## 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 December 2011**  **Volum e**  **2 of 2** 

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

**h ttp://www.regulations.gov**  **by searching Docket ID EPA**  **- HQ** **- OAR** **- 2009** **- 0234.** 1 **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, Industrial

Commercial

-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, Ill inois ; 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 h ttp://www.regulations.gov by searching Docket IDs EPA

-HQ

- OAR

2009

- 0234 (NESHAP action) and EPA

-HQ

- OAR

- 2011

- 0044 (NSPS action)

. This document contains responses to comments on the NESHAP only ; responses to c omments 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 comment s in the preamble of the final rule. This document contains a summary of all signi ficant 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 b y an organization, by the commenter incorporating b y reference the comments in another comment letter, or b y 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 o f all the commenters who submitted the same form letter or otherwise incorporated the comments by reference in Tables 9A

1 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 anal ys is 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 d uplicative comments, we have removed from this document comments associated with the NSPS2

action. For this reason, the EPA encourages the public to read the Response to Comment document prepared for the NSPS action.3 **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:**  **Em ission 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 -**  **Im pacts/Costs: Testing and Monitoring Cost Assumptions**  **6H -**  **Impacts/Costs: Projection of New Units 6I**  **- Impacts/Costs: Economic Impacts/Employment Impacts**  **6J -**  **Im pacts/Costs: Social Costs**  **6K -**  **Im pacts/Costs: Health Co**  **- Benefits**  **6L -**  **Impacts/Costs: Mercury Benefits 6M**  **- Im** **pacts and Costs: Air quality co -**  **benefits modeling 6N**  **- Im** **pacts/Costs: Other/Miscellaneou s**  **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** 4

**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**5

**CHAPTER 5 :**  **COMPLIANCE WITH TESTING/MONITORING/RECORDKEEPING AND REPORTING**  **5A01 -**  **Testing/Monitoring: Stack T**  **est M**  **ethods 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 , 1953 7 , 19538, 18932, 18023 **1 . Comments**  **r elated to**  **a lternative**  **c om** **pliance t**  **est m**  **ethods .**  **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 han d, are also allowed the option of using Method 5B
- Determination of Nonsulfuric Acid Particulate Matter Emissions from Stationary Sources. The c ommenter 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 p art 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 (sectio n 63.1450(b), UUU (section 63.1579 and t ables).) 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 specificall y 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 testin g 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 IC R 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 mu st provide EGUs the option to use Method 29 for any PM testing. **Comment 2** : Multiple c ommenters (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. Condition al 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 and**  **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 b y the6

c alculation of the emission limit. The basis for the filterable PM emissions limit in the final rule is EPA Method 5 with a filter temperature of 320° F and sample desiccation at temperatures up to 220o F for up to 3 hours
. While Method 5B also specifies a filter temperature of 320o F, Method 5B includes an additional extended (6 hour) heating of the filter in the laboratory to remove particulate matter that would volatilize at 320o F including condensed sulfuric acid. This additional anal ytical step renders the method unusable for determining compliance with a limit based on Method 5 procedures. As for using Method 17, we did not cite the method in the rule but would entertain a request for site

- specific alternative method approval to use Mehtod 17 in lieu o f Method 5. A condition of approval is that the stack gas temperature at the sampling location remains no greater than 320o F during the performance testing. **Comment 3:** Several c ommenters (17767, 17790, 17795, 17800, 17821) state that proposed use of Metho d 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 ty

pe of heated cyclone to vaporize water droplets before anal yz ing 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 ob tain 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 beli eve 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 allo w 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 ty pes listed in Table 5 to subpart UUUUU of part 63 performance stack testing requirements. The c ommenter 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 th e commenter, the methods used to determine pollutant concentrations (e.g., Metho ds 5, 23, and7

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 h as been amended to clarify that only methodology

or equations required for the specific emission limit will be required. **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 p art 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 th ere are at least 168 unit operating hours (as defined in this section) or, for a common stack or by pass 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 rul e (e.g., coal and liquid oil), because b y requiring a minimum level of operation to trigger stack testing requirements, no unit will be operated simpl y 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 monthl y fuel tests, the commenter proposes that owners/operators of a LEE unit have the option to conduc t 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 ye ar. If a LEE unit exceeds LEE limits, the commenter proposes that the unit revert back to more frequent performance tests (e.g., quarterl y, 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 s ome 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 be en 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 mo nitoring options (Method 29 testing every 2 months or every

month depending on PM control) retained. The c ommenter 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.8

**2 . Comments**  **r elated to**  **t esting**  **p eriod (**  **c larification 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 day s, but proposed Table 5 specifies 30 day s. **Response to Comment 7:** The EPA has clarified this issue in the final rule
. The required testing period is 30 days **. Comment 8:**  Commenter 1 8539 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 uni ts with FGD technology and SO 2 CEMs is determined using the average hourly SO 2 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 th e preamble and section 63.10005(a) indicate that PM, metals, SO 2 , and HCl compliance tests are required initially and every

