146 7147 7148 7149 7150 7151 7152 7153 7154 7155

7156 7157 7158 7159 7160 7161 7162 7163 7164 7165 7166 7167

7168 7169 7170 7171 7172 7173 7174 7175 7176 7177 7178 7179

7180 7181 7182 7183 7184 7185 7186 7187 7188 7189 7190 7191

7192 7193 7194 7195 7196 7197 7345 7589 7590 7591 7592 7593

7594 7595 7596 7597 7598 7599 7600 7601 7602 7603 7604 7605

7606 7607 7608 7609 7610 7611 7612 7613 7614 7615 7616 7617

7618 7619 7620 7621 7622 7623 7624 7625 7626 7627 7628 7629

7630 7631 7656 7657 7676 7677 7678 7679 7680 7681 7682 7683

7684 7685 7686 7687 7688 7689 7690 7691 7692 7693 7694 7695

7696 7697 7698 7699 7700 7701 7702 7703 7704 7705 7706 7707

7708 7709 7710 7711 7712 7713 7714 7715 7716 7717 7718 7719

7720 7721 7722 7723 7724 7725 7726 7727 7728 7729 7730 7731

7732 7733 7734 7735 7736 7737 7738 7739 7740 7741 7742 7743

7744 7745 7746 7748 7749 7750 7751 7752 7753 7754 7755 7756

7757 7758 7759 7758 7761 7762 7763 7764 7765 7766 7767 7768

7769 7770 7771 7772 7773 7774 7775 7776 7777 7778 7779 7780

7781 7782 7783 7784 7785 7786 7787 7788 7789 7790 7791 7792

7793 7794 7795 7796 7797 7798 7799 7800 7801 7802 7803 7804

7805 7806 7807 7808 7809 7810 7811 7812 7813 7814 7815 7816

7817 7818 7819 7820 7821 7822 7823 7824 7825 7826 7827 7829

7830 7831 7832 7833 7834 7835 7836 7837 7838 7839 7840 7841

7842 7843 7844 7845 7846 7847 7848 7849 7850 7851 7852 7853

7854 7855 7856 7857 7858 7860 7861 7862 7863 7864 7865 7866

7867 7868 7869 7870 7871 7872 7873 7874 7875 7876 7877 7878

7879 7880 7881 7882 7883 7884 7885 7886 7887 7888 7889 7890

7891 7892 7893 7894 7895 7896 7897 7898 7899 7900 7901 7902

7903 7904 7905 7906 7907 7908 7909 7910 7911 7912 7913 7914

7915 7916 7917 7918 7919 7920 7921 7922 7923 7924 7925 7926

7927 7928 7929 7930 7931 7932 7933 7934 7935 7936 7937 7938

7939 7940 7941 7942 7943 7944 7945 7946 7947 7948 7949 7950

7951 7952 7953 7954 7955 7956 7957 7958 7959 7960 7961 7962

7963 7964 7965 7966 7967 7968 7969 7970 7971 7972 7973 7974
12/09/11 DRAFT

792

7976 7977 7978 7979 7980 7981 7982 7983 7984 7985 7986 7988

7989 7990 7991 7992 7993 7994 7995 7996 7997 7998 7999 8000

8001 8002 8003 8004 8005 8006 8007 8008 8009 8010 8011 8012

8013 8014 8015 8016 8017 8018 8019 8020 8021 8022 8023 8024

8025 8026 8027 8028 8029 8030 8031 8032 8033 8034 8035 8036

8037 8038 8039 8040 8041 8042 8043 8044 8045 8046 8047 8048

8049 8050 8051 8052 8053 8054 8055 8056 8057 8058 8059 8060

8061 8062 8063 8064 8065 8066 8067 8068 8069 8070 8071 8072

8073 8074 8075 8076 8077 8078 8079 8080 8081 8082 8083 8084

8085 8086 8087 8088 8089 8090 8091 8092 8093 8094 8095 8096

8097 8098 8099 8100 8101 8102 8103 8104 8105 8106 8107 8108

8109 8110 8111 8112 8113 8114 8115 8116 8117 8118 8119 8120

8121 8122 8123 8124 8125 8126 8127 8128 8129 8130 8131 8132

8133 8134 8135 8136 8137 8138 8139 8140 8141 8142 8143 8144

8145 8146 8147 8148 8149 8150 8151 8152 8153 8154 8155 8156

8157 8158 8159 8160 8161 8162 8163 8164 8165 8166 8167 8168

8169 8170 8171 8172 8173 8174 8175 8176 8177 8178 8179 8180

8181 8182 8183 8184 8185 8186 8187 8188 8189 8190 8191 8192

8193 8194 8195 8196 8197 8198 8199 8200 8201 8202 8203 8204

8205 8206 8207 8206 8209 8210 8211 8212 8213 8214 8215 8216

8217 8218 8219 8220 8221 8222 8223 8224 8225 8226 8227 8228

8229 8230 8231 8232 8233 8234 8235 8236 8237 8238 8239 8240

8241 8242 8243 8244 8245 8246 8247 8248 8249 8250 8251 8252

8253 8254 8255 8258 8259 8260 8261 8262 8263 8264 8265 8266

8267 8268 8269 8270 8271 8272 8273 8274 8275 8276 8277 8278

8279 8280 8281 8282 8283 8284 8285 8286 8288 8289 8290 8291

8292 8293 8294 8295 8296 8297 8298 8299 8302 8303 8304 8305

8306 8307 8308 8309 8310 8311 8312 8313 8314 8315 8316 8317

8318 8319 8320 8321 8322 8323 8324 8325 8326 8327 8328 8329

8330 8331 8332 8333 8334 8335 8336 8337 8338 8339 8340 8341

8342 8343 8344 8345 8346 8347 8348 8349 8350 8351 8352 8353

8354 8355 8356 8357 8358 8359 8360 8361 8362 8363 8364 8365

8366 8367 8368 8369 8370 8371 8372 8373 8374 8375 8376 8377

8378 8379 8380 8381 8382 8383 8384 8385 8386 8387 8388 8389

8390 8391 8392 8393 8394 8395 8396 8397 8398 8399 8400 8401

8402 8403 8404 8405 8406 8407 8408 8409 8410 8411 8412 8413

8414 8415 8416 8417 8418 8419 8420 8421 8422 8423 8424 8425

8426 8427 8428 8429 8430 8431 8432 8433 8435 8436 8437 8438

8439 8440 8441 8442 8444 8445 8446 8447 8448 8449 8450 8451

8452 8453 8454 8455 8456 8457 8458 8459 8460 8461 8462 8463

8464 8465 8466 8467 8468 8469 8470 8471 8472 8473 8474 8475

8476 8477 8478 8479 8480 8481 8482 8483 8484 8485 8486 8487
12/09/11 DRAFT

793

8488 8489 8490 8491 8492 8493 8494 8495 8496 8497 8498 8499

8500 8501 8502 8503 8504 8505 8506 8507 8508 8509 8510 8511

8512 8513 8514 8515 8516 8517 8518 8519 8522 8523 8524 8525

8526 8527 8528 8529 8530 8531 8532 8533 8534 8535 8536 8537

8538 8539 8540 8541 8542 8543 8544 8545 8546 8547 8548 8549

8550 8551 8552 8553 8554 8555 8556 8557 8558 8559 8560 8561

8562 8563 8564 8565 8566 8567 8568 8569 8570 8571 8572 8573

8574 8575 8576 8577 8578 8589 8590 8591 8592 8593 8594 8595

8596 8597 8598 8599 8600 8601 8602 8603 8604 8605 8606 8607

8608 8609 8610 8611 8612 8613 8614 8615 8616 8617 8618 8619

8620 8621 8622 8623 8624 8625 8626 8627 8628 8629 8630 8631

8632 8633 8634 8635 8636 8637 8638 8639 8640 8641 8642 8643

8644 8645 8646 8647 8648 8649 8650 8651 8652 8653 8654 8655

8656 8657 8658 8659 8660 8661 8662 8663 8664 8665 8666 8667

8668 8669 8670 8669 8672 8673 8674 8675 8676 8677 8678 8679

8680 8681 8682 8683 8685 8686 8687 8688 8689 8690 8691 8692

8693 8694 8695 8696 8697 8698 8699 8700 8701 8702 8703 8704

8705 8706 8707 8708 8709 8710 8711 8712 8713 8714 8715 8716

8717 8718 8719 8720 8721 8722 8723 8724 8725 8726 8727 8728

8729 8730 8731 8732 8733 8734 8735 8736 8737 8738 8739 8740

8741 8742 8743 8744 8745 8746 8747 8748 8749 8750 8751 8752

8753 8754 8755 8756 8757 8758 8759 8760 8761 8762 8763 8764

8765 8766 8767 8768 8769 8770 8771 8772 8773 8774 8775 8776

8777 8778 8779 8780 8781 8782 8783 8784 8785 8786 8787 8788

8789 8790 8791 8792 8793 8794 8795 8796 8797 8798 8799 8800

8801 8802 8803 8804 8805 8806 8807 8808 8809 8810 8811 8812

8813 8814 8815 8816 8817 8818 8819 8820 8821 8822 8823 8824

8825 8826 8827 8828 8829 8830 8831 8832 8833 8834 8835 8836

8837 8838 8839 8840 8841 8842 8843 8844 8845 8846 8847 8848

8849 8850 8851 8852 8853 8854 8855 8856 8857 8858 8859 8860

8861 8862 8863 8864 8865 8866 8867 8868 8869 8870 8871 8880

8881 8882 8883 8884 8885 8886 8887 8888 8889 8890 8891 8892

8893 8894 8895 8896 8897 8898 8899 8900 8901 8902 8903 8904

8905 8906 8907 8908 8909 8910 8911 8912 8913 8914 8915 8916

8917 8918 8919 8920 8921 8922 8923 8924 8925 8926 8927 8928

8929 8930 8931 8932 8933 8934 8935 8936 8937 8938 8939 8940

8941 8942 8943 8944 8945 8946 8947 8948 8949 8950 8951 8952

8953 8954 8955 8956 8957 8959 8960 8962 8963 8964 8965 8966

8967 8968 8969 8970 8971 8972 8973 8974 8975 8976 8977 8978

8979 8980 8981 8982 8983 8984 8985 8986 8987 8988 8989 8990

8991 8992 8993 8994 8995 8996 8997 8998 8999 9000 9001 9002

9003 9004 9005 9006 9007 9008 9009 9010 9011 9012 9013 9014
12/09/11 DRAFT

794

9015 9016 9017 9018 9019 9020 9021 9023 9024 9025 9026 9027

9028 9029 9030 9031 9032 9033 9034 9035 9036 9037 9038 9039

9040 9041 9042 9043 9044 9045 9046 9047 9048 9049 9050 9051

9052 9053 9054 9055 9056 9057 9058 9059 9060 9061 9062 9063

9064 9065 9066 9067 9068 9069 9070 9071 9073 9074 9075 9076

9077 9078 9079 9080 9081 9082 9083 9084 9085 9086 9087 9088

9089 9090 9091 9092 9093 9094 9095 9096 9097 9098 9099 9100

9101 9103 9104 9105 9106 9107 9108 9109 9110 9111 9113 9114

9115 9116 9117 9119 9120 9121 9122 9123 9124 9125 9126 9127

9128 9129 9130 9129 9132 9133 9134 9135 9136 9137 9138 9139

9140 9141 9142 9143 9144 9145 9146 9147 9148 9149 9150 9151

9152 9153 9155 9156 9157 9160 9161 9162 9163 9164 9165 9166

9167 9168 9169 9170 9171 9173 9218 9219 9220 9286 9287 9288

9289 9290 9291 9292 9293 9294 9295 9296 9297 9345 9347 9348

9350 9351 9352 9353 9354 9355 9356 9357 9358 9359 9360 9361

9362 9363 9364 9365 9366 9367 9368 9369 9370 9371 9372 9373

9374 9375 9377 9378 9379 9380 9381 9383 9384 9385 9386 9387

9388 9389 9390 9391 9392 9393 9394 9395 9396 9397 9398 9399

9400 9401 9402 9403 9404 9405 9406 9407 9408 9409 9410 9411

9412 9413 9414 9415 9416 9417 9418 9419 9420 9421 9422 9423

9424 9425 9426 9427 9428 9429 9448 9466 9467 9468 9484 9497

9499 9507 9509 9512 9514 9523 9616 9728 9729 9731 9734 9735

9739 9740 9741 9745 9746 9747 9748 9750 9751 9752 9753 9771

9772 9773 9774 9775 9776 9777 9778 9779 9780 9781 9782 9783

9784 9785 9786 9787 9788 9789 9791 9792 9793 9794 9795 9796

9797 9798 9799 9800 9801 9802 9803 9804 9850 9851 9852 9853

9856 9857 9861 9865 9905 9906 9908 9910 9911 9912 9913 9914

9915 9916 9917 9918 9922 9923 9924 9925 9926 9927 9928 9929

9930 9935 9936 9937 9938 9945 9948 9949 9950 9952 9954 9955

9956 9957 9960 9961 10030 10031 10032 10033 10034 10035 10036 10037

10038 10039 10040 10042 10043 10044 10045 10046 10047 10048 10049 10050

10051 10052 10053 10054 10055 10056 10057 10058 10059 10060 10061 10062

10063 10064 10066 10067 10068 10069 10070 10071 10072 10073 10074 10075

10076 10077 10078 10079 10080 10081 10082 10083 10084 10085 10086 10087

10088 10089 10090 10091 10092 10093 10094 10095 10096 10097 10098 10101

10102 10103 10105 10107 10108 10111 10112 10113 10123 10124 10127 10129

10130 10131 10132 10133 10134 10135 10136 10137 10138 10139 10140 10141

10142 10143 10144 10145 10146 10147 10148 10149 10150 10151 10152 10153

10154 10155 10156 10157 10158 10159 10161 10162 10163 10164 10168 10171

10173 10174 10175 10176 10177 10178 10179 10180 10181 10183 10184 10185

10186 10187 10188 10189 10190 10191 10192 10193 10195 10196 10197 10198

10199 10202 10203 10204 10205 10206 10207 10208 10209 10210 10211 10212
12/09/11 DRAFT

795

10216 10217 10218 10219 10220 10221 10222 10223 10224 10225 10226 10227

10228 10229 10230 10231 10232 10233 10234 10235 10236 10237 10238 10239

10240 10241 10242 10243 10244 10245 10246 10247 10248 10249 10250 10251

10252 10253 10254 10255 10256 10257 10258 10259 10260 10261 10262 10263

10264 10265 10266 10265 10268 10269 10270 10271 10272 10273 10274 10275

10276 10277 10278 10279 10280 10281 10282 10283 10284 10285 10286 10287

10288 10289 10290 10291 10292 10293 10294 10295 10296 10297 10298 10299

10300 10301 10302 10303 10304 10305 10306 10307 10308 10309 10310 10311

10312 10313 10314 10315 10316 10317 10318 10319 10320 10321 10322 10323

10324 10325 10326 10327 10328 10329 10330 10331 10332 10333 10334 10335

10336 10337 10338 10339 10340 10341 10342 10343 10344 10345 10346 10347

10348 10349 10350 10351 10352 10353 10354 10355 10356 10357 10358 10359

10360 10361 10362 10363 10364 10365 10366 10367 10368 10369 10370 10371

10372 10373 10374 10375 10376 10377 10378 10379 10380 10381 10382 10383

10384 10385 10386 10387 10388 10389 10390 10391 10392 10393 10394 10395

10396 10397 10398 10399 10400 10401 10402 10403 10404 10405 10406 10407

10408 10409 10410 10411 10412 10413 10414 10415 10416 10417 10418 10419

10420 10421 10422 10423 10424 10425 10426 10427 10428 10429 10430 10431

10432 10433 10434 10435 10436 10437 10438 10439 10440 10441 10442 10443

10444 10445 10446 10447 10448 10449 10450 10451 10452 10453 10454 10455

10456 10457 10458 10459 10460 10461 10462 10463 10464 10465 10466 10467

10468 10469 10470 10471 10472 10473 10474 10475 10476 10477 10478 10479

10480 10481 10482 10483 10484 10485 10486 10487 10488 10489 10490 10491

10492 10493 10494 10495 10496 10497 10498 10499 10500 10501 10502 10503

10504 10505 10506 10507 10508 10509 10510 10511 10512 10513 10514 10515

10516 10517 10518 10519 10520 10523 10524 10525 10526 10527 10528 10529

10530 10531 10532 10533 10534 10535 10536 10537 10538 10539 10540 10541

10542 10543 10544 10545 10546 10547 10548 10549 10550 10551 10552 10553

10554 10555 10556 10557 10558 10559 10560 10561 10562 10563 10564 10565

10566 10567 10568 10570 10571 10572 10573 10574 10575 10576 10577 10578

10579 10580 10581 10582 10583 10584 10585 10586 10587 10588 10589 10590

10591 10592 10593 10594 10595 10596 10597 10598 10599 10600 10601 10602

10603 10604 10605 10606 10607 10608 10609 10611 10612 10613 10614 10615

10616 10617 10618 10619 10620 10621 10622 10624 10625 10626 10627 10628

10629 10630 10631 10632 10633 10634 10635 10636 10638 10639 10640 10641

10642 10643 10644 10645 10647 10648 10649 10650 10652 10653 10654 10655

10656 10657 10658 10661 10662 10663 10664 10665 10666 10667 10668 10669

10670 10671 10672 10673 10674 10675 10676 10677 10678 10679 10680 10681

10682 10683 10684 10685 10686 10687 10688 10689 10690 10691 10692 10693

10694 10695 10696 10697 10698 10699 10700 10701 10702 10703 10704 10705

10706 10707 10708 10709 10710 10711 10712 10713 10714 10715 10716 10717

10718 10719 10720 10719 10722 10723 10724 10725 10726 10727 10728 10730
12/09/11 DRAFT

796

10731 10733 10735 10737 10738 10739 10740 10741 10742 10743 10744 10745

10746 10747 10748 10749 10751 10752 10753 10754 10755 10756 10759 10760

10761 10763 10764 10765 10768 10769 10770 10771 10772 10773 10774 10775

10776 10777 10778 10779 10780 10781 10782 10783 10784 10785 10786 10787

10788 10789 10790 10791 10792 10793 10794 10795 10796 10797 10798 10799

10800 10801 10802 10803 10804 10805 10806 10807 10808 10809 10810 10812

10814 10815 10816 10817 10818 10819 10820 10823 10824 10825 10826 10829

10830 10831 10832 10833 10834 10835 10836 10837 10838 10839 10840 10841

10842 10843 10844 10845 10846 10863 10864 10865 10866 10867 10868 10914

11082 11083 11084 11085 11086 11087 11282 11283 11284 11289 11290 11291

11292 11293 11294 11295 11296 11297 11300 11301 11302 11303 11304 11305

11306 11307 11308 11309 11310 11311 11312 11313 11315 11316 11317 11318

11319 11320 11321 11322 11323 11324 11325 11326 11327 11328 11329 11330

11331 11332 11333 11334 11335 11336 11337 11338 11339 11340 11341 11342

11343 11344 11345 11346 11347 11348 11349 11350 11353 11354 11355 11356

11357 11358 11360 11361 11362 11363 11365 11367 11369 11372 11375 11376

11381 11385 11397 11398 11399 11400 11405 11406 11407 11408 11409 11412

11420 11428 11429 11430 11431 11432 11433 11434 11435 11436 11437 11438

11449 11450 11451 11452 11453 11454 11455 11456 11457 11458 11459 11460

11461 11462 11463 11464 11465 11466 11467 11468 11469 11470 11471 11472

11473 11474 11475 11476 11478 11479 11480 11481 11482 11483 11484 11485

11486 11487 11488 11489 11490 11491 11492 11493 11494 11495 11496 11497

11498 11499 11500 11501 11502 11503 11504 11505 11506 11507 11508 11509

11510 11511 11512 11513 11514 11515 11516 11517 11518 11519 11520 11521

11522 11523 11524 11525 11526 11527 11537 11538 11539 11540 11541 11542

11543 11544 11545 11548 11551 11553 11568 11575 11579 11587 11593 11594

11595 11604 11621 11625 11629 11631 11632 11637 11638 11646 11649 11650

11652 11657 11658 11662 11663 11664 11668 11696 11697 11698 11699 11700

11701 11704 11705 11713 11714 11715 11716 11717 11718 11719 11720 11721

11722 11723 11724 11726 11727 11729 11730 11731 11732 11733 11734 11735

11736 11737 11738 11739 11740 11741 11742 11743 11744 11745 11746 11747

11748 11749 11750 11751 11752 11753 11754 11755 11756 11758 11759 11760

11761 11762 11765 11766 11773 11774 11775 11776 11777 11778 11779 11780

11781 11786 11787 11788 11789 11796 11797 11798 11799 11800 11817 11818

11819 11820 11821 11822 11823 11824 11825 11826 11827 11828 11829 11830

11831 11833 11838 11839 11843 11845 11859 11861 11866 11875 11880 11895

11925 11926 11929 11926 11934 11936 11937 11938 11939 11950 11956 11957

11958 11959 11960 11961 11962 11964 11965 11966 11968 11995 12005 12006

12010 12015 12016 12017 12018 12019 12020 12021 12034 12044 12052 12057

12058 12063 12064 12069 12070 12071 12074 12075 12076 12081 12082 12088

12089 12092 12096 12097 12098 12123 12124 12125 12126 12127 12130 12145

12146 12147 12149 12150 12153 12154 12170 12172 12201 12202 12229 12233
12/09/11 DRAFT

797

12239 12240 12242 12243 12244 12245 12246 12247 12248 12249 12250 12251

12263 12266 12279 12280 12282 12385 12386 12387 12388 12389 12390 12391

12392 12393 12394 12395 12396 12397 12398 12399 12400 12401 12403 12404

12407 12408 12410 12412 12413 12414 12415 12419 12420 12422 12423 12424

12426 12427 12428 12429 12432 12433 12434 12435 12436 12437 12444 12445

12446 12447 12451 12452 12453 12454 12455 12456 12458 12465 12469 12470

12471 12472 12473 12475 12476 12477 12478 12479 12480 12481 12482 12483

12484 12485 12486 12487 12488 12489 12490 12491 12492 12493 12494 12496

12497 12498 12499 12500 12501 12502 12514 12515 12516 12517 12522 12523

12524 12527 12528 12529 12530 12531 12538 12541 12542 12543 12544 12545

12549 12550 12552 12553 12554 12555 12557 12558 12559 12575 12576 12577

12578 12579 12580 12581 12582 12583 12585 12586 12587 12588 12590 12591

12592 12593 12594 12595 12596 12597 12598 12600 12601 12602 12603 12604

12605 12606 12607 12608 12610 12611 12612 12613 12614 12616 12623 12631

12632 12633 12634 12635 12636 12637 12638 12640 12641 12642 12643 12646

12647 12655 12656 12657 12658 12659 12660 12666 12667 12668 12669 12670

12671 12672 12680 12681 12688 12689 12690 12691 12692 12693 12694 12695

12696 12697 12698 12699 12700 12701 12702 12703 12713 12721 12726 12728

12729 12730 12731 12732 12733 12734 12735 12736 12737 12738 12739 12740

12741 12742 12743 12744 12745 12746 12747 12748 12749 12750 12751 12752

12753 12754 12771 12773 12774 12775 12776 12777 12778 12779 12781 12782

12783 12784 12785 12786 12787 12788 12789 12790 12792 12804 12805 12806

12808 12809 12810 12811 12813 12817 12818 12819 12820 12821 12822 12823

12824 12825 12826 12827 12829 12830 12831 12832 12833 12834 12835 12837

12838 12839 12840 12841 12842 12843 12844 12845 12846 12847 12848 12849

12850 12851 12852 12853 12854 12855 12856 12857 12858 12859 12860 12861

12862 12863 12864 12865 12866 12867 12868 12869 12870 12871 12872 12873

12874 12876 12877 12878 12879 12880 12882 12883 12884 12885 12893 12895

12897 12898 12899 12900 12902 12903 12904 12905 12906 12907 12908 12909

12910 12911 12912 12913 12914 12915 12916 12917 12918 12919 12920 12921

12922 12923 12924 12925 12926 12927 12928 12929 12930 12931 12932 12933

12934 12935 12936 12935 12938 12939 12940 12941 12942 12943 12944 12945

12946 12947 12972 12973 12974 12975 12978 12980 12981 12982 12983 12984

12985 12986 12990 12993 12997 12998 12999 13000 13001 13002 13003 13004

13009 13011 13012 13013 13014 13015 13016 13017 13018 13019 13020 13021

13022 13023 13024 13025 13026 13027 13028 13030 13031 13032 13033 13034

13035 13036 13037 13038 13039 13040 13041 13042 13043 13044 13045 13046

13047 13048 13049 13050 13051 13053 13054 13057 13058 13064 13065 13066

13067 13068 13069 13070 13071 13072 13073 13074 13075 13076 13077 13078

13079 13080 13081 13082 13083 13086 13087 13088 13094 13095 13096 13098

13102 13103 13104 13108 13111 13113 13114 13115 13116 13123 13124 13125

13129 13130 13135 13136 13142 13143 13144 13145 13146 13147 13155 13156
12/09/11 DRAFT

798

13157 13158 13160 13161 13162 13173 13174 13175 13176 13177 13219 13220

13221 13222 13223 13224 13225 13231 13232 13233 13245 13246 13247 13248

13249 13254 13260 13261 13262 13263 13274 13275 13277 13278 13279 13280

13281 13282 13283 13284 13285 13286 13287 13288 13289 13290 13291 13292

13293 13294 13295 13296 13297 13298 13316 13318 13319 13320 13321 13323

13324 13327 13328 13329 13330 13333 13334 13335 13338 13339 13340 13341

13342 13343 13344 13345 13346 13358 13363 13364 13380 13381 13403 13405

13409 13410 13422 13423 13424 13425 13426 13436 13437 13438 13439 13440

13441 13467 13470 13471 13473 13474 13476 13481 13482 13484 13485 13486

13487 13488 13489 13490 13491 13499 13500 13501 13502 13503 13504 13505

13506 13507 13516 13535 13542 13543 13565 13567 13571 13574 13577 13581

13582 13583 13584 13585 13586 13587 13588 13602 13607 13608 13610 13616

13618 13625 13626 13628 13633 13634 13637 13638 13641 13642 13643 13689

13795 14018 14021 14024 14026 14030 14031 14032 14048 14049 14062 14078

14083 14084 14089 14090 14103 14104 14111 14120 14125 14131 14143 14147

14151 14155 14158 14159 14161 14162 14163 14167 14169 14172 14184 14188

14189 14196 14197 14198 14199 14200 14203 14204 14226 14390 14391 14392

14393 14404 14405 14762 14795 15008 15015 15024 15051 15081 15180 15210

15274 15282 15332 15338 15536 15556 15894 16001 16029 16128 16129 16131

16132 16133 16134 16135 16136 16147 16148 16150 16151 16153 16155 16156

16157 16158 16210 16211 16216 16235 16283 16298 16299 16303 16322 16345

16514 16520 16521 16523 16524 16590 17072 17074 17083 17084 17085 17087

17088 17141 18553 18562 18570 18572 18700 19523 19524 19528 19532 19534

19543 19546 19557 19563 19570 19571 19572 19613 19636 19637 19638 19639

19640 19641 19642 19663 19664 19665 19672 19673 19674 19675

Total: 5,014

Table 9A-20. Union of Concerned Scientists

3121 3122 3123 3124 3125 3126 3127 3128 3129 3130 3131 3132

3133 3134 3135 3136 3137 3161 3162 3163 3164 3165 3166 3167

3168 3169 3170 3171 3172 3173 3174 3175 3176 3177 3178 3179

3180 3181 3182 3184 3185 3186 3199 3202 3203 3208 3213 3215

3217 3220 3222 3225 3226 3227 3228 3229 3230 3231 3232 3233

3234 3235 3236 3237 3238 3239 3240 3241 3242 3243 3244 3245

3271 3272 3273 3274 3310 3311 3312 3313 3314 3332 3333 3337

3338 3339 3340 3341 3349 3350 3353 3356 3359 3360 3362 3365

3370 3382 3386 3388 3391 3424 3425 3426 3427 3428 3429 3430

3431 3432 3433 3434 3435 3452 3453 3462 3463 3464 3465 3466

3467 3468 3469 3470 3471 3472 3473 3474 3476 3477 3478 3488

3489 3490 3491 3492 3493 3508 3509 3511 3514 3520 3521 3522

3523 3524 3525 3524 3527 3528 3529 3530 3531 3532 3533 3534

3535 3536 3537 3538 3539 3540 3541 3542 3543 3544 3545 3546
12/09/11 DRAFT

799

3547 3548 3559 3560 3561 3562 3563 3564 3565 3566 3568 3588

3750 3751 3772 3797 3798 3799 3802 3845 3846 3859 3865 3866

3887 3888 3889 3891 3897 3903 3904 3909 3910 3913 3915 3919

3920 3926 3927 3933 3934 3935 3936 3937 3948 4053 4057 4058

4059 4060 4063 4065 4067 4071 4150 4342 4343 4673 4677 4685

4686 4687 4705 4930 4972 4973 4984 4985 4986 4994 4995 5016

5086 5087 5105 5106 5107 5108 5125 5143 5144 5145 5162 5196

5215 5248 5814 5815 5820 5838 5839 5840 5848 5858 5859 5860

5861 6008 6054 7987 9174 9175 9176 9177 9178 9179 9180 9181

9182 9183 9184 9185 9186 9187 9188 9189 9190 9191 9192 9193

9194 9195 9196 9197 9198 9199 9200 9201 9202 9203 9204 9205

9206 9207 9208 9209 9210 9211 9212 9213 9214 9215 9216 9217

9221 9222 9223 9224 9225 9226 9227 9228 9229 9230 9231 9232

9233 9234 9235 9236 9237 9238 9239 9240 9241 9242 9243 9244

9245 9246 9247 9248 9249 9250 9251 9252 9253 9254 9255 9256

9257 9258 9259 9260 9261 9262 9263 9264 9265 9266 9267 9277

9278 9279 9280 9281 9282 9283 9284 9285 9298 9299 9300 9301

9302 9303 9304 9305 9306 9307 9308 9309 9310 9311 9312 9313

9314 9315 9316 9317 9318 9319 9320 9321 9322 9323 9324 9326

9327 9328 9329 9330 9331 9332 9333 9334 9335 9336 9337 9338

9339 9340 9341 9342 9343 9344 9346 9430 9431 9432 9433 9434

9435 9436 9437 9438 9439 9440 9441 9442 9443 9444 9445 9446

9447 9449 9450 9451 9452 9453 9454 9455 9456 9457 9458 9459

9495 9496 9498 9500 9501 9502 9503 9504 9506 9511 9513 9515

9516 9517 9615 9665 9700 9715 9732 9744 9749 9754 9755 9756

9757 9758 9759 9760 9761 9762 9763 9764 9805 9806 9808 9809

9810 9811 9812 9813 9814 9815 9816 9817 9818 9819 9820 9821

9822 9823 9824 9825 9826 9827 9828 9829 9830 9831 9832 9833

9834 9835 9836 9837 9838 9839 9840 9841 9842 9843 9844 9845

9846 9847 9848 9849 9854 9855 9862 9863 9864 9866 9867 9868

9869 9870 9871 9872 9873 9874 9875 9876 9877 9878 9879 9880

9881 9882 9883 9884 9885 9886 9887 9888 9889 9890 9891 9892

9893 9894 9895 9896 9897 9898 9899 9900 9901 9902 9903 9904

9907 9909 9919 9920 9921 9931 9932 9933 9934 9939 9940 9941

9942 9943 9944 9946 9947 9951 9953 9958 9959 9962 10099 10100

10104 10106 10109 10106 10114 10115 10116 10117 10118 10119 10120 10121

10122 10125 10126 10128 10182 10610 11703 11728 12072 12816 16502 19521

19556

Total: 644

Three thousand and fifty (3,050) letters were received in support of the proposed rule that were not 