5 years. According to the commenter, s ection 63.10005(a) states that “ [I ]f you use a continuous monitoring sy stem that measures a surrogate for a pollutant (e.g., an SO 2 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 c onducting 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 SO 2 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 onl y require testing and/or monitoring for the specific emissio n standard with which the source complies (either the direct emission limit, such as HCl, or the alternate equivalent standard, such as SO 2 ). **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 day s of sorbent trap data ( i.e ., two 14
- day sorbent traps) to determine the “ average Hg c oncentration ” 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 . Commen**  **ts related to**  **o perating**  **p arameters and**  **f uel**  **l imits**  **s et**  **d uring**  **t esting**  **. 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 appl y, because on its face, the requirements of section 63.10011(b) appear to apply to all EGUs , regardless of the compliance option. However, ac cording 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 appl y 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) (emphasis9

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 limi ts in section 63.10011(b) appl y to liquid oil

- fired EGUs opting to demonstrate compliance using stack testing, the EPA should make clear that EGUs combusting a single fuel ty pe 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 ty

pe 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 complyingthrough fuel anal ys is. **Comment 11:** Commenter 18023 states that the agency must clarif

y 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 regularl y scheduled performance tests at units that are no t 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 onl y 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). **Com ment 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 p arameters measured during performance testing creates what is effectivel y 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 flexib ility

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 1**  **4 :**  Commenter 17868 states that the EPA should re

- evaluate the proposed operating parameter requirements. **Response to Comments 1**  **0 -**  **1 4**  **:** The final rule has removed the requirements for operating and fuel limits, except where a source: (1) opts to use a PM CPMS to monito r compliance; or (2) for a liquid oil

fired unit, adopts a source

- specific monitoring plan to collect, record, and report on appropriate operational parameters in addition to conducting quarterl y 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 rul e 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**  **r elated to**  **u se of**  **s hort**  **t erm**  **s tack**  **t est and**  **fuel s amples**  **to s**  **et 30 -**  **d ay**  **s tandards**  **.**10

**Comment 1 5**  **:** 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 effectivel y 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 aff ected source 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 IC R 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 prop osed 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 feasibl y perform numerous stack tests. **Response to Comment 1 5**  **:** 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**  **r elated to**  **c oncerns**  **a bout**  **u se of Method 202**  **. Comment 1**  **6 :**  Commenter 18014 states that despite Method 202 being revised to include a nitrogen purge and an initial dry impinger (which is quickly wetted with conden sation from the flue gas) to reduce these artifacts, the remaining SO 2 - 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 SO 2 - related artifact formation to be particularl y acute if there is any NH 3 in the flue gas (e.g., slip from an SCR for NO X control), which again is not related to primary particulate and certainly

not related to metal HAP in any

way . **Comment 1 7**  **:** Commenter 17402 expresses concerns that condensable PM reference Method 2 02 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 recentl y completed Method 202 stacks tests on a number of units using the same coal, and observations that the condensable PM fraction ranged f rom 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 properl y quantify actual reductions. Commenter 17402 also relays plans to commission nine SNCR systems and associated concerns about ammonia slip reactions with dissolved SO 2 . 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 reli able 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 b y 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 NH 3 in the gas stream will be absorbed in the aqueous layer of the Method 202 impingers and will react with SO 2 to form either ammonium sulfate or bisulfate. According to11

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 SO 2 -NH 3 - H 2 O can occur in the new M202 , and should also allow for quantification and correction ” of this artifact using procedures prescribed b y CAE or the EPA should modify Method 202 to reduce or eliminate the bias. 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 1 8**  **:** Commenters 17725 and 18498 state that using onl y filterable particulate (in conjunction with SO 2 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 b y sulfate and nitrate compounds, which have nothing to do with metal HAP emissions. According to the commenter s , 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 SO 2 artifact formation (again, something that has nothing to do with metal HAP ) that make the results especiall y 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 S O 2 related artifacts can be significant at low levels. Also, according to the commenters, because of the bias, extending the run time does not necessaril y 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 SO 2 - related artifact formation to be particularly acute if there is any NH 3 in the flue gas (e.g., slip from an SCR for NO X control), which again is not related to primary particulate and certainl y 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 b y more than 90%. ” See Metho d 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 substanti ally 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 compli ance with the proposed rules. Given the different train configurations and operating temperatures, the commenter s suspect that OTM 28 data are not directl y comparable to Method 202 and therefore sources may have difficulty planning or demonstrating compliance without substantial comparative testing.12

**Comment 2**  **1** : Commenter 17820 states that Method 202, recentl y finalized by the EPA to measure condensables , is still prone to biases due to SO 2 artifact formation that has nothing to do with metal HAP and makes r esulting PM measurements questionable. **Response to Comments 1 6**  **- 2**  **1 :**  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. **6 . Comments**  **r elated to**  **f requency of**  **s tack**  **t esting**  **. Comment 2**  **2 :**  Commenter 17775 s tates 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 annuall y. However, according to the 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 t esting 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 2 2**  **:** 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 wi ll be subject to ongoing QA, including RATA tests. **Comment 2 3**  **:** Several c ommenters (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