matched to any mass mail efforts.
12/09/11 DRAFT

800

Table 9A-21. General Support Letters

3374 3385 3393 3740 4031 4048 4139 4294 4341 4432 4483 4487

4488 4522 4721 4751 4797 4921 5559 6138 7497 7498 7584 7585

7653 7654 7655 7661 7975 8684 9118 9541 9549 9569 9717 9743

10166 10169 10170 10521 10522 10637 10660 10729 10732 10734 10757 10762

10902 10906 11096 11104 11105 11106 11373 11374 11382 11393 11396 11401

11426 11477 11528 11529 11530 11531 11534 11535 11596 11597 11598 11599

11600 11601 11602 11603 11605 11606 11607 11608 11609 11610 11611 11612

11613 11614 11615 11616 11617 11618 11619 11620 11622 11623 11624 11626

11627 11628 11630 11633 11634 11635 11636 11644 11645 11647 11648 11653

11654 11655 11656 11667 11669 11670 11671 11672 11673 11674 11675 11676

11677 11678 11679 11680 11681 11682 11683 11684 11685 11686 11687 11688

11689 11690 11691 11692 11693 11694 11695 11706 11707 11708 11710 11767

11768 11769 11770 11769 11782 11783 11792 11801 11802 11803 11804 11805

11806 11807 11808 11809 11844 11846 11847 11848 11849 11850 11851 11852

11853 11854 11855 11856 11857 11862 11863 11868 11869 11870 11871 11872

11873 11874 11876 11879 11881 11883 11893 11896 11897 11898 11899 11900

11906 11907 11908 11909 11910 11911 11912 11913 11918 11919 11920 11921

11922 11923 11930 11931 11932 11940 11941 11942 11943 11944 11945 11946

11947 11948 11949 11951 11952 11953 11954 11955 11969 11970 11971 11972

11973 11974 11975 11976 11977 11978 11979 11980 11981 11982 11983 11984

11985 11986 11987 11988 11989 11990 11991 11992 11993 11994 12003 12007

12008 12009 12011 12012 12013 12014 12022 12024 12025 12026 12027 12028

12029 12030 12031 12032 12033 12035 12036 12037 12038 12039 12040 12041

12042 12043 12045 12046 12047 12048 12051 12053 12054 12059 12060 12061

12062 12067 12073 12083 12084 12085 12086 12087 12091 12095 12099 12104

12128 12131 12133 12148 12155 12156 12221 12222 12223 12224 12226 12227

12228 12230 12231 12232 12238 12252 12253 12254 12255 12256 12257 12258

12259 12260 12261 12262 12264 12265 12278 12281 12283 12288 12290 12295

12296 12297 12307 12312 12314 12316 12334 12335 12336 12339 12345 12369

12374 12375 12376 12377 12378 12379 12381 12382 12383 12402 12405 12459

12460 12461 12503 12504 12505 12506 12509 12510 12511 12513 12518 12520

12525 12526 12532 12533 12534 12535 12536 12546 12547 12548 12560 12561

12562 12563 12564 12565 12566 12567 12568 12569 12570 12571 12572 12617

12618 12619 12620 12621 12622 12626 12627 12628 12629 12648 12649 12651

12652 12653 12661 12662 12663 12664 12665 12673 12682 12683 12684 12685

12686 12687 12704 12705 12706 12707 12709 12710 12711 12722 12723 12724

12725 12755 12756 12757 12758 12759 12760 12761 12762 12763 12764 12765

12766 12767 12780 12793 12794 12795 12796 12797 12799 12800 12807 12814

12881 12886 12887 12888 12896 12948 12949 12950 12951 12952 12953 12954

12955 12956 12957 12958 12959 12960 12961 12962 12963 12964 12965 12966

12967 12968 12969 12970 12971 12976 12977 12987 12988 12989 12992 12994

12995 13005 13006 13007 13008 13010 13110 13112 13117 13118 13119 13120
12/09/11 DRAFT

801

13121 13122 13126 13127 13128 13131 13132 13133 13134 13137 13138 13139

13140 13141 13151 13152 13153 13154 13159 13163 13164 13165 13166 13167

13168 13169 13170 13171 13172 13179 13180 13181 13182 13183 13184 13185

13186 13187 13188 13189 13195 13196 13197 13198 13199 13200 13201 13202

13203 13204 13205 13206 13207 13208 13209 13210 13211 13212 13213 13214

13215 13216 13217 13218 13226 13227 13228 13229 13230 13234 13235 13236

13237 13238 13239 13240 13241 13242 13243 13244 13250 13251 13252 13253

13257 13258 13259 13258 13268 13269 13270 13271 13276 13302 13303 13304

13305 13306 13307 13308 13309 13310 13311 13312 13313 13314 13325 13398

13399 13402 13419 13420 13432 13433 13434 13448 13449 13450 13451 13452

13453 13454 13455 13456 13457 13460 13461 13462 13463 13466 13469 13472

13478 13479 13480 13495 13498 13512 13513 13514 13515 13518 13519 13520

13521 13522 13523 13524 13525 13527 13528 13530 13531 13532 13533 13534

13544 13545 13546 13548 13549 13550 13551 13552 13553 13554 13556 13557

13558 13559 13560 13561 13562 13589 13590 13591 13592 13593 13594 13595

13596 13597 13598 13599 13619 13620 13645 13646 13647 13648 13649 13650

13651 13652 13653 13654 13655 13656 13657 13658 13659 13660 13661 13663

13664 13665 13666 13667 13668 13669 13670 13671 13675 13676 13677 13678

13679 13680 13681 13682 13683 13684 13685 13686 13687 13688 13702 13703

13704 13705 13706 13708 13711 13713 13714 13715 13717 13718 13719 13720

13721 13722 13723 13724 13725 13726 13727 13728 13729 13730 13731 13732

13734 13735 13736 13737 13738 13739 13740 13741 13742 13743 13744 13745

13746 13747 13748 13750 13751 13752 13753 13754 13755 13756 13757 13758

13759 13760 13761 13762 13763 13764 13765 13766 13776 13785 13793 13794

13802 13804 13805 13806 13807 13808 13809 13817 13818 13819 13820 13821

13822 13823 13824 13825 13826 13828 13829 13830 13831 13832 13833 13834

13835 13836 13837 13838 13839 13840 13841 13842 13843 13844 13845 13846

13847 13848 13849 13850 13851 13852 13853 13854 13855 13856 13857 13858

13859 13860 13872 13907 13908 13919 13932 13965 13966 13967 13968 13969

13970 13971 13972 13973 13974 13975 13976 13977 13978 13979 13980 13981

13982 14004 14005 14006 14007 14008 14009 14010 14011 14012 14013 14014

14015 14020 14044 14045 14050 14065 14066 14072 14073 14075 14076 14085

14086 14087 14091 14092 14093 14094 14095 14096 14100 14101 14102 14109

14110 14116 14117 14118 14119 14126 14127 14128 14129 14130 14133 14134

14138 14141 14142 14145 14146 14148 14152 14164 14165 14166 14168 14178

14179 14192 14193 14194 14195 14201 14205 14255 14256 14257 14280 14281

14282 14283 14284 14286 14287 14299 14300 14369 14370 14371 14372 14373

14374 14375 14413 14414 14417 14418 14419 14420 14428 14431 14432 14433

14434 14441 14442 14443 14444 14445 14446 14447 14448 14450 14478 14480

14482 14483 14484 14485 14488 14489 14490 14491 14492 14493 14494 14495

14496 14497 14498 14499 14500 14503 14504 14512 14513 14514 14541 14542

14543 14544 14545 14546 14547 14548 14549 14550 14551 14552 14553 14554

14555 14556 14557 14558 14559 14560 14561 14562 14563 14564 14565 14566

14567 14568 14569 14570 14571 14572 14573 14574 14575 14576 14577 14578
12/09/11 DRAFT

802

14579 14580 14581 14580 14583 14584 14585 14586 14587 14588 14589 14590

14591 14592 14593 14594 14595 14596 14597 14598 14599 14629 14672 14673

14674 14675 14697 14698 14699 14700 14701 14702 14703 14704 14705 14706

14707 14708 14709 14710 14711 14712 14713 14714 14715 14716 14717 14718

14719 14720 14722 14723 14724 14728 14729 14730 14731 14732 14733 14734

14735 14736 14737 14738 14739 14740 14741 14742 14743 14744 14745 14746

14747 14748 14749 14750 14751 14752 14753 14754 14755 14756 14757 14758

14759 14760 14761 14769 14770 14771 14772 14773 14774 14775 14780 14781

14782 14783 14784 14785 14786 14787 14788 14789 14790 14802 14803 14807

14808 14809 14813 14814 14815 14816 14817 14819 14820 14821 14822 14823

14824 14825 14826 14827 14828 14829 14830 14831 14832 14845 14855 14856

14857 14858 14859 14860 14861 14862 14863 14864 14865 14866 14867 14868

14869 14870 14871 14872 14873 14874 14875 14876 14877 14878 14879 14880

14881 14882 14883 14884 14885 14886 14887 14888 14889 14890 14891 14892

14893 14894 14895 14896 14897 14898 14899 14900 14905 14906 14907 14908

14909 14910 14911 14912 14913 14914 14915 14916 14917 14918 14919 14920

14921 14922 14923 14924 14925 14926 14927 14928 14929 14930 14931 14932

14933 14934 14935 14936 14937 14938 14939 14940 14941 14942 14943 14944

14945 14946 14947 14948 14949 14954 14955 14956 14957 14958 14959 14960

14961 14967 14968 14971 14976 14977 14978 14979 14980 14981 14982 14983

14984 14985 14986 14987 14988 14989 14990 14991 14992 14993 14994 14995

14996 14997 14998 14999 15000 15001 15004 15005 15010 15012 15013 15014

15025 15026 15027 15028 15029 15030 15031 15032 15033 15034 15035 15036

15037 15038 15039 15040 15041 15047 15055 15062 15063 15064 15065 15066

15067 15068 15069 15070 15071 15072 15073 15074 15075 15076 15077 15078

15079 15083 15084 15085 15086 15087 15088 15089 15090 15091 15092 15093

15094 15095 15096 15097 15098 15099 15100 15101 15102 15103 15105 15106

15107 15108 15109 15110 15111 15112 15113 15114 15115 15116 15117 15118

15119 15120 15121 15122 15123 15124 15125 15126 15127 15128 15129 15130

15131 15132 15133 15134 15135 15136 15137 15138 15139 15140 15141 15142

15143 15144 15145 15146 15147 15148 15149 15150 15151 15152 15153 15154

15155 15156 15157 15158 15159 15162 15163 15169 15175 15177 15178 15179

15181 15183 15184 15185 15186 15187 15188 15189 15191 15192 15193 15199

15200 15201 15202 15203 15204 15205 15206 15207 15208 15213 15215 15216

15218 15222 15223 15226 15228 15231 15232 15233 15234 15235 15236 15237

15238 15239 15240 15241 15242 15243 15245 15246 15247 15248 15254 15255

15256 15257 15258 15259 15260 15261 15262 15263 15266 15269 15270 15271

15272 15276 15284 15276 15288 15300 15301 15302 15303 15304 15305 15306

15307 15308 15309 15310 15311 15312 15313 15314 15315 15316 15317 15318

15319 15328 15329 15330 15331 15336 15352 15353 15354 15355 15356 15357

15358 15359 15360 15361 15362 15363 15364 15365 15366 15367 15368 15369

15370 15371 15372 15373 15374 15375 15376 15377 15378 15379 15380 15381

15382 15383 15384 15385 15392 15393 15394 15395 15396 15397 15398 15404

15410 15411 15412 15413 15414 15415 15416 15417 15418 15424 15426 15427
12/09/11 DRAFT

803

15428 15429 15430 15431 15432 15447 15451 15452 15453 15454 15455 15456

15459 15462 15463 15464 15466 15467 15468 15469 15470 15471 15472 15473

15474 15475 15476 15477 15478 15479 15480 15481 15482 15493 15497 15499

15500 15501 15502 15503 15504 15505 15506 15507 15508 15509 15510 15511

15512 15513 15521 15524 15535 15537 15538 15539 15540 15541 15542 15543

15544 15545 15546 15547 15554 15555 15561 15562 15563 15564 15565 15571

15572 15573 15574 15575 15576 15577 15578 15579 15580 15581 15582 15583

15584 15585 15586 15587 15588 15589 15591 15592 15593 15594 15595 15596

15597 15598 15599 15600 15601 15602 15603 15604 15605 15606 15607 15608

15609 15610 15611 15612 15613 15614 15615 15616 15617 15618 15619 15620

15621 15622 15623 15624 15625 15626 15627 15628 15629 15630 15631 15632

15633 15634 15635 15637 15638 15639 15640 15641 15642 15643 15644 15645

15646 15647 15648 15649 15650 15651 15652 15653 15654 15655 15656 15657

15658 15659 15660 15665 15666 15667 15679 15692 15693 15694 15695 15696

15697 15698 15699 15700 15701 15702 15703 15704 15705 15706 15707 15708

15709 15710 15711 15712 15713 15714 15715 15716 15717 15718 15719 15720

15721 15722 15723 15724 15725 15726 15727 15728 15729 15730 15731 15732

15733 15734 15735 15736 15737 15738 15739 15740 15741 15742 15743 15744

15745 15746 15747 15748 15749 15750 15751 15752 15753 15754 15755 15756

15757 15758 15759 15760 15761 15762 15763 15764 15765 15766 15767 15800

15801 15804 15805 15806 15807 15808 15809 15810 15811 15814 15815 15816

15817 15818 15819 15820 15821 15822 15830 15832 15833 15834 15835 15836

15837 15838 15839 15840 15841 15842 15843 15844 15845 15846 15847 15848

15849 15853 15854 15855 15856 15857 15858 15859 15860 15861 15862 15863

15864 15874 15877 15878 15879 15881 15885 15886 15887 15888 15889 15890

15897 15898 15899 15900 15901 15902 15903 15904 15905 15906 15907 15908

15909 15916 15927 15928 15929 15936 15937 15938 15939 15940 15941 15942

15943 15944 15945 15946 15947 15957 15962 15963 15964 15965 15966 15967

15968 15969 15970 15971 15972 15973 15974 15975 15976 15977 15978 15979

15980 15981 15982 15983 15986 15987 15988 15989 15990 15991 15992 15993

15994 15995 15996 15995 15998 16002 16003 16004 16015 16016 16017 16018

16019 16020 16021 16022 16023 16033 16034 16035 16036 16037 16038 16039

16040 16041 16042 16043 16044 16045 16048 16050 16051 16056 16057 16058

16059 16061 16062 16063 16070 16071 16074 16076 16077 16078 16079 16082

16085 16086 16087 16088 16089 16090 16091 16093 16103 16105 16106 16107

16108 16109 16110 16111 16112 16113 16118 16119 16120 16123 16124 16137

16138 16139 16140 16141 16142 16143 16144 16145 16146 16149 16152 16163

16167 16168 16169 16170 16171 16172 16173 16174 16175 16176 16178 16179

16180 16181 16182 16183 16184 16185 16186 16187 16188 16189 16191 16193

16194 16195 16196 16197 16198 16199 16200 16201 16202 16203 16204 16205

16206 16219 16232 16240 16243 16244 16245 16246 16247 16248 16249 16250

16251 16252 16253 16254 16255 16256 16257 16258 16259 16260 16261 16262

16263 16264 16265 16266 16267 16268 16269 16270 16271 16272 16273 16274

16275 16276 16277 16278 16279 16280 16284 16288 16289 16290 16291 16292
12/09/11 DRAFT

804

16293 16294 16295 16296 16301 16302 16305 16307 16308 16309 16310 16313

16317 16318 16321 16325 16326 16327 16328 16329 16330 16331 16332 16333

16334 16335 16336 16337 16338 16339 16340 16341 16342 16343 16344 16347

16348 16356 16359 16360 16361 16362 16363 16364 16365 16366 16367 16368

16369 16370 16371 16372 16373 16374 16375 16385 16407 16408 16409 16410

16411 16419 16420 16421 16422 16423 16424 16425 16426 16427 16428 16429

16430 16431 16432 16433 16434 16437 16487 16490 16491 16492 16493 16494

16495 16496 16497 16498 16499 16503 16519 16544 16563 16570 16571 16572

16573 16574 16579 16580 16582 16583 16593 16594 16595 16596 16599 16600

16601 16604 16605 16606 16607 16608 16609 16610 16611 16612 16613 16614

16615 16616 16617 16618 16619 16620 16621 16622 16623 16624 16625 16631

15745 15746 15747 15748 15749 15750 15751 15752 15753 15754 15755 15756

15757 15758 15759 15760 15761 15762 15763 15764 15765 15766 15767 15800

15801 15804 15805 15806 15807 15808 15809 15810 15811 15814 15815 15816

15817 15818 15819 15820 15821 15822 15830 15832 15833 15834 15835 15836

15837 15838 15839 15840 15841 15842 15843 15844 15845 15846 15847 15848

15849 15853 15854 15855 15856 15857 15858 15859 15860 15861 15862 15863

15864 15874 15877 15878 15879 15881 15885 15886 15887 15888 15889 15890

15897 15898 15899 15900 15901 15902 15903 15904 15905 15906 15907 15908

15909 15916 15927 15928 15929 15936 15937 15938 15939 15940 15941 15942

15943 15944 15945 15946 15947 15957 15962 15963 15964 15965 15966 15967

15968 15969 15970 15971 15972 15973 15974 15975 15976 15977 15978 15979

15980 15981 15982 15983 15986 15987 15988 15989 15990 15991 15992 15993

15994 15995 15996 15995 15998 16002 16003 16004 16015 16016 16017 16018

16019 16020 16021 16022 16023 16033 16034 16035 16036 16037 16038 16039

16040 16041 16042 16043 16044 16045 16048 16050 16051 16056 16057 16058

16059 16061 16062 16063 16070 16071 16074 16076 16077 16078 16079 16082

16085 16086 16087 16088 16089 16090 16091 16093 16103 16105 16106 16107

16108 16109 16110 16111 16112 16113 16118 16119 16120 16123 16124 16137

16138 16139 16140 16141 16142 16143 16144 16145 16146 16149 16152 16163

16167 16168 16169 16170 16171 16172 16173 16174 16175 16176 16178 16179

16180 16181 16182 16183 16184 16185 16186 16187 16188 16189 16191 16193

16194 16195 16196 16197 16198 16199 16200 16201 16202 16203 16204 16205

16206 16219 16232 16240 16243 16244 16245 16246 16247 16248 16249 16250

16251 16252 16253 16254 16255 16256 16257 16258 16259 16260 16261 16262

16263 16264 16265 16266 16267 16268 16269 16270 16271 16272 16273 16274

16275 16276 16277 16278 16279 16280 16284 16288 16289 16290 16291 16292

16293 16294 16295 16296 16301 16302 16305 16307 16308 16309 16310 16313

16317 16318 16321 16325 16326 16327 16328 16329 16330 16331 16332 16333

16334 16335 16336 16337 16338 16339 16340 16341 16342 16343 16344 16347

16348 16356 16359 16360 16361 16362 16363 16364 16365 16366 16367 16368

16369 16370 16371 16372 16373 16374 16375 16385 16407 16408 16409 16410

16411 16419 16420 16421 16422 16423 16424 16425 16426 16427 16428 16429

16430 16431 16432 16433 16434 16437 16487 16490 16491 16492 16493 16494
12/09/11 DRAFT

805

16495 16496 16497 16498 16499 16503 16519 16544 16563 16570 16571 16572

16573 16574 16579 16580 16582 16583 16593 16594 16595 16596 16599 16600

16601 16604 16605 16606 16607 16608 16609 16610 16611 16612 16613 16614

16615 16616 16617 16618 16619 16620 16621 16622 16623 16624 16625 16631

17172 17173 17175 17176 17177 17178 17179 17180 17181 17182 17183 17185

17186 17187 17188 17189 17190 17192 17195 17196 17198 17199 17200 17201

17202 17203 17204 17205 17206 17207 17208 17209 17210 17211 17212 17213

17214 17215 17216 17217 17218 17219 17220 17221 17222 17223 17224 17225

17226 17227 17228 17237 17238 17241 17242 17243 17244 17246 17247 17248

17249 17250 17251 17255 17267 17268 17271 17273 17274 17275 17276 17277

17282 17289 17290 17292 17293 17303 17304 17309 17310 17317 17318 17319

17320 17321 17323 17336 17337 17338 17339 17340 17341 17342 17343 17344

17345 17346 17347 17348 17349 17350 17351 17352 17353 17355 17356 17357

17358 17359 17360 17361 17362 17363 17364 17366 17367 17368 17369 17371

17372 17373 17375 17376 17377 17378 17379 17380 17382 17384 17387 17388

17389 17390 17391 17393 17395 17396 17397 17398 17399 17407 17457 17463

17465 17466 17470 17466 17473 17489 17490 17496 17624 17641 17652 17688

17759 17764 17780 17793 17828 17832 17888 17896 17905 17906 17907 17932

17933 17934 17935 17951 17952 18040 18041 18042 18044 18045 18046 18047

18048 18049 18065 18249 18260 18267 18286 18287 18288 18302 18306 18313

18319 18361 18362 18363 18364 18365 18366 18367 18368 18369 18370 18401

18406 18413 18503 18504 18505 18506 18507 18511 18547 18548 18551 18552

18554 18557 18616 18646 18668 18669 18670 18671 18672 18695 18696 18697

18708 18712 18719 18743 18828 18850 18869 18878 18879 18918 18928 18929

18957 18972 18973 18974 18987 19004 19009 19010 19013 19016 19024 19027

19028 19030 19039 19084 19089 19090 19095 19097 19098 19099 19102 19103

19117 19118 19119 19124 19144 19149 19154 19155 19156 19159 19161 19162

19164 19165 19166 19167 19172 19173 19175 19177 19179 19195 19196 19198

19202 19206 19220 19221 19223 19224 19226 19227 19228 19229 19236 19238

19239 19240 19241 19242 19244 19246 19247 19248 19249 19255 19256 19257

19258 19259 19260 19262 19264 19265 19271 19273 19274 19275 19276 19277

19278 19279 19280 19281 19282 19283 19284 19285 19286 19287 19290 19293

19294 19300 19301 19308 19309 19328 19330 19331 19332 19433 19507 19518

19519 19529 19531 19554 19561 19575 19576 19577 19582 19590 19591 19594

19596 19597 19598 19599 19600 19602 19604 19605 19607 19614 19616 19618

19619 19621 19623 19624 19626 19655 19656 19657 19658 19676 19695 19696

19697 19698

Total: 3,050
12/09/11 DRAFT

806

9B - General Opposition

Comment 1: The EPA received 4,830 mass-mail and form letters expressing general opposition to the 

electric generating units NESHAP. Commenter’s concerns include the rule’s effect on electricity prices, 

system dependability, employment, and the effect on small businesses and the overall economy. Due to 

the high number of comments for this proposed rule, these comments were categorized and sorted 

according to the group that organized the mass-mail campaign.

The U.S. Docket office identified 4,527 mass-mail comment letters and assigned them to 6 DCNs, 

simplifying this process. These mass-mail DCNs are listed in Table 9B-1 of this section with the count 

of comment letters and the associated organization.

More mass-mail comment letters were identified from the remaining comment letters and are listed in 

Tables 9B-2 through 9B-4 in this section.

Letters expressing general opposition that are not associated with any mass-mail campaign are listed in 

Table 9B-5 in this section.

Many organizations provided members with form letters. Form letters containing substantive comments 

had a few representative letters excerpted and summarized for the Response to Comments document. 

The remaining letters are listed here.

Many commenters (17295, 17401, 17748, 17749, 17750, 17763, 17778, 17783, 17788, 17792, 17822, 

17825, 17826, 17827, 17866, 17890, 17891, 17897, 17910, 17924, 18414, 18482, 18499, 18705, 18706, 

18894, 18936, 18937, 18944, 19549, 19559, 19560, 19566) representing municipal utilities expressed 

concerns about the proposed rule. These commenters asked that the EPA evaluate the impact of the 

proposed rule under SBREFA, UMRA and EO 13563, EO 13132, EO 12866, and EO 13211. Comments 

are discussed in further detail by commenter 18038.

Response to Comment 1: The EPA acknowledges the general concerns of the commenters regarding 

the Mercury and Air Toxics Standards, and responses to comments elsewhere in this document generally

address those concerns. Comments and responses relating to the consideration of SBREFA, UMRA, EO 

13563, EO 13132, EO 12866, and EO 13211 may also be found elsewhere in this document.
12/09/11 DRAFT

807

Section 9B Tables

Mass Mailings - General Opposition to the Proposed Rule

Table 9B-1. Mass mail comments identified by the U.S. Docket Office

DCN Docket Entry Count

19651 Mass Comment Campaign sponsoring organization unknown 142 

19633 Mass Comment Campaign sponsoring organization unknown 885 

19646 Mass Comment Campaign sponsoring organization unknown 20 

19645 Mass Comment Campaign sponsoring organization unknown 945 

19650 Mass Comment Campaign sponsoring organization unknown 1,788 

19652 Mass Comment Campaign sponsoring organization unknown 747 

Total: 4,527 

In addition to the mass mailings identified by the U.S. Docket Office, 268 mass mail comments were 

also identified by RTI International. 

Table 9B-2. American Electric Power

14487 14509 14511 14520 14610 14612 14613 14614 14616 14617 14618 14619

14620 14621 14624 14628 14630 14631 14634 14635 14636 14637 14638 14639

14640 14641 14642 14643 14644 14645 14646 14647 14649 14651 14652 14654

14656 14658 14659 14660 14662 14664 14666 14667 14668 14671 14679 14680

14681 14682 14683 14684 14685 14686 14687 14688 14689 14690 14691 14692

14693 14694 15190 15439 15560 15566 15567 15568 15569 15661 15662 15663

15664 15670 15768 15769 15770 15771 15772 15773 15779 15780 15781 15782

15783 15785 15793 15794 15795 15796 15797 15798 15799 15812 15825 15826

15827 15829 15850 15851 15868 15869 15870 15871 15872 15880 15882 15924

15925 15935 15948 15950 15958 16127 16130 16154 16159 16160 16161 16162

16208 16212 16221 16222 16223 16224 16234 16239 16285 16286 16287 16300

16314 16315 16316 16324 16349 16350 16351 16353 16354 16355 16357 16358

16376 16379 16381 16379 16436 16450 16461 16488 16489 16501 16517 16536

16537 16542 16597 16845 17108 17184 17300 17330 17331 17332 17333 17334

17335 17354 17365 17370 17445 17472 17486 17908 17947 17953 18186 18301

18357 18377 18558 18565 18571 18620 18621 18623 18631 18661 18662 18664

18682 18683 18686 18689 18690 18692 18693 18694 18699 18776 18780 18784

18841 18849 18874 18917 18925 18926 18927 18940 18955 18969 18971 19085

19295 19320 19625

Total: 219
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808

Table 9B-3. Chamber of Commerce

17657 17658 17659 17660 17661 17680 17684 17685 17686 17693 17694 17695

17700 17708 17717 17779 17823 18415 18416 18417 18418 18420 19296

Total: 23

Table 9B-4. Public Service Company of Oklahoma

18959 18960 18975 19025 19026 19029 19091 19096 19100 19109 19140 19141

19142 19148 19153 19158 19160 19163 19168 19174 19176 19261 19266 19461

19527 19584

Total: 26

The EPA received 35 letters opposing the proposed rule that were not matched to any mass mail efforts.

Table 9B-5. General Opposition Letters

12152 12192 12708 13749 14003 14427 14501 14519 14625 14818 15104 16412

16414 16415 16416 16417 16438 16543 16718 16947 16966 17032 17233 17269

17280 17329 18279 18615 18622 18867 18966 19178 19302 19562 19635

Total: 35
12/09/11 DRAFT

809

CHAPTER 10: INCORPORATION BY REFERENCE

10 - Incorporation by Reference

Comment: Many commenters requested that the remarks of other commenters be incorporated into their 

own comments on the proposed rule. The table below lists the commenters who have been referenced, 

followed by the commenters who asked to incorporate the referenced commenters’ remarks. 

Specifically, the first column in Table 10-1 is a list of commenters who were referred to by other 

commenters. The second column gives a short name for the commenters who were referenced. The third 

column provides a list of the commenters who referred to each of the referenced commenters. 

Response: The EPA acknowledges the general concerns of the commenters regarding the proposed 

Mercury and Air Toxics Standards and has responded to them in this document, the preamble to the final 

rule, and other associated technical and regulatory impact analysis supporting materials.

Table 10-1. Incorporation by Reference

Referenced 

Commenter 

DCN

Referenced 

Commenter 

Short Name

Referencing Commenters

17799 ACCCE 17790

17877 AECI 19094

17815 AECT 17904, 18785

19114 AEP 17715, 17757, 18907, 19041

17810 ANGA 17853

8443, 17868 APPA 17655, 17702, 17705, 17767, 18015, 18018, 18031, 18032, 

18437, 18500, 18831, 19121, 19213

17754 ARIPPA 18427

17757 Buckeye 19041

17760 Class 85 17702, 17722, 17776, 17807, 17870a, 17902, 17909, 17920, 

18018, 18020, 18831

17808 Clean Energy

Group 17870a

, 18025

18500 CPG 18437

17758 EEI 17627, 17770, 17772, 17776, 17790, 17800, 17805b, 17807, 

17820, 17870a, 17881, 17902, 17920, 18015, 18031, 18428

18037 EPGA 17627

17621 EPRI 17627, 17705, 17722, 17730, 17757, 17790, 17800, 17820, 

17821, 17881, 17886, 17902, 17904, 18015, 18020, 18021, 

18428, 18437, 18443, 19041

17638 FCG 17702, 17769, 17807, 17814, 18018, 18831

18018 FMEA 18831

17930 GCLC 17813, 17904, 18785

17698 GPA 17710

19506 IDEM 19212

19122 LADWP 19121

17724 LEC 17722, 17805, 18031
12/09/11 DRAFT

810

17623 LPPC 17705, 18437, 18831

18426 MDEQ 17881

19742 MMA 17881

18488 MOG 17627, 17800

17297 MPSC 17881

17640, 

19580

NAM 18031

17701, 

17791

NARUC 16850

17842 ND PSC 17805

17735 New Units 17817

18033 NMA 17901, 17904, 18051, 18424, 18489

17689 NRECA 17197, 17909, 17730, 17757, 17813, 17817, 17909c, 18020, 

18429, 18443, 18820, 19041, 19094

17736 OEUG 17627, 17715, 17772

16549 PACE 17137, 17782

18448, 

18441

PJM 17804

16873 PUCO 17856

18538 TX PUC 18034

17775 UARG 17197, 17627, 17705, 17715, 17728, 17730, 17737, 17770, 

17772, 17790, 17795, 17800, 17820, 17821, 17868d, 17881, 

17886, 17904, 18015, 18021, 18031, 18033, 18428, 18429, 

19041, 19121, 18203

16496 UJAE 17817

17656 WBRT 17805

19741 West 17705, 17737, 18015

14115 Willie Soon 14368

a NextEra Energy Inc. (DCN 17870) incorporated by reference comments from several contributors, but 

with the caveat, “except in instances when the comments of these industry groups may conflict with 

NextEra Energy’s position as set forth in the comments below.”

b Montana-Dakota Utilities Company (DCN 17805) incorporated by reference the majority of EEI’s 

comments, as identified in Montana-Dakota Utilities Company’s letter.

c

PowerSouth Energy Cooperative (DCN 17909) incorporated by reference comments from NRECA on 

setting numerical standards.

d American Public Power Association (DCN 17868) incorporated by reference UARG’s comments in 

regard to data availability, data analysis, conversion errors, and MACT monitoring.
12/09/11 DRAFT

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APPENDIX A: PUBLIC HEARING PARTICIPANTS

List of Speakers for Public Hearing – Atlanta – 26 May 2011

Time Name Affiliation

9:15 Josh Galperin Southern Alliance for Clean Energy

9:20 Jen Rennicks Southern Alliance for Clean Energy

9:25 Katie Preston Georgia Interfaith Power and Light

9:30 Colleen Kiernan Georgia Sierra Club

9:35 Peter Bahouth US Climate Action Network

9:40 H. James Gooden American Lung Association Board of Directors

9:45 Robert Kappelmann Energy and Environmental Policy Consultants

9:50 Dr. Anne MellingerBirdsongGeorgia Chapter of the American Academy of Pediatrics 

Committee on Environmental Health

9:55 Janice Nolen American Lung Association

10:00 Charles “Clay” B. Jones, 

III

Georgia Traditional Manufacturers Association

10:05 William P. Brown Individual

10:10 Representative Scott 

Holcomb

GA State Representative

10:15 Dale Kemmerick POPE

10:20 Stanley P. Saunders Individual

10:25 Juliet Cohen Upper Chattahoochee River Keeper

10:30 Rebecca Watts-Hull Mothers & Others for Clean Air

10:35 Joe Hudson Farmers & Merchants Bank

10:40 Chris Hobson Southern Company Services

10:45 Rev. Woody Bartlett Georgia Interfaith Power & Light

10:50 Robert D. Bullard Environmental Justice Resource Center

Clark Atlanta University

10:55 Dr. Yolanda Whyte Individual

11:00 Mike Kennedy Progress Energy

11:05 Byron T. Burrows Tampa Electric Company

11:10 Alison Amyx Georgia Interfaith Power & Light

11:15 Bob Donaghue Georgia Interfaith Power & Light

11:20 Clark Efaw Georgia Interfaith Power and Light

11:25 Dr. James Rust

11:30 Thomas Pearce Sierra Club

11:35 Robin Mann Sierra Club

11:40 Jaffer Khimani Clean Air Task Force

11:45 Mark MacLeod Environmental Defense Fund

11:50 John B. Hammond National Wildlife Federation

11:55 Jack Thirolf Business Council for Sustainable Energy

12:00 Dabney Dixon Individual

12:05 Lance Brown Partnership for Affordable Clean Energy (PACE)

12:10 Steve Earle UMWA Region 3

12:15 Virginia Galloway Americans for Prosperity

12:20 Kevin McGrath GA Trout Unlimited
12/09/11 DRAFT

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Time Name Affiliation

12:25 Alan O. Toney Individual

12:30 James Capp Georgia Air Protection Branch

12:35 Joy Kramer GA Solar Energy Association

12:40 Thelma Heywood Sierra Club

12:45 Roger Mills Individual

12:50 Sean Hutchins KY Environmental Foundation

2:10 Seandra Rawls Southern Alliance for Clean Energy

2:15 Eriqua Foreman Williams Southern Alliance for Clean Energy

2:20 Emily Enderlee Earthjustice

2:25 Danny Schweinhart Individual

2:30 Alexei Laushkin The Evangelical Environment Network

2:35 Rev. Richard Cizik Evangelicals for the Common Good

2:40 Glen Hooks Sierra Club

2:45 Katherine Helms 

Cummings

FACE

2:50 Midge Sweet Georgians for Smart Energy Coalition

2:55 Lynn Redwood SAFE MINDS

2:25 Jennette Gayer Environment Georgia

2:55 Dave Muhly Sierra Club

3:00 Eddie Ehlert Individual

3:05 Lyndsay Moseley Sierra Club

3:10 Imran Battla The Prana Group

3:15 David Richardson

3:20 Ron Shipman Georgia Power Company

3:25 Seth Hutchins KY Environmental Foundation

3:30 Thomas Hutegger Individual

3:35 John Walsh Sierra Club

3:40 Robert Fletcher

3:45 Elizabeth Crowe Kentucky Environmental Foundation

3:50 Kathy Little Kentucky Environmental Foundation

3:55 Robert Ukeiley Citizen

4:00 Natalie Crone & Student 

group

Chelsea Carroll

Matt Callo

Shawn Hutchins

Alex English

Austin Delph

Seth Hutchins

Kentucky Environmental Foundation

4:05 Simon Montelongo Kentucky Environmental Foundation

4:10 Benita Dodd

4:15 Shelia Tyson Citizen-Birmingham, Al

4:20 Jessica Spruill Southern Energy Network

4:25 Joan Lindop Sierra Club GA
12/09/11 DRAFT

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Time Name Affiliation

4:30 Elizabeth Lopez Global Warming and Energy Team

4:35 Patti Gettinger Individual

4:40 Rel Corbin

4:45 Cassy Hobert Kentucky Environmental Foundation

4:50 Michael J. Churchman Alabama Environmental

4:55 Molly Embree Environment Georgia

5:00 April Ingle GA River Network

5:05 Natasha Herbert

5:10 Arthur Gibert Sierra Club

5:15 Andrea Lyle Individual

5:20 John Krueger Georgia Chamber of Commerce

30303

5:25 Flora Tommie Sierra Club / Perkerson Civic Association (PCA)

5:30 June Deen American Lung Association in Georgia

6:40 Lev Guter Sierra Club

6:45 Jenna Garland Southern Energy Network

6:50 Michael Wall Environment Georgia

6:55 Bill Cunningham Unions for Jobs and the Environment (UJAE)

Mark Woodall Sierra Club Georgia Chapter

7:10 Tony C. Anderson The Lets Raise a Million Education Fund

7:15 Erin Glynn (presented 

video testimony narrated 

by Erin Savage)

Sierra Club

7:20 John Noel Individual

7:25 Burt Lesnick American Thoracic Society

7:35 Brandon Sutton Sierra Club

7:40 Carly Queen Individual

7:45 Melissa Nummink Individual
12/09/11 DRAFT

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List of Speakers for Public Hearing – Chicago – 24 May 2011

Time Name Affiliation

9:15 Rev. Dr. Clare 

Butterfield

Faith in Place and the Illinois Interfaith Power and Light 

Campaign

9:20 Rev. Faith Bugel Environmental Law and Policy Center

9:25 Brian Urbaszewski Respiratory Health Association of Metropolitan Chicago

9:30 Amy M. Trojecki Exelon Business Services Company

9:35 Ben Lowe Evangelical Environmental Network

9:40 Verena Owen Sierra Club

9:45 Peter Iwanowicz American Lung Association

9:50 Sarah Hodgdon Sierra Club

9:55 Matthew Dunne for Lisa 

Madigan

IL Attorney General

10:00 Mary Gade Gade Environmental Group, LLC

10:05 Catie Krasner Environmental Illinois

10:10 Steve Frenkel Union of Concerned Scientists 

10:15 Jerry Mead-Lucero Pilsen Environmental Rights and Reform Organization

10:20 William “Bill”

Kempiners

American Lung Association Advocacy Committee

10:25 Jennifer Johnson 

Monberg

Individual

10:30 Lyman C. Welch Alliance for the Great Lakes

10:35 Erika Dornfeld Faith in Place

10:40 Michael T.W. Carey Ohio Coal Association

10:45 Matt Most Encana Natural Gas Inc.

10:50 Dr. Michael S. Hogue Meadville Lombard Theological School

10:55 Matthew Soerens Individual

11:00 Jerome Stone Individual

11:05 Cathy S. Woollums MidAmerican Energy Holdings Company

11:10 Dr. Lin Kaatz Chary Indiana Toxics Action

11:15 Dr. Dawn M. Nothwehr Catholic Theological Union

11:20 Dr. Helen J. Binns American Academy of Pediatrics

11:25 Nancy Bultinck Respiratory Health Association of Metropolitan Chicago

11:30 Jim Ginderske Neighbors for a Healthy Rogers Park

11:35 Michael Murray Individual

11:40 Eve Pytel Metropolitan Mayors Caucus Clean Air Counts Campaign

11:45 Terry Grace Educator – Retired

11:50 Cory Jones Sierra Club

11:55 Don Ferber Sierra Club

12:00 Rev. Homer Cobb NAACP

12:05 Kimberly Wasserman Little Village Environmental Justice Organization /NETAC

12:10 Ian Viteri Little Village Environmental Justice Organization

12:15 Victoria Persky Individual

12:20 John Blair Valley Watch

12:25 Leigh Touchton NAACP

12:30 Dr. Howard Ehrman UIC/LVESO
12/09/11 DRAFT

815

Time Name Affiliation

12:35 Benjamin Stewart Lutheran School of Theology at Chicago

12:40 Janet Bohn Individual

12:45 David Shaw National Association of Clean Air Agencies

12:50 Brenda Archambo Individual

2:00 Rose Gomez Sierra Club

2:05 Chris Pado Individual

2:10 Dr. Suzanna McColley American Thoracic Society

2:15 Richard Cogan President of Textile Industries, Inc.

2:20 Margaret Nelson League of Conservation Voters

2:25 Shannon Fisk Natural Resources Defense Council

2:30 Laura Kratz League of Women Voters of Illinois

2:35 Alfred B.J. Williams II NAACP

2:40 Brad Vam Guilder Ecology Center, Ann Arbor, MI

2:45 Susan Michetti Individual

2:50 Howard A. Learner Environmental Law and Policy Center

2:55 Boise Jones Sierra Club/EJAM

3:00 Ade Oba Abdalla Energy Efficiency and Environmental Health Services - Task 

Force

3:05 Dennis Nelson NEIS

3:10 Jerry B. Cain Judson University

3:15 Rebecca Rossof Climate and Energy Program

3:20 Michelle Martinez Sierra Club

3:25 Ingrid Wendland 

(daughter of Juliee De La 

Terre)

Individual

3:27 Juliee De La Terre Individual

3:30 Lance Green Individual

3:35 Patricia Rosenthal Sierra Club

3:40 Kelly Pierce Individual

3:45 Patricia A.S. Crowley Kalamazoo County Drain Commissioner

3:50 James McPike Individual

3:55 Vivian Hood Individual

4:00 Joan Arnold Individual

4:05 Dr. Sarah Lovinger Physicians for Social Responsibility

4:10 Susan E. Harley Michigan Policy Director

4:15 Lee Sprague Little River Band of Ottawa Indians

Tribal Council

4:20 Danielle Korpalski National Wildlife Federation

4:25 Frank Szollosi National Wildlife

Federation’s Great Lake’s Office in Ann Arbor

4:30 Suhail Barot Individual

4:35 Amy Allen Individual

4:40 Dr. Barbara Timmermans Evangelical Environmental Network

4:45 Frederick Ellsworth Sierra Club

4:50 Dr. Daniel N. Weber Children’s Environmental Health Sciences Center
12/09/11 DRAFT

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Time Name Affiliation

4:55 Amanda Kaley Individual

5:00 Susan Williams Sierra Club

5:05 David A. Creech ELCA World Hunger

5:10 Dr. Edward (Ted) 

Naureckas

Individual

5:15 Sue Blaine Labadie Environmental Organization/Individual

5:20 Dana March Individual

5:25 Jason Duba Individual

5:30 Jennifer Jansen National Wildlife Federation

5:35 Jocelyn Travis NAACP

5:40 David L. DePrez Individual

5:45 Rose Joshua NAACP

5:50 Auriel Banister Little Village Environmental Justice Organization

6:45 Olivia Woollam University of Chicago Climate Action Network, and the 

Chicago Youth Climate Coalition

6:50 Caroline Wooten UChicago Climate Action Network, Chicago Youth Climate 

Coalition

6:55 Pamela Ortner Individual

7:00 Donna Hriljac Individual

7:05 Rev. Theresa Dear NAACP

7:10 Jim Schneider Individual

7:15 Dr. Sam Dorevitch University of Illinois

7:20 Susanne Brooks Environmental Defense Fund

7:25 Brian Perbix Sierra Club

7:30 Sherry Leonard Individual

7:35 Marianne Flanagan Individual

7:40 Jessica Brackett Individual

7:45 Paul Kim University of Chicago

7:50 Joyce Blumenshine Heart of Illinois Sierra Club

7:55 Dr. Maureen McCue Iowa Physicians for Social Responsibility

8:00 Susan Lannin Individual

8:05 Tim Sutherlin Individual

8:10 Kristen Vyhnal Individual

8:15 Melissa Mullarkey

8:20 Alexandra Sipiora Individual

8:25 Kevin Carol Individual

8:30 Adam Burke Individual

8:35 Marybeth Gardam Women’s International League for Peace & Freedom

8:40 Richard Stucky Individual

8:45 Grace Pai University of Chicago

8:50 Dr. Robert A. Rosenstein Sierra Club, Union of Concerned Scientists, and Green America

8:55 Carol Chaplan GREENFAITH

9:00 Chris Didato Individual

9:05 Bonnie Atkins Clean Air Muscatine
12/09/11 DRAFT

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List of Speakers for Public Hearing – Philadelphia – 24 May 2011

Time Name Affiliation

9:15 Rabbi Daniel Swartz Scranton Area Ministerium and PA Interfaith Power and Light

9:20 Deborah P. Brown The American Lung Assoc.