- monthl y 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 n ot 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 monthl y 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 tes ting 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, particularl y the cold winter months. Finally, according to the commenter, infl exible 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 t ests 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 no t 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 quarterl y under standard operation (i.e., unless boiler operations or characteristics are substantiall y altered, in which case initial testing should be repeated). The commenter believes that quarterl y stack testing in combination with p arameter 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 proposed13

monitoring option for sources not using CEMS as excessive and overl y burdensome because the commenter believes the requirement to conduct stack testing either monthly or bi

- monthl y 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 re quire 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 protec t 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 testing or accounted for the cost of such frequent testing in its proposed IC R . 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 p roposed frequency of testing is by definition arbitrary and capricious and contends that EGUs demonstrating initial compliance through stack testing and confirming compliance b y monitoring and responding to appropriate operating parameters should not need to conduct additional stack tests more frequently than annually , unless the EGU ’ s fuel ty pe 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 2 4**  **:** 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 sy stems are required to complete stack tests less frequentl y 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 anal ys is 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 historicall y been sufficient. **Comment 2 5**  **:** Commenter 18498 states that because many liquid oil

- fired sources operate infrequently and only during peak demand periods for liquid oil

- fired sources, th e 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 additio nal emission testing is needed.14

**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 quarterl y testing for all HAP
. According to the commenter, quarterl y testing provides the necessary performance guarantee, while balancing the substantial costs of stack testing. **Response to Comments 2 3**  **- 26**  **:** In response to comments, the final rule has been amended to include quarterl y 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. Plea se see the final preamble for further discussion. **Comment 2 7**  **:** Commenter 17880 supports the requiring of coal

- fired, IGC C and solid oil

- derived fuel

fired units to conduct HAP metals and P M 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 2 8**  **:** 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 sy stems
. 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 2 7**  **- 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 recognize s 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 re

established over time. With respect to the f requency 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 r**  **elat ed to**  **d erating**  **u nits**  **. a.**  **Compliance Plans to t**  **emporarily d**  **erate u**  **nits w**  **hile a**  **ir p**  **ollution c**  **ontrol u**  **pgrades are c**  **om pleted**  **. Comment 2**  **9 :**  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 complianc e deadline, and the commenter believes that compliance prior to completion of air pollution control upgrade projects can onl y be achieved b y operating such units at reduced load. Commenter 17402 requests that the EPA clarify that “maximum normal operating load ” under the proposed performance test guidelines can15

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 1740 2 notes that in proposed section 63.10007(c), the EPA specificall y 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 no t 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 limi ts set based on the most recent performance test well temporaril y 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 fac ilities 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 periodic performance test. The commenter notes that the EPA has supported interim control strategies previously , including voluntary capacity reductions. **Response to Comment 2 9**  **:** The EPA believes the proposed and final rule s already provide for this ty pe of flexibility . If a source adopts a derate restriction as a condition of its federall y 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**  **i mplications of**  **i nterim MACT**  **c om** **pliance s**  **trategies i**  **nvolving d**  **erates .**  **Comment 30**  **:** Commenter 17402 requests, regarding temporary measures to administratively derate a unit to a generating capacity that can compl y with MACT standards while air pollution control upgrades are installed, that the EPA provide cl arification 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 “bas eline actual emissions ” are defined as any consecutive 24

- month period from the 5 ye ars prior to the start of construction, an operator could reasonabl y 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 requests16

for guidance on a case

- specific basis under the normal procedures established for issuing guidance an d policy interpretations under the NSR program. **8 . Comment**  **r elated to**  **b ypass**  **r equirements** 

**– 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 by pass stack is not appropriate for EGUs that only use the b yp ass 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 u sage on an occasional basis. The commenter believes that alternative monitoring methods such as data substitution techniques similar to those used in 40 CFR p art 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 by

pass stack. **Response to Comment 31**  **:** The EPA has modified the by pass stack monitoring requirements. Under 40 CFR P art 75, the EPA allows the use of a maximum potential concentration value on a by pass 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 by pass stack consistent with the proposed rule. The other is to treat any hours of bypass stack emissions as periods of monitor downtime. Ingeneral, 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 by pass stack as the emission limit does not apply during the periods when the source is most likely to operate a b yp ass stack. Use of a by

pass 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**  **r elated**  **to d**  **uplicative t**  **esting .**  **Comment 3**  **2:** 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. Fo r 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 SO 2 or HCl for acid gas HAP, and these options provide the sources with a measure of flexibility . According to one 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 3 3**  **:** 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 c ommenter 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 unsuppo rtable. The commenter states that for EGUs that opt to comply with a chosen17

emission limit using stack testing, the EPA (again without explanation) requires stack testing no less frequentl y 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 IC R . 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 w ith 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 be st 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 lan guage: the agency summarizes the D.C . Circuit decision in National Lime Ass ’n , 233 F.3d 625: I f these criteria are satisfied and the PM emission standards reflect what the best sources achieve

-- complying with CAA section 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 h as satisfied the criteria for use of PM, HCl , and SO 2 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 e mission 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 comment er 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 directl y measuring the regulated HAP , it is superfluous to require any further testing of surrogates, and under the stack testing compliance option the agenc y should specify that performance tests only for methods necessary

to measure the regulated HAP are required. **Comment 3 4**  **:** 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 in18

addition to stack testing for total PM and establishing a filterable PM limit and demonstrating compliance with PM CEMS, and s imilarly, sources using SO 2 as a surrogate for HCl must test for HCl in addition to the SO 2 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 any way . 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 SO 2 CEMS to conduct “ all applicable performance tests ” for SO 2 and HCl annually

and, for units with SO 2 controls, to conduct SO 2 emissions testing “ at least every other month. ” See also p reamble, 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 unr easonable. The commenter also views both requirements as inconsistent with Tables 1 and 2, which, according to the commenter, establish surrogate emission limits as “ alternatives ” to HAP emission limits and vice versa. The commenter states that although th e EPA describes these duplicative testing requirements in the preamble, the EPA provides no rationale to support them. **Comment 3 5**  **:** Commenter 18015 states that section 63.10000(c)(1) of the proposed rule provides that for all coal

- fired and solid oil

- derive d 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 SO 2, 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 demonstrat e 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 emis sion 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 compl ying with the PM emission limit, not the individual HAP metals emission limits. Thus, states the commenter, initial compliance should only appl y to the applicable emission limit and result in testing of only the surrogate pollutant, PM, not HAP metals. **Comment 3 6**  **:** Commenter 18034 states that proposed section 63.10006 requires coal

- fired and solid

- oil derived fuel

- fired EGUs to perform testing for non

- H g 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 SO 2 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

- monthl y 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 subje ct to the non

- Hg metal HAP limits and a demonstration of compliance is not necessary . The same issue applies to an EGU using SO 2 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 s ection 63.10006 is inconsistent with the EPA statements in the preamble that use of the PM surrogate would eliminate costs ass ociated with conducting performance testing for non

- Hg metals (76 FR 25039). According to the commenter, these19

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**  **:** Comment er 17868 states that the EPA must remove the requirement for SO 2 performance testing. According to the commenter, proposed section 63.10006(h) and (i) include testing provisions for SO 2 for units without SO 2 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 states that there is no basis for testing of the surrogate SO 2 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 SO 2 performance testing or an SO 2 emissions standard other than those applicable to units with SO 2 CEMS . The commenter states the EPA has no basis to require EGUs that choose to comply through stack testing to also install an SO 2 CEMS
. **Response to Comments 3**  **2 -**  **3 7**  **:** 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**  **r elated to**  **n on**  **- Hg**  **m etal**  **s tandards**  **. Comment 3**  **8 :**  Commenter 17775 supports the proposed inclusion of an option for non

- Hg HAP metals stack testing (i.e., Meth od 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 c ommenter 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 op tion 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 c ommenter concludes that requiring testing for a surrogate in addition to the regulated HAP is beyond the agency ’ s authority
. 2. The c ommenter 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 flex ible 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 c ommenter 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 c ommenter 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 ty pe or mixture has the highest content of non

- Hg HAP metals)20

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 onl y to liquid oil

- fired EGUs complying through fuel analy sis. 4. Commenters 17775 and 17868 state that the final rule should specify minimum detection limits for laboratory anal ys es and provide procedures for calculating combined concentrations of single metals and total non

- Hg metals. According to C ommenter 17775 the data collected in the 2010 IC R indicated the reported detection limits for laboratory anal ys es were highl y 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 3 8**  **:** We agree that maintaining low method detection levels is critic al in demonstrating compliance with the applicable emissions limits for this MACT rule. We disagree that we can provide default values for method detection levels to use in determining compliance since there are many site

- specific factors that can affect m ethod detection levels for any one set of data. In achieving the most effective testing including method detection levels commensurate with compliance determinations, the tester must consider multiple technical and procedural choices and anal ytical laboratories used in any

test program. There are some testing factors that we believe are appropriate for the rule to address including minimum sample volume and some specific analy tical finishes; however, those required elements do not lead directl y to maximum m ethod detection levels. 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. It is difficult to define maximum acceptable method detection levels that would adequatel y account for the my riad of test matrices, interference, various typ es of anal ytical finish es , and final anal ytical volumes that could very well be effective for all situations. Instead, the rule includes a requirement that specifies how to use method detection level information in calculating compliance with the emissions limits. The language in the final rule is similar to that found in the Mercury cell Chlor

alkali plant regulations ( see § 63.8232 (c)(1)). The source must use the test specific method detection level in calculating compliance with an emissions limit for any value measured and reported as below detection level. On the other issue of method detection capabilities for fuel sampling and analy ses, the removal of the proposed fuel input operating requirements in the final rule renders the concerns about identifying highest fuel mixture and supplemental fuels no longer relevant
. **11 . Comments**  **r elated to**  **HCl s**  **tandard t**  **esting .**  **Comment 3 9**  : Commenter 17775 expresse s 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 SO 2 performance testing under this option because there is no basis for testing of the surrogate SO 2 at a unit that is complying with the HCl standard. In addition, the commenter states, the proposed rule does not provide any procedure for SO 2 performance testing, or an SO 2 emissions standard other than those applicable to units with SO 2 CEMS. The commenter states that the EPA has no basis to require EGUs that choose to comply through stack testing to also install an SO 2 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 sufficientl y connected to21