9:25 Charles McPhedran Citizens for PA’s Future (PennFuture)

9:30 Robin Mann Sierra Club

9:35 Joseph Minott Clean Air Council

9:40 Adam Garber Penn Environment

9:45 Paul J. Miller Northeast States for Coordinated Air Use Management

9:50 Dr. Walter Tsou Philadelphia Physicians for Social Responsibility

9:55 Stephen Harvey Sierra Club; Pepper Hamilton LLP

10:00 Reverend Cheryl Pyrch Summit Presbyterian Church

10:05 Eileen O’Boyle Greenpeace USA

10:10 Jay Butera Individual

10:15 Rev. Mitchell Hescox Evangelical Environmental Network

10:20 Leslie G. Fields Sierra Club

10:25 Paul G. Billings American Lung Association 

10:30 James W. Banford, Jr. International Brotherhood of Boilermakers; Boilermakers 

Local Lodge No. 13

10:35 Dr. Poune Sabieri Sierra Club

10:40 Doug Keith Sierra Club

10:45 Joy Bergey The Center for the Celebration of Creation

10:50 Kevin M. Stewart American Lung Association of the Mid-Atlantic

10:55 Christine Guhl Sierra Club

Statement from Anna 

Maria Caldera read by 

Christine Guhl

Individual

11:00 Scott Segal Electric Reliability Coordinating Council/B&G

11:05 Corinne Wright Sisters of St. Francis of Philadelphia

11:10 Thomas Au Clean Air Board of Central Pennsylvania

11:05 Ed Perry National Wildlife Federation

11:10 Don Robertson Isaac

Walton League of America

11:15 Rev. Horace W. Strand Chester Environmental Partnership

11:20 William Kramer Sierra Club

11:25 Dr. Scott Manaker American Thoracic Society

11:30 Chris Salmi New Jersey Department of Environmental Protection

11:35 Michael Bradley The Clean Energy Group

11:40 Anthony DiSorbo Individual

11:45 John McLaughlin Individual

11:50 Jack Miller Individual

11:45 Mariko Franz Individual

11:50 Paul J Mellon, Jr Novetas Solutions, LLC

11:55 Jim Black Partnership for Sustainability in Delaware

12:00 Kevin Pflug Sierra Club

12:05 Mervyn Kline Individual
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818

Time Name Affiliation

12:10 Alicia McDevitt MA Dept of Environmental Protection

12:15 Margaret Motheral Union of Concerned Scientists

12:20 Catherine Bowes National Wildlife Federation

12:25 Rabbi Kevin M. Kleinman Individual

12:30 Jamin Bogi Group Against Smog and Pollution

2:15 Nancy Parks SC/PA Chapter/Clean Air Committee

2:20 Jay Butera One Million Calls For Clean Energy

2:25 Katie Feeney Clean Air Council

2:30 Tyra Bryant-Stephens The Community Asthma Prevention Program

2:35 Candance Cheatham Individual

2:40 Mark Schmerling Individual

2:45 Dr. Rima Synnestivedt Sierra Club

2:50 Robert Cooper Union of Concerned Scientists

2:55 Sarah Bucic Delaware City Environmental Coalition

3:00 Dr. Kristen Welker-Hood Physicians for Social Responsibility

3:05 Gretchen DahlkemperAlfonsoIndividual

3:10 Judith Focareta

3:15 Sarah Landini Pittsburgh City Council

3:20 John Elwood Evangelical Environmental Network

3:25 Rev. Leah Schade The Evangelical Lutheran Church in America

3:30 Donna Henry Individual

3:35 Dr. Kevin Osterhoudt American Academy of Pediatrics

3:40 Theodore Carrington NAACP

3:45 Gina E. Wood Joint Center for Political and Economic Studies

3:50 John Hanger PA Dept of Environmental Protection

Hanger Consulting

3:55 Teresa Mendez-Quigley Women’s Health and Environmental Network

4:00 Amy Roe Individual

4:05 Geneva Boyer Individual

4:10 Shreena Bindra Individual

3:55 Coralie A. Pryde Individual

4:00 Josh Nelson CREDO Action from Working Assets

4:20 Jeff A McNelly ARIPPA

4:25 Brenda Afzal HCWH, U.S. Climate Policy Coordinator

4:30 Ed Braun City of Philadelphia Department of Public Health, Air 

Management Services

4:35 Mary Anne Rushlau Sierra Club

4:40 Jenny Kordick Individual

4:45 Bruce Alexander Exelon Corporation

4:50 Kate Etherington Philadelphia Physicians for Social Responsibility

4:55 Alex Milone

5:00 Mandy Warner Environmental Defense Fund

5:05 Katie Edwards Individual

5:10 Phillipa Strahm League of Conservation Voters

5:15 James Grande Sierra Club
12/09/11 DRAFT

819

Time Name Affiliation

5:20 James Kelley Individual

5:25 Freyda Black Individual

6:45 Al Rizzo American Lung Association

6:50 Matthew Pale PennEnvironment

6:55 Joe Parrish American Lung Association of New Jersey

7:00 Kendall Mackey National Wildlife Federation

7:05 Adam H. Cutler Public Health and Environmental Justice Law Clinic

7:10 Rachel Mentin Individual

7:15 Lynn Jaeger Eastern MontCo Action

7:20 Captain Joel Fogel Waterwatch International

7:25 Kate Zaidan Individual

7:30 Myriam Fallon Greenpeace

7:35 Christina Marie Glessner Individual

7:40 Rosa Michmya Individual

7:30 Dr. Gwen DuBois Chesapeake Physicians for Social Responsibility

7:35 Dr. Cindy Parker Chesapeake Physicians for Social Responsibility

7:40 Jeff Player Individual

7:45 Lisa Hastings Individual

7:50 Stephen Shapiro Chesapeake Physicians for Social Responsibility

7:55 Hollister Knowlton National Council of Churches and the Quaker Earthcare 

Ministry

8:00 Georgina Shanley Citizens United for Renewable Energy

8:05 Steven Fenichel Citizens United for Renewable Energy

8:10 Miranda Outman

8:15 Martin Hage Individual

8:20 Ann Dixon Penn Environment

8:25 Jay Fabrikant Individual
12/08/11 DRAFT

820

APPENDIX B: LIST OF COMMENTERS

DCN

Commenter 

Name Commenter Affiliation

EPA-HQ-OAR-2009-0234-6543-A1 Chris M. Hobson Southern Company

EPA-HQ-OAR-2009-0234-6584-A1 Sheila C. 

Holman

North Carolina Department of 

Environment and Natural 

Resources (NCDENR), Division 

of Air Quality (NC DAQ)

EPA-HQ-OAR-2009-0234-6637-A1 Naomi Goodman Electric Power Research Institute 

(EPRI)

EPA-HQ-OAR-2009-0234-6640-A1 A. MellingerBirdsongNone

EPA-HQ-OAR-2009-0234-8443-A1 Theresa Pugh American Public Power 

Association (APPA)

EPA-HQ-OAR-2009-0234-9738-A1 H. Tsourous None

EPA-HQ-OAR-2009-0234-10167-A1 Mike Roddy Seminole Electric Cooperative, Inc

EPA-HQ-OAR-2009-0234-10569-A1 Juan Ramirez Florida Electric Power 

Coordinating Group, Inc. (FCG)

EPA-HQ-OAR-2009-0234-10750-A1 John M. 

McManus

American Electric Power (AEP)

EPA-HQ-OAR-2009-0234-10821-A2 Michael J. Nasi Jackson Walker, LLP on behalf of 

Gulf Coast Lignite Coalition 

(GCLC)

EPA-HQ-OAR-2009-0234-10822-A2 L. Mohorovic, 

PhD

None

EPA-HQ-OAR-2009-0234-10942-A1 John D. Free Alabama Public Service 

Commission (APSC)

EPA-HQ-OAR-2009-0234-10943-A1 James O. Vick Gulf Power Company

EPA-HQ-OAR-2009-0234-10944-A1 Charles 

McPhedran

Citizens for Pennsylvania’s Future 

(PennFuture)

EPA-HQ-OAR-2009-0234-10987-A1 Rae Cronmiller, 

James J. Nipper

National Rural Electric 

Cooperative Association 

(NRECA), American Public 

Power Association (APPA)

EPA-HQ-OAR-2009-0234-11107-A1 Alan H. 

Lockwood

None

EPA-HQ-OAR-2009-0234-11889 Douglas K. 

Stevens

None

EPA-HQ-OAR-2009-0234-12050-A2 Thomas Au Clean Air Board of Central 

Pennsylvania (CAB)

EPA-HQ-OAR-2009-0234-12267-A1 S. W. Kuntz, 

PhD

EPA-HQ-OAR-2009-0234-12380-A2 Anonymous 

public comment

None
12/08/11 DRAFT

821

EPA-HQ-OAR-2009-0234-12462-A1 Lee Sprague Little River Band of Ottawa 

Indians

EPA-HQ-OAR-2009-0234-12798-A2 Alisa Gravitz Green America

EPA-HQ-OAR-2009-0234-12991-A1 Jeffrey Quick Utah Geological Survey, Utah 

Department of Natural Resources

EPA-HQ-OAR-2009-0234-12996-A2 Michael P. 

Halpin

Division of Air Resource 

Management, Florida Department 

of Environmental Protection 

(DEP)

EPA-HQ-OAR-2009-0234-13178-A1 Patrick 

O’Loughlin

Buckeye Power, Inc.

EPA-HQ-OAR-2009-0234-13526-A1 Susana M. 

Hildebrand

Texas Commision on 

Environmental Quality (TCEQ)

EPA-HQ-OAR-2009-0234-13529-A1 Byron T. 

Burrows

Tampa Electric Company (TECO)

EPA-HQ-OAR-2009-0234-13827-A1 Darrell Dorsey Kansas City Board of Public 

Utilities (BPU)

EPA-HQ-OAR-2009-0234-14017-A1 David R. Tripp 

and Dennis Lane

Stinson Morrison Hecker LLP on 

behalf of Westar Energy, Inc.

EPA-HQ-OAR-2009-0234-14069-A1 Raymond L. 

Evans

FirstEnergy Corp.

EPA-HQ-OAR-2009-0234-14070-A1 G. Vinson 

Hellwig

Michigan Department of 

Environmental Quality (MDEQ)

EPA-HQ-OAR-2009-0234-14070-A2 G. Vinson 

Hellwig

Michigan Department of 

Environmental Quality (MDEQ)

EPA-HQ-OAR-2009-0234-14115-A1 Dr. W. Soon None

EPA-HQ-OAR-2009-0234-14368-A1 Niger Innis Congress of Racial Equality on 

behalf of Affordable Power

Alliance (APA)

EPA-HQ-OAR-2009-0234-15002-A1 Barbara Gottlieb Physicians for Social 

Responsibility (PSR)

EPA-HQ-OAR-2009-0234-15160-A1 Dr. Lawrence 

Raymond

Clean Air Carolina

EPA-HQ-OAR-2009-0234-15182-A2 James Zorn Great Lakes Indian Fish and 

Wildlife Commission (GLIFWC)

EPA-HQ-OAR-2009-0234-15678-A2 William Skrabak Transportation and Environmental 

Services, Office of Environmental 

Quality, City of Alexandria, 

Virginia

EPA-HQ-OAR-2009-0234-15884-A2 Joseph Otis 

Minott

Clean Air Council

EPA-HQ-OAR-2009-0234-16121-A1 Cynthia Bearer, 

Board Chair

Children’s Environmental Health 

Network (CEHN)

EPA-HQ-OAR-2009-0234-16122-A1 Harold “Gus”

Frank

Forest County Potawatomi 

Community (FCPC)
12/08/11 DRAFT

822

EPA-HQ-OAR-2009-0234-16207-A1 Nancy F. Parks Sierra Club

EPA-HQ-OAR-2009-0234-16402-A1 Joseph S. Hensel Rochester Public Utilities

EPA-HQ-OAR-2009-0234-16403-A1 Paul Bailey American Coalition for Clean Coal 

Electricity (ACCCE)

EPA-HQ-OAR-2009-0234-16404-A1 Charles D. 

Connor

American Lung Association

EPA-HQ-OAR-2009-0234-16405-A1 Art Graham Florida Public Service 

Commission (FPSC)

EPA-HQ-OAR-2009-0234-16469-A1 Bill Banig and 

Jim Hunter

Unions for Jobs and the 

Environment (UJAE)

EPA-HQ-OAR-2009-0234-16513-A1 Daniel C. Esty Connecticut Department of Energy

and Environmental Protection

EPA-HQ-OAR-2009-0234-16549-A1 Lance Brown et 

al.

Partnership for Affordable Clean 

Energy (PACE)

EPA-HQ-OAR-2009-0234-16626-A1 Congressman 

John D. Dingell, 

et al.

Congress of the United States

EPA-HQ-OAR-2009-0234-16627-A1 Illona A. 

Jeffcoat-Sacco

North Dakota Public Service 

Commission

EPA-HQ-OAR-2009-0234-16630-A1 Ellen Rendulich Citizens Against Ruining the 

Environment (CARE)

EPA-HQ-OAR-2009-0234-16682-A1 Juliet Cohen Upper Chattahoochee 

Riverkeepers

EPA-HQ-OAR-2009-0234-16705-A2 William H. 

Conrad

City of Newberry, Florida

EPA-HQ-OAR-2009-0234-16738-A1 Leonard Levin Electric Power Research Institute 

(EPRI)

EPA-HQ-OAR-2009-0234-16822-A1 Senator James A. 

Inhofe, et al.

Congress of the United States

EPA-HQ-OAR-2009-0234-16824-A2 Chris Clark Georgia Chamber of Commerce

EPA-HQ-OAR-2009-0234-16826-A1 Brian Saylor American Lung Association

EPA-HQ-OAR-2009-0234-16844-A1 John A. Arway Pennsylvania Fish and Boat 

Commission (PFBC)

EPA-HQ-OAR-2009-0234-16849-A1 Rebecca Heffren Empire District Electric Company

EPA-HQ-OAR-2009-0234-16850-A2 Cindy B. Miller Florida Public Service 

Commission

EPA-HQ-OAR-2009-0234-16856-A1 Tom Bloss Pritchard Electric

EPA-HQ-OAR-2009-0234-16857-A1 Caroline Choi Progress Energy

EPA-HQ-OAR-2009-0234-16858-A1 R.D. Cross Gilmer, TX

EPA-HQ-OAR-2009-0234-16859-A1 Leo M. Drozdoff Environmental Council of the 

States (ECOS)

EPA-HQ-OAR-2009-0234-16861-A1 Thomas R. Kuhn Edison Electric Institute (EEI)

EPA-HQ-OAR-2009-0234-16872-A1 Tony Clark National Association of 

Regulatory Utility Commissioners 
12/08/11 DRAFT

823

(NARUC)

EPA-HQ-OAR-2009-0234-16873-A1 Thomas W. 

McNamee

Public Utilities Commission Ohio 

(PUCO)

EPA-HQ-OAR-2009-0234-17003-A1 Scott H. Segal Electric Reliability Coordinating 

Council (ERCC)

EPA-HQ-OAR-2009-0234-17004-A1 Billy Ray Jones City of Nashville, Arkansas 

EPA-HQ-OAR-2009-0234-17022-A1 Charles Waldon Town of Stonewall, Louisiana

EPA-HQ-OAR-2009-0234-17026-A1 David R. 

Rockett, Jr.

Greater Bossier Economic 

Development Foundation

EPA-HQ-OAR-2009-0234-17028-A1 Carson C. Joines City of Carthage, Texas

EPA-HQ-OAR-2009-0234-17055-A1 Nicholas A. 

Brown

Southwest Power Pool, Inc. (SPP)

EPA-HQ-OAR-2009-0234-17110-A1 Michael Bradley Clean Energy Group’s Clean Air 

Policy Initiative

EPA-HQ-OAR-2009-0234-17114-A1 Rosemary

Elebash

National Federation of 

Independent Business (NFIB)

EPA-HQ-OAR-2009-0234-17123-A1 Andrew J. Such Michigan Manufacturers 

Association (MMA)

EPA-HQ-OAR-2009-0234-17137-A1 Mike Arms Association of Tennessee Valley

Governments (ATVG)

EPA-HQ-OAR-2009-0234-17157-A1 Evelyn Fang Leadership Council Alaska, 

American Lung Association

EPA-HQ-OAR-2009-0234-17174-A2 Myra C. Reece Bureau of Air Quality, South 

Carolina Department of Health 

and Environmental Control 

(DHEC)

EPA-HQ-OAR-2009-0234-17191-A2 Terry Hogan Wabash Valley Power Association 

(WVPA)

EPA-HQ-OAR-2009-0234-17197-A1 Paul Schulz Platte River Power Authority

EPA-HQ-OAR-2009-0234-17254-A1 Public Hearing 

in Atlanta, GA 

on May 26, 2011

EPA-HQ-OAR-2009-0234-17265-A1 Michael P. 

Halpin

Division of Air Resource 

Management, Florida Department 

of Environmental Protection 

(FDEP)

EPA-HQ-OAR-2009-0234-17270 V. Watson None

EPA-HQ-OAR-2009-0234-17278-A1 Donald H. Picard Southeast Volusia Audubon 

Society chapter of the National 

Audubon Society

EPA-HQ-OAR-2009-0234-17279 Mark Mueller St. Petersburg chapter of the 

National Audubon Society

EPA-HQ-OAR-2009-0234-17281-A2 Kenneth J. 

Schilling

Washington Electric Cooperative, 

Inc.
12/08/11 DRAFT

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EPA-HQ-OAR-2009-0234-17283-A1 Carli Smith et al. Cooper Environmental Services, 

LLC (CES)

EPA-HQ-OAR-2009-0234-17291 Anonymous 

public comment

None

EPA-HQ-OAR-2009-0234-17294 L. McClain None

EPA-HQ-OAR-2009-0234-17295-A2 L. J. Joey Durel, 

Jr.,

Lafayette Consolidated 

Government on behalf of 

Lafayette Utilities System

EPA-HQ-OAR-2009-0234-17296-A2 Marshall D. 

Moore

Chemtura Corporation

EPA-HQ-OAR-2009-0234-17297-A2 Orjiakor N. 

Isiogu, Monica 

Martinez, and 

Greg R. White

Department of Licensing and 

Regulatory Affairs, Michigan 

Public Service Commission

EPA-HQ-OAR-2009-0234-17299-A2 George Carter Paulding Putnam Electric 

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-17305-A2 Gerald Lauer Consolidated Electric Cooperative, 

Inc.