HCl removal or sufficiently flexible for use a s 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 ty pe are not required to make any determination regarding that fuel under section 63.10011(b)(1)(i) (requiring determination that the fuel ty pe 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 anal ys is. 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 stan dard rather than HAP metals standard. **Response to Comment 3 9**  **:** The final rule has been amended to remove the requirement for testing of both SO 2 and HCl
. Operational parameter requirements specified for HCl have been removed. The frequency of periodic testing has been reduced to quarterl y 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 HC I 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 hi gh 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 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 b y 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 th at 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 anal ys is demonstrating no material changes in the fuel supply are sufficient to assure compliance with the applicable HCl emission limit between semi

- annual perfor mance tests.22

**Response to Comment 41**  **:** The final rule has been amended to require quarterl y HCl testing for sources not using an HCl/HF or SO 2 CEMS option. The EPA disagrees that one performance test at 50 % of the emission standard would be adequate to ensur e 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**  : Co mmenter 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 be low 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 Co mment**  **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**  **a bout**  **c oncerns**  **w ith**  **c ombined**  **s tack**  **. Comment**  **4 3:**  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 largel y 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 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 accurate ly 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 way s: (1) when multiple emission sources vent gases through separate flues that are phys icall y 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 point s. 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 s tack 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 co mmenter, a monitoring regime that does not require each source to separatel y monitor and report its HAP emissions will not assure that each covered EGU complies with all applicable MACT23

requirements. The commenter provide s an example of monitoring emission s at both ty pes of combined stacks. **Response to Comment 4**  **3:** 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 o r tested location at any unit that operates in such a manner. For the more ty pical 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 lev el or monitoring of the combined emissions. Inthe 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**  **a bout**  **u sing**  **t otal 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 onl y 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 l imit to represent selenium is not supported. **Comment 4 5**  **:** 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 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 inclus ive 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 anal ys is should be performed on the 12 % of existing units identified in the developm ent of the PM surrogate for HAP metals. **Response to Comments 44**  **- 4**  **5 :**  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**  **c omments**  **rega rding**  **t esting**  **. Comment 4**  **6 :**  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 IC R laboratories at those emission levels using the standard methods required by the ICR (Appendix B; Method Sensitivity

for IC R 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 o n outliers and did does not take into account method performance with actual stack gas samples.24

**Comment 4 7**  **:** 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 anal ytical detection limits and emissions standards th at are properl y adjusted for non

- detect values. **Response to Comments 4 6**  **- 4**  **7 :**  The EPA reviewed the minimum sample volumes required for the emissions limits and, based upon the present anal ytical capabilities, concluded that the sample volumes specified are appropriate. Inthe 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 4 8**  **:** 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

unlikel y an EGU could demonstrate compliance with the total PM limit while exceeding the individual PM and HAP metals limits. **Response to Comment 4 8**  : 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 4 9**  **:** 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 dat a is to be maintained in 12

- hour block averages, it would seem the EPA want s 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 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 4 9**  **:** 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. Generall y, the onl y 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 5 0**  **:** 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 non

Hg 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 clearl y address25

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 po llutants. **Response to Comment 5 0**  **:** 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 remain ed 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 aff ected 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 propose d rule designated a single surrogate. The c ommenter 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. **Response to Comments 51**  **and 52**  **:** The agency agrees with the commenter that performance testing should be representative of an EGU’s actual operation. For initial short term performance tests (e.g., manual three run tests), the rule specifies that emissions testing is to occur at maximum normal operating loads. The rule also reminds EGU owners or operators of the ability to conduct performance testing at loads other than maximum, in case alternate operating limits for those periods are desired. For the 30 day or other longer term performance testing averaging periods, the final rule does specify a minimum process operation but expects that measured emissions values to represent normal operations. As noted elsewhere in the responses to comments, emissions created during process startup and shutdown are not included in the compliance calculations. All other periods are considered normal process operations during which the emissions limits apply
. The final rule has been amended to remove the requirement for testing for both the HAP and a surrogate. for the final rule provides multiple alternative emissions limits and you will have to demonstrate compliance onl y with the limit for which you are demonstrating compliance. **Comment 53**  **:** Commenter 18015 states that a tes ting grace period, similar to the 40 CFR p art 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 be26

provided for the performance testing requirements in s ubpart UUUUU. The p art 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. The provisions for requesting such extensions and the procedures for implementing them are explained in greater detail in the “Clean Air Act National Stack Testing Guidance” released on April 27, 2009. **Comment 5**  **4:** Commenter 17881 states that clarification is nee ded with respect to what it means to “ conduct all applicable performance tests for PM (or SO 2 ) 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 limit ed 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 , possib le interferences from multiple probes inserted at a given stack plane, etc. **Comment 5 5**  **:** Commenter 17881 questions how, when CEMS are being used to measure the surrogate (i.e., PM or SO 2 ), one would reconcile a 30

- day compliance test period for the surrogate with the relativel y short duration run times associated with manual sampling methods for non

- Hg metals and HCl (citing section 63.10006). **Response to Comments 5**  **4 -**  **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 5 6**  **:** Commenter 17881 states that as currentl y 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/MM Btu 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 5 6**  **:** The f inal rule has be en amended to clarify that only the methodology

or equations required for the specific emission limit will be required. **Comment 5 7**  **:** Commenter 17881 states under Table 1