EPA-HQ-OAR-2009-0234-17306-A2 Glenn W. Miller Holmes-Wayne Electric 

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-17316-A2 B. Machaver None

EPA-HQ-OAR-2009-0234-17381 Jon Hinck Maine House of Representatives

EPA-HQ-OAR-2009-0234-17383-A1 John T. Graves Minnkota Power Cooperative, Inc.

EPA-HQ-OAR-2009-0234-17385-A2 Floyd 

DesChamps

Alliance to Save Energy

EPA-HQ-OAR-2009-0234-17386-A2 Richard Vélez Taunton Municipal Lighting Plant 

(TMLP)

EPA-HQ-OAR-2009-0234-17400-A1 Eugene F. 

Wallace and 

Paul H. 

Beckhusen

Coldwater Board of Public 

Utilities, City of Coldwater, 

Michigan

EPA-HQ-OAR-2009-0234-17401-A1 Jay Vavricek and 

Timothy

Luchsinger

City of Grand Island, Nebraska

EPA-HQ-OAR-2009-0234-17402-A1 Basil G. 

Constantelos

Edison Mission Energy, LLC

EPA-HQ-OAR-2009-0234-17403-A1 Anthony N. 

Jacobs

International Brotherhood of 

Boilermakers, Iron Ship Builders, 

Blacksmiths, Forgers and Helpers 

and AFL-CIO (Boilermakers 

Union)

EPA-HQ-OAR-2009-0234-17405-A1 Jennifer Lust Brainerd Lakes Area Audubon 

Society

EPA-HQ-OAR-2009-0234-17406-A1 Raymond Burns Rogers-Lowell Area Chamber of 

Commerce
12/08/11 DRAFT

825

EPA-HQ-OAR-2009-0234-17408-A1 Public Hearing 

in Chicago, IL 

on May 24, 2011

EPA-HQ-OAR-2009-0234-17409-A1 Public Hearing 

in Philadelphia, 

PA on May 24, 

2011

EPA-HQ-OAR-2009-0234-17608-A1 Winslow 

Sargeant

Small Business Administration 

(SBA)

EPA-HQ-OAR-2009-0234-17620-A1 S. William 

Becker

National Association of Clean Air 

Agencies (NACAA)

EPA-HQ-OAR-2009-0234-17621-A1 Paul Chu Electric Power Research Institute

(EPRI)

EPA-HQ-OAR-2009-0234-17622-A1 David Foerter Institute of Clean Air Companies 

(ICAC)

EPA-HQ-OAR-2009-0234-17623-A1 Brian H. Moeck Large Public Power Council 

(LPPC)

EPA-HQ-OAR-2009-0234-17625-A1 Ronald Poltak New England Interstate Water 

Pollution Control Commission 

(NEIWPCC)

EPA-HQ-OAR-2009-0234-17626-A1 Robert G. Hilton Power Technologies for 

Government Affairs, Alstom

EPA-HQ-OAR-2009-0234-17627-A1 Raymond L. 

Evans

FirstEnergy Corp. (FE)

EPA-HQ-OAR-2009-0234-17628-A1 Les Oakes King & Spalding LLP on behalf of 

Power4Georgians, LLC (P4G)

EPA-HQ-OAR-2009-0234-17629-A1 John V. Corra Wyoming Department of 

Environmental Quality

EPA-HQ-OAR-2009-0234-17637-A1 Ruthanne F. 

Calabrese

Northeast Utilities System 

Company (NUSCO)

EPA-HQ-OAR-2009-0234-17638-A1 James O. Vick Florida Electric Power 

Coordinating Group, Inc. (FCG)

EPA-HQ-OAR-2009-0234-17639-A1 Terry E. 

Branstad, 

Governor

State of Iowa

EPA-HQ-OAR-2009-0234-17640-A1 Paul A. Yost National Association of 

Manufacturers (NAM)

EPA-HQ-OAR-2009-0234-17648-A2 Kathleen Barron Exelon Corporation (Part 1 of 3)

EPA-HQ-OAR-2009-0234-17654-A1 David E. 

Meehan

Sunbury Generation LP

EPA-HQ-OAR-2009-0234-17655-A1 David M. Fraley City Utilities of Springfield, 

Missouri (CU)

EPA-HQ-OAR-2009-0234-17656-A1 Holly Propst Western Business Roundtable

EPA-HQ-OAR-2009-0234-17657-A1 Joan Small Gilmer Area Chamber of 

Commerce

EPA-HQ-OAR-2009-0234-17658-A1 Lynda Munkres, Morris County, TX
12/08/11 DRAFT

826

Judge

EPA-HQ-OAR-2009-0234-17659-A1 Kelly R. Hall Real East Texas Longview 

Chamber of Commerce

EPA-HQ-OAR-2009-0234-17660-A1 J. W. Fullen, 

Mayor

City of Henderson, TX

EPA-HQ-OAR-2009-0234-17661-A1 Charles Thomas Carthage Economic Development 

Corporation

EPA-HQ-OAR-2009-0234-17674-A1 Charles L. 

Franklin

Akin Gump Strauss Hauer & Feld 

LLP on behalf of Gila River 

Indian Community

EPA-HQ-OAR-2009-0234-17675-A1 Brian Brazil TransAlta Centralia Generation 

LLC

EPA-HQ-OAR-2009-0234-17676-A1 Ellen Bloom et 

al.

Consumers Union

EPA-HQ-OAR-2009-0234-17677-A1 Tim Mordhorst Black Hills Corporation (BH)

EPA-HQ-OAR-2009-0234-17678-A1 Eric Redman Summit Texas Clean Energy, LLC

EPA-HQ-OAR-2009-0234-17679-A1 David Evers Biodiversity Research Institute 

(BRI)

EPA-HQ-OAR-2009-0234-17680-A1 David 

Chadwick, 

Mayor

City of Center, TX

EPA-HQ-OAR-2009-0234-17681-A1 Farzie Shelton Lakeland Electric

EPA-HQ-OAR-2009-0234-17682-A1 Steven C. Borell Alaska Miners Association (AMA)

EPA-HQ-OAR-2009-0234-17683-A1 Tim Gestwicki 

and Dick 

Hamilton

North Carolina (NC) Wildlife 

Federation and North Carolina 

Camouflage Coalition

EPA-HQ-OAR-2009-0234-17684-A1 Judy Sewell Henderson Area Chamber of 

Commerce

EPA-HQ-OAR-2009-0234-17685-A1 Bobby Beane Kilgore Economic Development 

Corporation

EPA-HQ-OAR-2009-0234-17686-A1 Alan Grantham 

and Connie 

Ware

Marshall Chamber of Commerce

EPA-HQ-OAR-2009-0234-17689-A1 Rae E. 

Cronmiller

The National Rural Electric 

Cooperative Association 

(NRECA)

EPA-HQ-OAR-2009-0234-17690-A1 Roger Caiazza Environmental Energy Alliance of 

New York, LLC

EPA-HQ-OAR-2009-0234-17691-A1 John S. Lyons Commonwealth of Kentucky, 

Division for Air Quality

EPA-HQ-OAR-2009-0234-17692-A1 Daniel L. Juneau Louisiana Association of Business 

and Industry (LABI)

EPA-HQ-OAR-2009-0234-17693-A1 Stephen J. 

Metcalf and 

Susan 

Longview Economic Development 

Corporation
12/08/11 DRAFT

827

Mazarakes-Gill

EPA-HQ-OAR-2009-0234-17694-A1 Lynda Rauscher Mineola, Texas, Community

Development Department

EPA-HQ-OAR-2009-0234-17695-A1 Sue Henderson Henderson Economic 

Development Corporation

EPA-HQ-OAR-2009-0234-17696-A2 Linda Whelan Dynegy, Inc.

EPA-HQ-OAR-2009-0234-17697-A1 Edward J. B. 

Calvo

Governor of Guam on behalf of 

Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-17698-A1 Joaquin C. 

Flores

Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-17699-A1 Alexander 

Jackson

Fond du Lac Band of Lake 

Superior Chippewa

EPA-HQ-OAR-2009-0234-17700-A1 R. E. Spradlin, 

III, Mayor

Kilgore, TX

EPA-HQ-OAR-2009-0234-17701-A1 Robin J. Lunt National Association of 

Regulatory Utility Commissioners 

(NARUC)

EPA-HQ-OAR-2009-0234-17702-A1 Robert E. 

Hunzinger

Gainesville Regional Utilities 

(GRU)

EPA-HQ-OAR-2009-0234-17703-A1 Ronald W. Gore Alabama Department of 

Environmental Management 

(ADEM)

EPA-HQ-OAR-2009-0234-17704-A1 Angela 

Rodriguez

City Public Service (CPS Energy)

EPA-HQ-OAR-2009-0234-17705-A1 Kevin Wanttaja Salt River Project (SRP)

EPA-HQ-OAR-2009-0234-17707-A1 Jack Pelfrey Eufaula Barbour County Chamber 

of Commerce

EPA-HQ-OAR-2009-0234-17708-A1 E. F. Whitus, 

Mayor

Mineola, Texas

EPA-HQ-OAR-2009-0234-17709-A1 Bruce Caswell, 

State Senator

State of Michigan

EPA-HQ-OAR-2009-0234-17710-A1 Senator Thomas 

C. Ada

Committee on Utilities, 

Transportation, Public Works, and 

Veterans Affairs of the 31st Guam 

Legislature

EPA-HQ-OAR-2009-0234-17711-A1 Paul Noe and 

Robert 

Glowinski

American Forest & Paper 

Association (AF&PA) and 

American Wood Council (AWC)

EPA-HQ-OAR-2009-0234-17712-A1 Leonard F. 

Hopkins

Southern Illinois Power

Cooperative (SIPC)

EPA-HQ-OAR-2009-0234-17713-A1 Niger Innis Affordable Power Alliance

EPA-HQ-OAR-2009-0234-17714-A1 Nicholas M. 

Dernik

Northern Indiana Public Service 

Company (NIPSCO)

EPA-HQ-OAR-2009-0234-17715-A1 David E. Jones Ohio Valley Electric Corporation 

(OVEC)/Indiana Kentucky
12/08/11 DRAFT

828

Electric Corporation (IKEC)

EPA-HQ-OAR-2009-0234-17716-A1 Dennis Lane Stinson Morrison Hecker LLP on 

behalf of Westar Energy, Inc.

EPA-HQ-OAR-2009-0234-17717-A1 Lorenz Walker, 

Mayor

Bossier City, LA

EPA-HQ-OAR-2009-0234-17718-A1 Reid T. Clemmer PPL Corporation

EPA-HQ-OAR-2009-0234-17719-A1 Martha E. 

Rudolph

Colorado Department of Public 

Health and Environment

EPA-HQ-OAR-2009-0234-17720-A1 Angila M. 

Retherford

Vectren Corporation

EPA-HQ-OAR-2009-0234-17721-A1 Winston & 

Strawn LLP

on behalf of Chem-Mod LLC

EPA-HQ-OAR-2009-0234-17722-A1 Mary Jo Roth Great River Energy (GRE)

EPA-HQ-OAR-2009-0234-17723-A1 David M. Fraley City Utilities of Springfield, 

Missouri (CU)

EPA-HQ-OAR-2009-0234-17724-A1 John W. Dwyer Lignite Energy Council (LEC)

EPA-HQ-OAR-2009-0234-17725-A1 Verne Shortell NRG Energy, Inc.

EPA-HQ-OAR-2009-0234-17727-A1 John Proos, et 

al., State Senate

State of Michigan

EPA-HQ-OAR-2009-0234-17728-A1 Douglas J. Fulle Oglethorpe Power Corporation

EPA-HQ-OAR-2009-0234-17729-A1 Bruce Parker Electric Energy, Inc. (EEI)

EPA-HQ-OAR-2009-0234-17730-A1 Barbara A. Walz Tri-State Generation & 

Transmission Association, Inc.

EPA-HQ-OAR-2009-0234-17731-A1 Parthenia B. 

Evans and 

Dennis Lane

Stinson Morrison Hecker LLP on 

behalf of the Kansas City Board of 

Public Utilities (BPU)

EPA-HQ-OAR-2009-0234-17732-A1 Stephen B. 

Etsitty

Navajo Nation Environmental 

Protection Agency

EPA-HQ-OAR-2009-0234-17733-A1 Harold “Gus”

Frank and James 

Crawford

Forest County Potawatomi 

Community (FCPC)

EPA-HQ-OAR-2009-0234-17734-A1 Ed Williams Novinda Corporation

EPA-HQ-OAR-2009-0234-17735-A1 Wayne E. 

Penrod

Coalition of New Units

EPA-HQ-OAR-2009-0234-17736-A1 Ryan D. Elliott Shumaker, Loop & Kendrick, LLP 

on behlaf of Ohio Utility Group

EPA-HQ-OAR-2009-0234-17737-A1 Arie Hoekstra Tucson Electric Power Company

(TEP)

EPA-HQ-OAR-2009-0234-17738-A1 Derek R. 

McDonald

Baker Botts LLP on behalf of the 

IPA Coleto Creek LLC (IPA)

EPA-HQ-OAR-2009-0234-17739-A1 Neal J. Cabral McguireWoods LLP on behalf of 

CONSOL Energy, Inc.
12/08/11 DRAFT

829

EPA-HQ-OAR-2009-0234-17740-A1 William M. 

Bumpers

Baker Botts L.L.P., on behalf of 

Class of 1985 Regulatory 

Response Group

EPA-HQ-OAR-2009-0234-17741-A1 Stephen R. 

Lindauer

The Association of Union 

Constructors (TAUC)

EPA-HQ-OAR-2009-0234-17743-A1 E. Scott Pruitt, 

Attorney General

State of Oklahoma

EPA-HQ-OAR-2009-0234-17745-A1 Samuel S. Olens, 

Attorney General

State of Georgia

EPA-HQ-OAR-2009-0234-17747-A1 Krag Petterson Pall Corporation

EPA-HQ-OAR-2009-0234-17748-A1 Charles L. Hardy 

Jr., Mayor

City of Commerce, Georgia

EPA-HQ-OAR-2009-0234-17749-A1 Jeff Lewis Fitzgerald Water, Light & Bond 

Commission

EPA-HQ-OAR-2009-0234-17750-A1 Charlie Denham Crisp County Power Commission

EPA-HQ-OAR-2009-0234-17751-A1 William L. 

Kovacs

U.S. Chamber of Commerce

EPA-HQ-OAR-2009-0234-17752-A1 Mark Thoma Otter Tail Power Company

EPA-HQ-OAR-2009-0234-17753-A1 Jason D. Bostic West Virginia Coal Association 

(WVCA)

EPA-HQ-OAR-2009-0234-17754-A1 Jeff McNelly ARIPPA

EPA-HQ-OAR-2009-0234-17755-A1 Eddie Terrill Oklahoma Department of 

Environmental Quality (ODEQ)

EPA-HQ-OAR-2009-0234-17756-A1 Paul M. Ling Kansas City Power & Light 

Company (KCP&L

EPA-HQ-OAR-2009-0234-17757-A1 Patrick 

O’Loughlin

Buckeye Power, Inc.

EPA-HQ-OAR-2009-0234-17758-A1 Thomas R. Kuhn Edison Electric Institute (EEI)

EPA-HQ-OAR-2009-0234-17760-A1 William M. 

Bumpers

Baker Botts L.L.P., on behalf of 

Class of 1985 Regulatory 

Response Group

EPA-HQ-OAR-2009-0234-17761-A1 Cathy S. 

Woollums

Mid American Energy Holdings 

Company

EPA-HQ-OAR-2009-0234-17763-A1 Camille Payne, 

Mayor

Thomasville, GA

EPA-HQ-OAR-2009-0234-17765-A1 John T. Heard The Virginia Coal Association, 

Inc. (VCA)

EPA-HQ-OAR-2009-0234-17766-A1 Dennis M. 

Grzezinski

Midwest Environmental 

Advocates, Inc. (MEA)

EPA-HQ-OAR-2009-0234-17767-A1 PJ Becker City of Springfield, Illinois - City

Water Light & Power (CWLP)

EPA-HQ-OAR-2009-0234-17768-A1 Michael A. 

Livermore et al.

Institute for Policy Integrity, New 

York University School of Law

EPA-HQ-OAR-2009-0234-17769-A1 Mike Roddy Seminole Electric Cooperative, 

Inc.
12/08/11 DRAFT

830

EPA-HQ-OAR-2009-0234-17770-A1 Bruce W. 

Ramme

We Energies

EPA-HQ-OAR-2009-0234-17771-A1 Dave Martin New Mexico Environment 

Department (NMED)

EPA-HQ-OAR-2009-0234-17772-A1 JoAnne Rau Dayton Power and Light Company

(DP&L)

EPA-HQ-OAR-2009-0234-17773-A1 Leonard Levin Electric Power Research Institute 

(EPRI)

EPA-HQ-OAR-2009-0234-17774-A1 Jay Hudson Santee Cooper

EPA-HQ-OAR-2009-0234-17775 None Utility Air Regulatory Group 

(UARG)

EPA-HQ-OAR-2009-0234-17775-A1 Lee B. Zeugin et. 

al Hunton and 

Williams LLP

on behalf of Utility Air Regulatory

Group (UARG)

EPA-HQ-OAR-2009-0234-17776-A1 Patricia D. Horn Oklahoma Gas And Electric 

Company (OGandE)

EPA-HQ-OAR-2009-0234-17777-A1 Hunton and 

Williams LLP

on behalf of Utility Air Regulatory

Group (UARG)

EPA-HQ-OAR-2009-0234-17778-A1 Willie E. Burns, 

Mayor

City of Washington, Georgia

EPA-HQ-OAR-2009-0234-17779-A1 Albert Doughty, 

Mayor

Town of Benton, Louisiana

EPA-HQ-OAR-2009-0234-17780-A1 Mary Jo Graham Oakmoss Education

EPA-HQ-OAR-2009-0234-17781-A1 Hunton and 

Williams LLP

on behalf of Utility Air Regulatory

Group (UARG)

EPA-HQ-OAR-2009-0234-17782-A1 Rosemary

Elebash

National Federation of 

Independent Business (NFIB)

EPA-HQ-OAR-2009-0234-17783-A1 Kenneth D. 

Roberts

City of Barnesville, Georgia

EPA-HQ-OAR-2009-0234-17784-A1 Hunton and 

Williams LLP

on behalf of Utility Air Regulatory

Group (UARG)

EPA-HQ-OAR-2009-0234-17785-A1 Hunton and 

Williams LLP

on behalf of Utility Air Regulatory

Group (UARG)

EPA-HQ-OAR-2009-0234-17786-A1 Lauren Freeman Hunton & Williams LLP on behalf 

of Utility Air Regulatory Group

EPA-HQ-OAR-2009-0234-17787-A1 Lauren Freeman Hunton & Williams LLP on behalf 

of Utility Air Regulatory Group

EPA-HQ-OAR-2009-0234-17788-A1 Scott 

Getzschman and 

Derril Marshall

Fremont Department of Utilities, 

Nebraska

EPA-HQ-OAR-2009-0234-17789-A2 Scott M. Lorey Adirondack Council

EPA-HQ-OAR-2009-0234-17790-A2 William Rogers DTE Energy

EPA-HQ-OAR-2009-0234-17791-A2 Robin J. Lunt National Association of 

Regulatory Utility Commissioners 

(NARUC)
12/08/11 DRAFT

831

EPA-HQ-OAR-2009-0234-17792-A1 L. J. “Joey”

Durel, Jr.