- Emission Limits for New and Reconstructed EGUs , that the run times sp ecified 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. **Respons e to Comment 5**  **7 :**  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 5 8**  **:** Commenter 17881 questions why (under Table 2

- Emission Limits for Existing EGU s , 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 5 8**  **:** The final rule has be en amended to fix the clerical error.27

**Comment 5 9**  **:** Commenter 17881 states that (under Table 5

- Performance Stack Te sting 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 O 2/CO 2 levels should only need to be determined if complying with the lb/M M Btu standard. **Response to Comment 5 9**  **:** The final rule has be en 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 H F ) 40 CFR p art 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 p art 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 largel y s imilar to Appendix F as proposed but adapt those requirements to fit more closely with approaches taken under Part 75 so that the existing reporting in frastructure for Part 75 reporting can be easily adapted to support this rule. **Comment 6 1**  **:** Commenter 17881 states that (under Table 5) 40 CFR p art 60 , Appendix B, Performance Specification 6 conflicts with the QA requirements in part 63, subpart UUUUU , App endix A for auxiliary measurements. **Response to Comment 6 1**  **:** 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 provis ions for determining the number of sampling points as compared to Method 1. **Response to Comment 62**  **:** The final rule has be en amended to allow the alternative provisions for sample point selection contained in Method 3 0B
. **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. **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 be en amended to clarify that only the methodology

or equations required for the specific emission limit will be required. **Comment 6 5**  **:** 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 ty pes of coals (i.e., anthracite, bituminous, subbituminous, etc.) and between regions (i.e., Illinois Basin coal vs. Appalachian coal). **Response to Comment 6**  **5** : The final rule no longer includes this provision.28

**Comment 6 6**  **:** Several c ommenter s ( 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. Commenter s state that no periodic performance testing and operating parameter monitoring are specified for units that use CEMS but have no controls. **Response to Comment 6 6**  : The final rule does not include the control device continuous parametric monitoring of the proposal and replaced that monitoring with greater reliance on CEMS for control acid gases and the PM CPMS for control of HAP metals and filterable PM. The rule also provides the option to use frequent manual performance testing with the premise the frequent testing (e.g., quarterl y) will ensure that sources must maintain the process and control technologies in condition consistent with compliance performance on a continuous basis. This includes units that comply with emissions limits with no add on control devices. As for augmenting CEMS data with additional performance testing, we believe that CEMS data verified with periodic quality assurance testing and other quali ty control measures as required b y the rule provide means sufficient to demonstrate compliance with the emissions limit on a continuous basis and independent of additional performance testing. **Comment 6 7**  **:** 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 clearl y 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 6 8**  **:** 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 ty picall y, a unit will operate above or below the load conditions during which performance tests are conducted. **Comment 6 9**  **:** 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 significantl y 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 properl y budget and prepare for compliance testing. **Response to Comments 6**  **7 -**  **69 :**  The EPA reviewed , and adjusted as appropriate, the final emission limits and minimum detection levels so that th e rule contains appropriate sample volumes and run durations
.29

**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 c ommenter requests e laboration 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 c ommenter requests that th e 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 a gency 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.30

**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, 18 831, 19032, 19041, 19114, 19121, 18023 **1 . Commenter**  **s upporting**  **c urrent or**  **s horter**  **a veraging**  **t im**  **es .**  **Comment 1:** Commenter 17926 supports and offers praise for the proposed averaging times in conducting Hg

- related testing. According to the commenter, currentl y 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 b y 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 a gency 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 sampl ing 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 fo r 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 fo r 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 a gency 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 a genc y ’ s resources on those poorly performing or problematic sources, instead of penalizing inadvertent occurr ences. **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 day s 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 a gency 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 spikes31

focuses the a gency ’ 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 likel y 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. 2 The commenter be lieves that actual emissions averaged over 30 days during periods when units are operating at lower capacity with cleaner fuels

– are likel y to be much lower
. **Response to Comment 4:** The comment is m oot, as the rule no longer has numeric emissions limits a pplicable during periods of startup or shutdown. **2 . Commenters**  **s upporting**  **a nnual**  **c ompliance**  **p eriods**  **r ather than 30**  **- d**  **ay p**  **eriods .**  **Comment 5**  **:** Numerous c ommenters (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 th e 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. Co mmenter 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 a gency 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**  **a nnual**  **a veraging**  **d ue to**  **SSM i**  **ssues .**  **Comment 6**  **:** Multiple c ommenters (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 IC R 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
.32

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 day s to accommodate periods of startup and shutdown. **Comment 7**  **:** Several c ommenters (17718, 17627, 17757, 18037, 18539) note that IC R 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 operati ons, 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 IC R testing b y 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 nearl y impossible. Ac cording to the commenter, a few hours of ESP downtime can destro y 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 c ommenter states that an annualized averaging period is equally effective in reducing the total emissions as is a 30

- day

period. **Comment 1 1**  **:** 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. Accordingl y, 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 1 2**  **:** Commenter 17774 notes that the use of a 12

- month rolling average also assists regulated facilities in meeting what are extremel y strict standards. For example, th e 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
- 177 74
- A1.pdf) show that this unit will not consistently meet33

the proposed 30

- day

rolling average PM limit. The commenter states that although this unit ty pically operates below the proposed limit, there are numerous events (87 exceedances of a 30

- day average in a 2
- ye ar 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 usu ally operate below the proposed limit, there are a number of events (93 exceedances of a 30

- day average in a 2

- ye ar 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 reasonabl y control. The c ommenter 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 1 3**  **:** Commenter 17873 states that averaging time is important in de aling 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 co mmenter 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 NO X control, a spray dryer absorber lime

- based, FGD system for SO 2 control, and a pulse

- jet cleaned fa

bric 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 properl y. 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 SO 2 and NO X using a 30

- day rolling average, and the commenter ’ s experience provides strong evidence of the diff icult 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 significantl y jeopardiz e compliance for both SO 2 and NO X . 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 1 4**  **:** Commenter 17904 notes that even one of its best performing units (Oak Grove Unit 1), a well

- controlled unit, would l ikely not be able to achieve 100 percent compliance. According to the commenter, this is because the EPA ’ s proposed standards have been set too stringentl y, even for these units that were put into commercial operation since 2009 and are equipped with the most advanced, commerciall y 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 c ommenter urg es the EPA to establish longer averaging times to smooth out this34

variability . The c ommenter 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, apparentl y the EPA believes this would increase owner or operator risk of non

- compliance and liability

associated with non

- compliance, bec ause owners and operators would decide to onl y check control devices once per year. However, the commenter states the length of the compliance period is extremely unlikel y 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 th e same time applied its UPL variability anal ys is to set a lower numerical emissions rate. **Comment 1 5**  **:** 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 malfuncti on, 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 efficientl y reducing emissions consistent with the EPA policy and as such, are not an acceptable approach to periods of malfunction. **Comment 1 6**  **:** 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 furth er 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 boiler

operating 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 1**  **7 :**  Commenter 17740 states that the EPA ’ s conclusion that EGUs “ do not normally startup and shutdown frequently” effectivel y, 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 frequentl y, 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 operat e as reliabl y as newer units. According to the commenter, as EGUs age, they tend to experience more forced outages than when they were newly35

constructed; thus, an older EGU with highl y 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**  **- 1**  **7 :**  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 excee dances that may be caused by

such events. With these provisions, EPA believes that the concerns raised in these comments are appropriatel y addressed without modifyingthe general use of 30

- day rolling averages for this rule. See also preamble and response to comments below explaining EPA's approach to malfunctions. 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 1 2
- hour or similar averaging periods specified in the final rule. **4 . Supporting**  **l onger**  **averaging t im**  **e d**  **ue to h**  **ealth o**  **utcomes .**  **Comment 1 8**  **:** Several c ommenters (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 c ommenters (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 sug gest 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 1 9**  **:** Multiple c ommenters (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, particularl y 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 onl y 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 b y lower emissions during the next month(s), the health impact would be essentiall y identical to a source with no “ups and downs ” in the monthly emissions but with the same annual emissions. **Comment 20**  **:** Multiple c ommenters (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 creates36

acute or accumulative impacts. For example, according to the commenter, acid g ases are of concern for 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 1 8**  **- 20**  **:** The EPA establishes the limits based on the m aximum 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 tes ting where the margin of compliance indicates a reduced likelihood for potential noncompliance situations. **Comment 2**  **1:** Several c ommenters (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 2**  **1:** An Hg CEMS and an HCl CEMS are option s for use as the performance test method for the applicable Hg and HCl emission limits. I f 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 an d 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 emissio n limit as demonstrated in a periodic stack test. **Comment 2 2**  **:** Several c ommenters (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, s orbent 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 2 2**  **:** The a gency believes a number of Hg C EMS 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 co ntrol 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**  **u ncertainty**  **. Comment 2**  **3 :**  Several c ommenters (17725, 18014, 18498) state that in reviewing th e 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.37

**Response to Comment 2 3**  **:** The CEMS data will be quality

- assured in accordance with the rule requirements. Provided the monitoring s ys tems are producing valid, quality

- assured data, EPA will use 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 p art 60 in the 1980s. The data under this rule will be treated in accordance with those longstanding principles and regulatory provisions. **6 .**  **30 -**  **day rolling average is inappropriate**  **. Comment 2**  **4 :**  Several c ommenters (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 malfun ction) that single day will affect the 30

- day

average calculated not onl y for that day , but also the calculated averages for the next 29 days). Several c ommenters (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 2 4**  **:** The final rule includes a work practice in lieu of numerical limits to apply during periods of startup and shutdown. The scenario the commenter raises relative to startup and shutdown emissions inordinately affecting the 30 day

average should be moot. The rule als o includes provisions for the source owner to appl y for an affirmative defense of excess emissions that occur during malfunctions. We believe that the rule addresses these comments such that the source owner has the flexibility to manage process and contro l device operations in a timely fashion relative to the averaging time of the standards. See also response to Comments 6 through 17, above. **7 . Support**  **a nnual**  **f**