Lafayette Consolidated 

Government on behalf of 

Lafayette Utilities System et al.

EPA-HQ-OAR-2009-0234-17795-A1 Brian W. Green GenOn Energy, Inc.

EPA-HQ-OAR-2009-0234-17796-A1 J. Jared Snyder New York State Department of 

Environmental Conservation 

(NYSDEC)

EPA-HQ-OAR-2009-0234-17797-A1 Eldon Long, 

Mayor

City of Lowell, Arkansas

EPA-HQ-OAR-2009-0234-17798-A1 William B. 

Baumann

Wisconsin Department of Natural 

Resources (WDNR)

EPA-HQ-OAR-2009-0234-17799-A1 Paul Bailey American Coalition for Clean 

Electricity (ACCCE)

EPA-HQ-OAR-2009-0234-17800 Steven C. 

Whitworth

Ameren Corporation

EPA-HQ-OAR-2009-0234-17800-A1 Steven C. 

Whitworth

Ameren Corporation

EPA-HQ-OAR-2009-0234-17801-A1 Steve Meyers General Electric Company (GE)

EPA-HQ-OAR-2009-0234-17803-A1 Robert D. Teetz National Grid

EPA-HQ-OAR-2009-0234-17804-A1 Michael L. 

Krancer

Pennsylvania Department of 

Environmental Protection (DEP)

EPA-HQ-OAR-2009-0234-17805-A1 Abbie Krebsbach Montana-Dakota Utilities 

Company

EPA-HQ-OAR-2009-0234-17806-A1 Henry R. Darwin Arizona Department of 

Environmental Quality (ADEQ)

EPA-HQ-OAR-2009-0234-17807 Thomas L. 

Hernandez

Tampa Electric Company (TEC)

EPA-HQ-OAR-2009-0234-17807-A1 Thomas L. 

Hernandez

Tampa Electric Company (TEC)

EPA-HQ-OAR-2009-0234-17808-A1 Michael Bradley The Clean Energy Group

EPA-HQ-OAR-2009-0234-17809-A1 Mike Roddy Seminole Electric Cooperative, 

Inc.

EPA-HQ-OAR-2009-0234-17810-A1 Regina Hopper America’s Natural Gas Alliance 

(ANGA)

EPA-HQ-OAR-2009-0234-17811-A1 J. Dorgan and M. 

D. Gibson 

Lindblom on 

behalf of 

Michael 

Churchman

Alabama Environmental Council 

et al.

EPA-HQ-OAR-2009-0234-17812-A1 Robert D. 

Bessette

Council of Industrial Boiler 

Owners (CIBO)

EPA-HQ-OAR-2009-0234-17813-A1 Joseph G. Eutizi San Miguel Electric Cooperative, 

Inc.

EPA-HQ-OAR-2009-0234-17814-A1 James O. Vick Gulf Power Company
12/08/11 DRAFT

832

EPA-HQ-OAR-2009-0234-17815-A1 John W. Fainter, 

Jr.

Association of Electric Companies 

of Texas (AECT)

EPA-HQ-OAR-2009-0234-17816-A1 Michael L. Jones Puget Sound Energy, Inc.

EPA-HQ-OAR-2009-0234-17817-A1 Wayne E. 

Penrod

Sunflower Electric Power 

Corporation

EPA-HQ-OAR-2009-0234-17818-A2 Ronald A. 

Amirikian

State of Delware, Department of 

Natural Resources & 

Environmental Control, Division 

of Air and Waste Management

EPA-HQ-OAR-2009-0234-17819-A2 Keith Harley Environment Illinois, Chicago 

Legal Clinic, Inc. on behalf of 

Environmental Law and Policy

Center (ELPC)

EPA-HQ-OAR-2009-0234-17820-A1 Pamela F. 

Faggert

Dominion

EPA-HQ-OAR-2009-0234-17820-A2 Pamela F. 

Faggert

Dominion

EPA-HQ-OAR-2009-0234-17821-A1 John L. Stowell Duke Energy

EPA-HQ-OAR-2009-0234-17822-A1 Richard Barr, 

Mayor

Adel, GA

EPA-HQ-OAR-2009-0234-17823-A1 Woodrow 

Wilson, Jr.

Parrish of Caddo

EPA-HQ-OAR-2009-0234-17824-A1 Peter B. Storey Childersburg Chamber of 

Commerce

EPA-HQ-OAR-2009-0234-17825-A1 Keith Brady, 

Mayor

Newnan, GA

EPA-HQ-OAR-2009-0234-17826-A1 Peter L. Banks, 

Mayor

Barnesville, GA

EPA-HQ-OAR-2009-0234-17827-A1 J.D. Herring Quitman, GA

EPA-HQ-OAR-2009-0234-17829-A1 Fred Hlava, Gordon, NE

EPA-HQ-OAR-2009-0234-17830-A1 Dan Leise Cedar-Knox Public Power District 

(CKPPD)

EPA-HQ-OAR-2009-0234-17831-A1 Neal D. Suess Loup River Public Power District

EPA-HQ-OAR-2009-0234-17833-A1 David P. Hackett 

and Jessica 

Mitchell Wicha, 

Baker & 

McKenzie LLP

on behalf of Michael A. Gardner 

Gypsum Association

EPA-HQ-OAR-2009-0234-17834-A1 Jon Bruning State of Nebraska et al.

EPA-HQ-OAR-2009-0234-17835-A1 David M. Fraley City Utilities of Springfield, 

Missouri (CU)

EPA-HQ-OAR-2009-0234-17836 John T. Suttles Southern Environmental Law 

Center (SELC)

EPA-HQ-OAR-2009-0234-17836-A1 John T. Suttles, 

Jr.,

Southern Environmental Law 

Center (SELC) and Southeast 
12/08/11 DRAFT

833

Environmental Organizations

EPA-HQ-OAR-2009-0234-17837-A2 Thomas 

Holbrook, 

Illinois State 

Representative

Illinois General Assembly, 113th 

District

EPA-HQ-OAR-2009-0234-17838-A2 R. J. Shaffer Scrubgrass Generating Company

L.P.

EPA-HQ-OAR-2009-0234-17839-A2 Wallace L. 

Taylor

Sierra Club Iowa Chapter

EPA-HQ-OAR-2009-0234-17840-A2 William D. 

Bissett

Kentucky Coal Association (KCA)

EPA-HQ-OAR-2009-0234-17841-A2 Craig S. 

Campbell

Lafarge North America-Cement 

Division

EPA-HQ-OAR-2009-0234-17842-A2 Kevin Cramer North Dakota Public Service 

Commission (NDPSC) et al.

EPA-HQ-OAR-2009-0234-17843-A2 Arthur N. Marin Northeast States for Coordinated 

Air Use Management 

(NESCAUM)

EPA-HQ-OAR-2009-0234-17844-A2 Mindy Lubber Ceres

EPA-HQ-OAR-2009-0234-17845-A2 C. Richard Neff Cogentrix Energy, LLC

EPA-HQ-OAR-2009-0234-17846-A2 Alex Jackson Fond du Lac Band of Lake 

Superior Chippewa

EPA-HQ-OAR-2009-0234-17848-A2 Travis J. Blake Division of Air Pollution Control, 

Tennessee Department of 

Environment and Conservation

EPA-HQ-OAR-2009-0234-17849-A2 Garry A. Mbiad Guernsey-Muskingum Electric 

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-17850-A1 Jeff A. McNelly ARIPPA

EPA-HQ-OAR-2009-0234-17851-A2 Melvin E. 

Keener

Coalition for Responsible Waste 

Incineration (CRWI)

EPA-HQ-OAR-2009-0234-17852-A2 Gregory C. 

Staple

American Clean Skies Foundation 

(ACSF)

EPA-HQ-OAR-2009-0234-17853-A2 Matt Most Encana Natural Gas, Inc.

EPA-HQ-OAR-2009-0234-17854-A1 Kristina Curtis Green Century Capital 

Management

EPA-HQ-OAR-2009-0234-17855-A2 David A. 

Kellermeyer

Northern Star Generation, LLC

EPA-HQ-OAR-2009-0234-17856-A2 Scott J. Nally Ohio Environmental Protection 

Agency (Ohio EPA)

EPA-HQ-OAR-2009-0234-17857-A2 John A. Benedict West Virginia Department of 

Environmental Protection, 

Division of Air Quality

EPA-HQ-OAR-2009-0234-17866-A1 Jackie L.

Wilson, Mayor

City of Douglas, Georgia
12/08/11 DRAFT

834

EPA-HQ-OAR-2009-0234-17867-A2 Stephen 

Quennoz

Portland General Electric 

Company (PGE)

EPA-HQ-OAR-2009-0234-17868-A2 Alex Hofmann 

and Theresa 

Pugh

American Public Power 

Association (APPA)

EPA-HQ-OAR-2009-0234-17869-A1 Seth Jacobson Mercury Free Partnership (MFP)

EPA-HQ-OAR-2009-0234-17870-A2 Randall R. 

LaBauve

NextEra Energy Inc.

EPA-HQ-OAR-2009-0234-17871-A2 Dennis P. 

Laybourn

Newmont Nevada Energy

Investment, LLC (NNEI)

EPA-HQ-OAR-2009-0234-17872-A2 W. Lawrence 

Givens

Umatilla County Board of County

Commissioners, Oregon

EPA-HQ-OAR-2009-0234-17873-A2 Frank P. Prager Xcel Energy, Inc.

EPA-HQ-OAR-2009-0234-17875-A1 Susan Lyon Center for American Progress

EPA-HQ-OAR-2009-0234-17876-A2 Deborah Fohr 

Levchak

Basin Electric Power Cooperative 

(BEPC)

EPA-HQ-OAR-2009-0234-17877-A1 Todd A. Tolbert Associated Electric Cooperative, 

Inc.

EPA-HQ-OAR-2009-0234-17877-A2 Todd A. Tolbert Associated Electric Cooperative, 

Inc.

EPA-HQ-OAR-2009-0234-17878-A3 Ben Yamagata Coal Utilization Research Council 

(CURC)

EPA-HQ-OAR-2009-0234-17879-A2 Thomas S. 

Howard

Domtar

EPA-HQ-OAR-2009-0234-17880-A2 Adrienne 

Esposito

Citizens Campaign for the 

Environment (CCE)

EPA-HQ-OAR-2009-0234-17881-A2 Louis P. 

Pocalujka

Consumers Energy

EPA-HQ-OAR-2009-0234-17882-A2 Shelley Vinyard Environment America et al.

EPA-HQ-OAR-2009-0234-17883-A2 Kevin Cahill IPR-GDF SUEZ Energy

Generation NA, Inc.

EPA-HQ-OAR-2009-0234-17884-A2 Peter Glaser Troutman Sanders LLP on be half 

of Peabody Energy Company

EPA-HQ-OAR-2009-0234-17885-A1 Leonard F. 

Hopkins

Southern Illinois Power 

Cooperative (SIPC)

EPA-HQ-OAR-2009-0234-17886-A2 John W. Myers Tennessee Valley Authority

(TVA)

EPA-HQ-OAR-2009-0234-17887-A2 James E. Melia Pennsylvania Public Utility

Commission (PAPUC)

EPA-HQ-OAR-2009-0234-17889-A1 Kevin Pollard Norris Public Power

EPA-HQ-OAR-2009-0234-17890-A1 Duncan 

Kinchelow

Missouri Association of Municipal 

Utilities

EPA-HQ-OAR-2009-0234-17891-A1 William J. 

Yearta, Mayor

Sylvester, GA

EPA-HQ-OAR-2009-0234-17892-A1 Clay A. Gibbs Cornhusker Public Power District
12/08/11 DRAFT

835

EPA-HQ-OAR-2009-0234-17895-A1 Senator Jack 

Reed

United States Senate

EPA-HQ-OAR-2009-0234-17897-A1 Greg Thompson, 

Mayor

Monroe, GA

EPA-HQ-OAR-2009-0234-17898-A1 Kathy French Longleaf Energy Associates, LLC

EPA-HQ-OAR-2009-0234-17901-A2 Michael T.W. 

Carey

Ohio Coal Association (OCA)

EPA-HQ-OAR-2009-0234-17902-A2 Douglas R. Kopp Alliant Energy Corporate Services, 

Inc.

EPA-HQ-OAR-2009-0234-17903-A2 Leland M. 

Searles

Iowa Environmental Council 

(IEC)

EPA-HQ-OAR-2009-0234-17904-A3 Leslie Garrett 

Allen

Balch & Bingham LLP on behalf 

of Luminant

EPA-HQ-OAR-2009-0234-17909-A1 Keith M. 

Stephens

PowerSouth Energy Cooperative

EPA-HQ-OAR-2009-0234-17910-A1 Robert T. 

Hunnicutt, Sr.

Fort Valley Utility Commission, 

Fort Valley, CA

EPA-HQ-OAR-2009-0234-17911-A1 Floyd Gilzow Missouri Joint Municipal Electric 

Utility Commission (MJMEUC)

EPA-HQ-OAR-2009-0234-17912-A1 Les Oakes and 

Cynthia Stroman

King & Spalding LLP on behalf of 

IPP Coalition

EPA-HQ-OAR-2009-0234-17913-A1 Russ Baker Omaha Public Power District 

(OPPD)

EPA-HQ-OAR-2009-0234-17914-A1 R. L. Killion Babcock & Wilcox Power 

Generation Group, Inc. (B&W)

EPA-HQ-OAR-2009-0234-17915-A1 Alice Edwards Division of Air Quality, Alaska 

Department of Environmental 

Conservation (ADEC)

EPA-HQ-OAR-2009-0234-17916-A1 John Wilkinson Province of Ontario Ministry of 

the Environment, Canada

EPA-HQ-OAR-2009-0234-17917-A1 Matthew H. 

Mead, Governor

State of Wyoming

EPA-HQ-OAR-2009-0234-17918-A1 Dustin McDaniel Arkansas Attorney General’s 

Office

EPA-HQ-OAR-2009-0234-17919-A1 Scott H. Segal Electric Reliability Coordinating 

Council (ERCC)

EPA-HQ-OAR-2009-0234-17920-A1 Joseph Hantz Entergy Services, Inc.

EPA-HQ-OAR-2009-0234-17921-A1 Indra Frank Improving Kids’ Environment

EPA-HQ-OAR-2009-0234-17922-A1 Ross Gould Environmental Advocates of New 

York

EPA-HQ-OAR-2009-0234-17923-A1 Craig Bressan Prairie State Generating Company, 

LLC (PSGC)

EPA-HQ-OAR-2009-0234-17924-A1 James C. Welsh Kissimmee Utility Authority

(KUA)

EPA-HQ-OAR-2009-0234-17925-A2 Bill Matthews Cleco Power LLC
12/08/11 DRAFT

836

EPA-HQ-OAR-2009-0234-17926-A2 Derf Johnson Montana Environmental 

Information Center (MEIC)

EPA-HQ-OAR-2009-0234-17927-A2 Grant Rodway Bison Engineering, Inc.

EPA-HQ-OAR-2009-0234-17928-A2 Paul J. Allen Constellation Energy

EPA-HQ-OAR-2009-0234-17929-A2 James Pew Earthjustice

EPA-HQ-OAR-2009-0234-17930-A2 Michael J. Nasi Jackson Walker L.L.P. on behalf 

of Gulf Coast Lignite Coalition 

(GCLC)

EPA-HQ-OAR-2009-0234-17931-A2 William D. 

Bissett

Kentucky Coal Association (KCA)

EPA-HQ-OAR-2009-0234-17973-A1 John A. Paul Regional Air Pollution Control 

Agency (RAPCA) of Dayton, 

Ohio

EPA-HQ-OAR-2009-0234-17974-A1 James O. Vick Florida Electric Power 

Coordinating Group, Inc. (FCG)

EPA-HQ-OAR-2009-0234-17975-A1 Eric Schaeffer Environmental Integrity Project 

(EIP)

EPA-HQ-OAR-2009-0234-18014-A2 Larry J. Koshire Rochester Public Utlities (RPU)

EPA-HQ-OAR-2009-0234-18015-A2 Edward Z. Fox Arizona Public Service Company

(APS)

EPA-HQ-OAR-2009-0234-18016-A2 John D. Free Alabama Public Service 

Commission (APSC)

EPA-HQ-OAR-2009-0234-18017-A2 David V. 

Modeer

Central Arizona Water 

Conservation District (CAWCD)

EPA-HQ-OAR-2009-0234-18018-A2 Barry Moline Florida Municipal Electric 

Association (FMEA)

EPA-HQ-OAR-2009-0234-18019-A2 Susan Ackerman 

and John Savage

Oregon Public Utility Commission 

(OPUC)

EPA-HQ-OAR-2009-0234-18020-A2 Jonathan Oliver Arkansas Electric Cooperative 

Corporation (AECC)

EPA-HQ-OAR-2009-0234-18021-A2 James M. 

Landreth

South Carolina Electric and Gas 

Company (SCE&G)

EPA-HQ-OAR-2009-0234-18022-A2 Ross Gould Environmental Advocates of New 

York

EPA-HQ-OAR-2009-0234-18023 Chris Hobson Southern Company

EPA-HQ-OAR-2009-0234-18023-A2 Chris M. Hobson Southern Company

EPA-HQ-OAR-2009-0234-18024-A2 John P. Reese US Power Generating Company

(USPG)

EPA-HQ-OAR-2009-0234-18025-A2 Eric B. Svenson PSEG Services Corporation

EPA-HQ-OAR-2009-0234-18026-A2 Kevin Schmidt Ohio Manufacturers’ Association 

(OMA)

EPA-HQ-OAR-2009-0234-18027-A2 Vickie Patton Environmental Defense Fund 

(EDF)

EPA-HQ-OAR-2009-0234-18028 J. Butera Environmental Defense Fund 

(EDF)
12/08/11 DRAFT

837

EPA-HQ-OAR-2009-0234-18029-A2 Thomas M. 

Gibbons

Jersey City Environmental 

Commission

EPA-HQ-OAR-2009-0234-18030-A2 Bill Schuette State of Michigan Attorney

General Office

EPA-HQ-OAR-2009-0234-18031-A2 Michael G. 

Cashin

Minnesota Power (ALLETE)

EPA-HQ-OAR-2009-0234-18032-A2 Jim Weeks Michigan Municipal Electric 

Association (MMEA)

EPA-HQ-OAR-2009-0234-18033-A2 Thomas C. Perry National Mining Association 

(NMA)

EPA-HQ-OAR-2009-0234-18034-A2 Mark R. Vickery Texas Commission on 

Environmental Quality (TCEQ)

EPA-HQ-OAR-2009-0234-18034-A3 Mark R. Vickery Texas Commission on 

Environmental Quality (TCEQ)

EPA-HQ-OAR-2009-0234-18035-A2 Lauren Freeman, 

et al. Hunton & 

Williams LLP

Utility Air Regulatory Group 

(UARG)

EPA-HQ-OAR-2009-0234-18036-A2 Aaron Flynn, 

Hunton & 

Williams LLP

Utility Air Regulatory Group 

(UARG)

EPA-HQ-OAR-2009-0234-18037-A2 Douglas L. 

Biden

Electric Power Generation 

Association (EPGA)

EPA-HQ-OAR-2009-0234-18038-A2 Justin M. 

Nickels

City of Manitowoc Public 

Utilities, Wisconsin

EPA-HQ-OAR-2009-0234-18039-A2 Kenneth L. 

Kimmell

Massachusetts Department of 

Environmental Protection 

(MassDEP)

EPA-HQ-OAR-2009-0234-18043-A2 Allison D. Beals Adirondack Mountain Club 

(ADK)

EPA-HQ-OAR-2009-0234-18051-A2 Greg Schaefer Arch Coal, Inc. (ACI)

EPA-HQ-OAR-2009-0234-18248-A2 Joseph 

Mendelson III

National Wildlife Federation 

(NWF)

EPA-HQ-OAR-2009-0234-18414-A1 Larry L. Guest, 

Mayor

City of Elberton, Georgia

EPA-HQ-OAR-2009-0234-18415-A1 W. Kurt 

Foreman

North Louisiana Economic 

Partnership (NLEP)

EPA-HQ-OAR-2009-0234-18416-A1 Greg Hines, 

Mayor

City of Rogers, Arkansas

EPA-HQ-OAR-2009-0234-18417-A1 Patsy Meck Panola County Economic 

Development Corporation

EPA-HQ-OAR-2009-0234-18418-A1 Doug Sprouse, 

Mayor

City of Springdale, Arkansas

EPA-HQ-OAR-2009-0234-18419-A1 Jennifer G. 

Trammell

Greater Shelby County Chamber 

of Commerce

EPA-HQ-OAR-2009-0234-18420-A1 Perry Webb Springdale Chamber of Commerce

EPA-HQ-OAR-2009-0234-18421-A2 Susanne Brooks Environmental Defense Fund 
12/08/11 DRAFT

838

(EDF)

EPA-HQ-OAR-2009-0234-18422-A1 Ted Hampton Utah Associated Municipal Power 

Systems (UAMPS)

EPA-HQ-OAR-2009-0234-18422-A2 Ted Hampton Utah Associated Municipal Power 

Systems (UAMPS)

EPA-HQ-OAR-2009-0234-18423-A2 David 

Bookbinder

Julander Energy Company

EPA-HQ-OAR-2009-0234-18424-A2 J. Nathan Noland Indiana Coal Council, Inc.

EPA-HQ-OAR-2009-0234-18425-A2 Erika Padgett Clean Wisconsin, et al.

EPA-HQ-OAR-2009-0234-18426-A2 G. Vinson 

Hellwig

Michigan Department of 

Environmental Quality (MDEQ)

EPA-HQ-OAR-2009-0234-18427-A2 Kerry Kelly Waste Management (WM)

EPA-HQ-OAR-2009-0234-18428-A2 Caroline Choi Progress Energy

EPA-HQ-OAR-2009-0234-18429-A2 Coment 

submitted by

Brian L. Warner

Wolverine Power Supply 

Cooperative, Inc. (WPSCI)

EPA-HQ-OAR-2009-0234-18430-A2 Robert F. 

McDonnell

Commonwealth of Virginia

EPA-HQ-OAR-2009-0234-18431-A1 John Blair Valley Watch, Inc.

EPA-HQ-OAR-2009-0234-18432-A2 Adam H. Cutler Public Interest Law Center of 

Philadelphia

EPA-HQ-OAR-2009-0234-18433-A2 Joaquin C. 

Flores, P.E.

Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-18433-A3 Joaquin C. 

Flores, P.E.

Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-18433-A4 Joaquin C. 

Flores, P.E.

Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-18434-A2 David Gardiner The Alliance for Industrial 

Efficiency

EPA-HQ-OAR-2009-0234-18435-A2 American 

Academy of 

Pediatrics et al.

American Lung Association et al.

EPA-HQ-OAR-2009-0234-18436-A2 Jenny Dorgan Alabama Rivers Alliance

EPA-HQ-OAR-2009-0234-18437-A1 Patrick L. Pope Nebraska Public Power District

EPA-HQ-OAR-2009-0234-18438-A2 Vickie Patton Environmental Defense Fund 

(EDF)

EPA-HQ-OAR-2009-0234-18439-A2 Lisa Jacobson Business Council for Sustainable 

Energy (BCSE)

EPA-HQ-OAR-2009-0234-18440-A2 Dustin McCaniel Arkansas Attorney General’s 

Office

EPA-HQ-OAR-2009-0234-18441-A2 Craig Glazer PJM Interconnection, L.L.C.

EPA-HQ-OAR-2009-0234-18442-A1 Michael G. 

Dowd

Virginia Department of 

Environmental Quality (VADEQ)

EPA-HQ-OAR-2009-0234-18443-A1 Michalene Reilly Hoosier Energy Rural Electric 
12/08/11 DRAFT

839

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-18444-A2 William 

O’Sullivan, P.E.

State of New Jersey Department of 

Environmental Protection

EPA-HQ-OAR-2009-0234-18445-A2 Edward F. Miller American Lung Association 

(ALA)

EPA-HQ-OAR-2009-0234-18446-A2 Thomas Horne State of Arizona et al.

EPA-HQ-OAR-2009-0234-18447-A2 Brian Trower Ames Municipal Electric System

EPA-HQ-OAR-2009-0234-18448-A2 Craig A. Glazer PJM Interconnection, L.L.C. et al.

EPA-HQ-OAR-2009-0234-18449-A2 Frank Schaedlich Tekran Instruments Corporation

EPA-HQ-OAR-2009-0234-18450-A2 Donald Neal Calpine Corporation

EPA-HQ-OAR-2009-0234-18477-A3 Ronald R. Cox Hawaiian Electric Company, Inc.

EPA-HQ-OAR-2009-0234-18478-A1 Lois Capps, et al. Congress of the United States

EPA-HQ-OAR-2009-0234-18480-A1 Neal F. Niedfeldt City of Beatrice, Nebraska

EPA-HQ-OAR-2009-0234-18481-A1 William I. 

McLarty, Mayor

City of South Sioux City, 

Nebraska

EPA-HQ-OAR-2009-0234-18482-A1 Ann H. 

Campbell, 

Mayor

Mayor’s Office, City of Ames, 

Iowa

EPA-HQ-OAR-2009-0234-18483-A2 Larry G. Carlson Tenaska, Inc.

EPA-HQ-OAR-2009-0234-18484-A2 Steven C. Borell Alaska Miners Association (AMA)

EPA-HQ-OAR-2009-0234-18486-A2 Mark Maslyn American Farm Bureau Federation

EPA-HQ-OAR-2009-0234-18487-A2 Sierra Club, et 

al.

Sierra Club, et al.

EPA-HQ-OAR-2009-0234-18488-A2 Edward L. 

Kropp

Midwest Ozone Group (MOG)

EPA-HQ-OAR-2009-0234-18489-A2 Marion Loomis Wyoming Mining Association 

(WMA)

EPA-HQ-OAR-2009-0234-18497-A2 Jolene M. 

Thompson

American Municipal Power, Inc. 

(AMP)

EPA-HQ-OAR-2009-0234-18498-A2 Jerry Purvis East Kentucky Power Cooperative, 

Inc. (EKPC)

EPA-HQ-OAR-2009-0234-18499-A2 Sal LoBianco Muscatine Power and Water

EPA-HQ-OAR-2009-0234-18500-A2 Climate Policy

Group (CPG)

Climate Policy Group (CPG)

EPA-HQ-OAR-2009-0234-18501-A2 Tyler Edgar National Council of Churches

EPA-HQ-OAR-2009-0234-18502-A2 Late Miguel A. 

Cordero Lopez

Puerto Rico Electric Power 

Authority (PREPA)

EPA-HQ-OAR-2009-0234-18538-A2 Donna L. Nelson Public Utility Commission of 

Texas (Texas PUC)

EPA-HQ-OAR-2009-0234-18539-A1 Al DePaoli AES Corporation

EPA-HQ-OAR-2009-0234-18540-A2 Louis J. Manuel 

Jr.

Ak-Chin Indian Community

EPA-HQ-OAR-2009-0234-18541-A1 J. Fitzgerald and None
12/08/11 DRAFT

840

C. R. de Azua

EPA-HQ-OAR-2009-0234-18575-A1 Heartland 

Consumers 

Power District

Heartland Consumers Power 

District

EPA-HQ-OAR-2009-0234-18576-A2 Sherri Bulkley, 

et al.

American Lung Association in 

Hawaii

EPA-HQ-OAR-2009-0234-18590-A2 Robin Grant American Lung Association in 

Tennessee (ALATN)

EPA-HQ-OAR-2009-0234-18644-A2 S. Nelson Jr. None

EPA-HQ-OAR-2009-0234-18666-A1 P. Difani None

EPA-HQ-OAR-2009-0234-18705-A1 Michael P. 

Marcotte

City of Alexandria, Louisiana

EPA-HQ-OAR-2009-0234-18706-A1 Bucky Johnson, 

Mayor

City of Norcross, Georgia

EPA-HQ-OAR-2009-0234-18707-A2 Linda McGrath American Lung Association in 

Idaho

EPA-HQ-OAR-2009-0234-18716-A2 Taylor A. Davis 

III, Patty Unfred 

and Matthew 

Walker

American Lung Association in 

Oregon

EPA-HQ-OAR-2009-0234-18721-A2 Jon Breiner, et 

al.

American Lung Association in 

Washington

EPA-HQ-OAR-2009-0234-18749-A2 Mike Moody American Lung Association in 

Kentucky

EPA-HQ-OAR-2009-0234-18750-A2 Harry Perlstadt American Lung Association in 

Michigan

EPA-HQ-OAR-2009-0234-18751-A2 William Lawson 

and Jesse Neeley

American Lung Association in 

Tennessee

EPA-HQ-OAR-2009-0234-18759-A2 Rick 

MacCornack

Washington Asthma Initiative 

(WAI)

EPA-HQ-OAR-2009-0234-18785-A2 Eddy Young Optim Energy LP, Twin Oaks

EPA-HQ-OAR-2009-0234-18820-A1 M. Stiefermann Central Electric Power 

Cooperative

EPA-HQ-OAR-2009-0234-18823-A2 John Cloud American Lung Association in 

Ohio

EPA-HQ-OAR-2009-0234-18831-A1 Berdell Knowles JEA

EPA-HQ-OAR-2009-0234-18894-A1 Ric Hall, Mayor City of Blakely, Georgia

EPA-HQ-OAR-2009-0234-18897-A2 Daniel Sutton American Lung Association in 

Ohio (ALAO)

EPA-HQ-OAR-2009-0234-18898-A2 Linn Billingsley American Lung Association, 

Nevada

EPA-HQ-OAR-2009-0234-18899-A2 Marlis Hadley American Lung Association, New 

Mexico

EPA-HQ-OAR-2009-0234-18900-A2 Caroline 

Moassessi

American Lung Association, 

Nevada
12/08/11 DRAFT

841

EPA-HQ-OAR-2009-0234-18901-A2 Andy Boyce American Lung Association, 

Nevada

EPA-HQ-OAR-2009-0234-18907-A2 Charles D. 

Bennett

Marathon Petroleum Company LP

EPA-HQ-OAR-2009-0234-18924-A1 Jim Hawks City of North Platte

EPA-HQ-OAR-2009-0234-18930-A2 Connie Shawler 

et al.

American Lung Association in 

Arizona

EPA-HQ-OAR-2009-0234-18933-A2 Michael S. 

Hubbard

National Council of Textile 

Organizations (NCTO)

EPA-HQ-OAR-2009-0234-18934-A2 Nicky Sheats, 

Esq.

New Jersey Environmental Justice 

Alliance (NJEJA)

EPA-HQ-OAR-2009-0234-18935-A2 Jon Howard Weston Solutions, Inc.

EPA-HQ-OAR-2009-0234-18936-A1 Hays Arnold, 

Mayor

City of Thomaston, GA

EPA-HQ-OAR-2009-0234-18937-A1 Kimberly C. 

Carter, Mayor

City of Covington, GA

EPA-HQ-OAR-2009-0234-18944-A1 Charles 

Sherwood

City of Ellaville, GA

EPA-HQ-OAR-2009-0234-18961-A2 Meg Voorhes US SIF – The Forum for 

Sustainable and Responsible 

Investment

EPA-HQ-OAR-2009-0234-18963-A2 Daniel Traynor Northampton Generating 

Company, L.P

EPA-HQ-OAR-2009-0234-18964-A2 CONSOL

Energy Inc.

CONSOL Energy Inc.

EPA-HQ-OAR-2009-0234-19032-A1 James M. 

Andrew

Arizona Electric Power 

Cooperative, Inc. (AEPCO)

EPA-HQ-OAR-2009-0234-19033-A1 Samuel H. 

Bruntz

Alcoa Power Generating, Inc. 

(APGI)

EPA-HQ-OAR-2009-0234-19040-A1 D. S. McKeown None

EPA-HQ-OAR-2009-0234-19041-A1 Steven K. 

Nelson

The Frontier Power Company

EPA-HQ-OAR-2009-0234-19042-A2 James Parkhurst EOP Foundation

EPA-HQ-OAR-2009-0234-19094-A1 Michael C. 

Stiefermann

Central Electric Power 

Cooperative (CEPC)

EPA-HQ-OAR-2009-0234-19101-A1 James J. Egge Audubon Chapter of Minneapolis

EPA-HQ-OAR-2009-0234-19111-A1 Linda 

Vanderveen

Conservation Chair, Hernando 

Audubon of Florida

EPA-HQ-OAR-2009-0234-19114-A1 John M. 

McManus

American Electric Power (AEP)

EPA-HQ-OAR-2009-0234-19120-A1 Angelique Oliger Indianapolis Power & Light 

Company (IPL)

EPA-HQ-OAR-2009-0234-19121-A1 Jon A. Finlinson Intermountain Power Service 

Corporation (IPSC)

EPA-HQ-OAR-2009-0234-19122-A1 Mark J. Sedlacek Los Angeles Department of Water 
12/08/11 DRAFT

842

and Power (LADWP)

EPA-HQ-OAR-2009-0234-19123-A1 Markus I. Bryant Lorain-Medina Rural Electric 

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-19143-A1 John (no 

surname 

provided)

None

EPA-HQ-OAR-2009-0234-19145-A1 Juan M. Cofield National Association for the 

Advancement of Colored People 

(NAACP)

EPA-HQ-OAR-2009-0234-19199-A1 Heath R. 

VanNatter

House of Representative, State of 

Indiana

EPA-HQ-OAR-2009-0234-19205-A1 L. Garvey None

EPA-HQ-OAR-2009-0234-19209-A1 Markus I. Bryant North Central Electric 

Cooperative, Inc.

EPA-HQ-OAR-2009-0234-19210-A1 Richard H. 

Baker

Pelican Island Audubon Society

EPA-HQ-OAR-2009-0234-19211-A1 Joseph Croce Virginia Manufacturers 

Association (VMA)

EPA-HQ-OAR-2009-0234-19212-A2 James D. 

Atterholt

Indiana Utility Regulatory

Commission (IURC) et al.

EPA-HQ-OAR-2009-0234-19213-A1 J. Michael 

Houston, Mayor

City of Springfield, Illinois

EPA-HQ-OAR-2009-0234-19214-A1 Willie R. Taylor, 

Director

United States Department of the 

Interior

EPA-HQ-OAR-2009-0234-19225-A1 Mike Godwin Orange Audubon Society

EPA-HQ-OAR-2009-0234-19296-A1 Richard H. 

Bremer

Greater Shreveport Chamber of 

Commerce

EPA-HQ-OAR-2009-0234-19506-A1 Thomas W. 

Easterly

Indiana Department of 

Environmental Management

EPA-HQ-OAR-2009-0234-19540 Ann Brewster 

Weeks

Clean Air Task Force, et al.

EPA-HQ-OAR-2009-0234-19549-A1 David Theiss, 

Mayor

City of Ellaville, Georgia

EPA-HQ-OAR-2009-0234-19559-A1 C. Neil Mayer City of Whigam, Georgia

EPA-HQ-OAR-2009-0234-19560-A1 Lemuel O. 

Edwards

Albany Water Gas & Light 

Commission, Albany, Georgia

EPA-HQ-OAR-2009-0234-19564-A1 Jamey D. 

Pankoke

Perennial Public Power District

EPA-HQ-OAR-2009-0234-19565-A1 Brian 

Lukasiewicz

Howard Greeley Rural Public 

Power District

EPA-HQ-OAR-2009-0234-19566-A1 L. J. Joey Durel, 

Jr.

Lafayette Utilities System, 

Louisianna

EPA-HQ-OAR-2009-0234-19574-A1 Thomas E. 

Rudloff

Elkhorn Rural Public Power 

District

EPA-HQ-OAR-2009-0234-19580-A1 Jay Timmons National Association of 
12/08/11 DRAFT

843

Manufacturers (NAM)

EPA-HQ-OAR-2009-0234-19581-A1 Kent Greenwalt, 

Mayor

City of Terrytown

EPA-HQ-OAR-2009-0234-19595 N.A. Bishop City of Terrytown

EPA-HQ-OAR-2009-0234-19601-A1 J. M. Gibney, Jr. Wahoo Public Utility

EPA-HQ-OAR-2009-0234-19603-A1 Steve Rentfrow Crisp County Power Commission

EPA-HQ-OAR-2009-0234-19622-A2 Adriana Oller Nickel Producers Environmental 

Reseach Association (NiPERA, 

Inc)

EPA-HQ-OAR-2009-0234-19653-A1 Richard Marshall Spectrum Systems Inc.

EPA-HQ-OAR-2009-0234-19654 Rick Wajda Indiana Builders Association 

(IBA)

EPA-HQ-OAR-2009-0234-19671-A2 Lee A. Casey, 

Counsel, Baker 

& Hostetler LLP 

on behalf of 

Institute for 

Liberty et al.

Institute for Liberty et al.

EPA-HQ-OAR-2009-0234-19671-A3 Lee A. Casey, 

Counsel, Baker 

& Hostetler LLP 

on behalf of 

Institute for 

Liberty et al.

Institute for Liberty et al.

EPA-HQ-OAR-2009-0234-19677-A1 Michael Ralston Iowa Association of Business and 

Industry (ABI)

EPA-HQ-OAR-2009-0234-19678-A2 Barbara A. Walz Tri-State Generation and 

Transmission Association, Inc.

EPA-HQ-OAR-2009-0234-19679 John Artes Maryland Department of the 

Environment

EPA-HQ-OAR-2009-0234-19741

A. Gwen 

Ecklund

West Associates

EPA-HQ-OAR-2009-0234-19742

Andrew J. Such Michigan Manufacturer’s 

Association