**uel v**  **ariability .**  **Comment 2 5**  **:** Several c ommenters (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 betwe en compliance and noncompliance with the EPA ’ s proposed air toxics rule. **Response to Comment 2 5**  **:** As the rule no longer contains fuel content metals or acid gas operating limits but maintains the UPLcalculations to account for variability , as discussed el sewhere, 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 2 6**  **:** 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 onl y on 40 hand

-picked best performing units, and it is possible that the Hg content in a particular coal shipment could be high38

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 2 6**  **:** The a g ency 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 UPLprocedure 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**  **a lternative**  **c om** **pliance a**  **pproaches .**  **Comment 2 7**  **:** 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 commenter s 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 2 7**  **:** See response to Comments 6 through 17 and 24 , above. **Comment 2 8**  **:** Commenter 19121 encourages the EPA to reconsider increa sing 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 ha s 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 2 8**  **:** As mentioned in earlier responses, the a gency believes the rule ’ s averaging time appropriatel y accounts for brief, transient emissions spikes enabling the a gency 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**  **c larification/**  **e xplanation**  **. Comment 2**  **9 :**  Commenter 17638 urges the EPA to clarify that a “ 30 operating day

rolling average ” is determined b y 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 dail y 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 dail y averages is not fair to units that frequently cycle on and off and could weight a 15

- minute period equall y to a 24
- hour period.39

**Response to Comment 2 9**  **:** The final rule clarifies that the average is based on all valid hourly averages during each 30

- day

rolling average period. Hourl y 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 provi de 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 average does not address this issue, because Appendix A, S ection 6 (76 FR 25144), Equation A

- 4 requires Hg emissions to be calculated on an hourly bas is 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 s ection 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 o f 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 day s divided by the sum total output over the 30 boiler operating day s. 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 independentl y, 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 app licable 30

- day averaging period, the source is in noncompliance and subject to penalties unless the source demonstrates that the affirmative defense applies
. The commenter is correct that it may not be possible to demonstrate compliance with the output

- based emissions standards under the scenario outlined above. We do not agree, however, that a source would automatically

be in violation of the standards because the source could demonstrate that during those periods the source was meeting the applicable input - based standard contained in the final rule. An existing source compl ying with the output

- based limits during periods of normal operation would have to demonstrate that it complied with the applicable input

- based standards during the malfunction event.40

The source will need to include in its malfunction report the additional calculations and an explanation to demonstrate that the source complied with the standard notwithstanding the malfunction event. Sources compl ying with the input

- based limit would not have to take additional steps to demonstrate compliance during the malfunction event. For these reasons, we are not amending the final rule in the manner suggested b y the commenter. **Comment 31**  **:** Commenter 17705 recommends that the final rule define “boi ler 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 speci fy 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 response s to comments under Comment Code 5A12 of this document for further discussion on data availability
. **Comment 3**  **2:** 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) th e number of valid data points required for a valid 30

- day average. **Response to Comment 3**  **2:** 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 response s to c omments under Comment Code 5A12 of this document for further discussion on data availability
. **Comment 3 3**  **:** 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 cal culated 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 “hourl y 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,41

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 dail y averaging approach woul d 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 3 3**  **:** The final rule clarifies that the average is based on all valid hourly averages during each 30

- day

rolling average period. Hourl y averages are not summed to a daily average as an intermediate data value for purposes of determining each 30 boiler operating day average. **Comment 3 4**  **:** 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 3 4**  **:** Averaging periods apply for emission limits where a CEMS is used to determine compliance and fo r 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 3**  **5 :**  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 compl iance 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 facil ity

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? ” 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 3 5**  **:** 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

th e end of January , as that report covers the time period of July 1
- December 31. The agency

disagrees with the commenter’s view that a 30

- boiler operating day rolling average is inconsistent with historical averaging times for this industry . For example, the new source performance standard, subpart Da for electric utility steam generating units in existence for over 30 years, uses 30 boiler operating days for the rolling emissions averaging period. **Comment 3 6**  **:** 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 hourl y particulate emissions data for the preceding 30 boiler operating days ” (citing 76 FR 25,112/2). According to the commenter, p roposed 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 p roposed 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 would42

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 3 6**  **:** 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 day s, with no intermediate dail y values used to determine the 30

- day average. The agency

disagrees with the commenter’s suggestion that the 30

- boiler operating day rolling average period lacks sufficient support; use of a 30

- boiler operating day

rolling average period data management during startup and shutdown periods are discussed elsewhere in this document. **Comment 3 7**  **:** 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 63.100 10(f) refers the reader to Appendix A, but Appendix A does not state the compliance metric. **Response to Comment 3 7**  **:** See Section 6 of Appendix A to the final rule for the calculation procedures. **Comment 3 8**  **:** 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 3 8**  **:** The final rule clarifies that the average is based on all valid hourly averages during each 30

- day rolling average period. Hourl y 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. **Comm ent 3**  **9 :**  Commenter 17820 states that the 30

- day rolling average limits should contain at least 30 full days of operation. **Response to Comment 3 9**  **:** 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. **Comment 40**  **:** Commenter 18014 states that Table 8 requires the source is to convert “hourl y emissions concentrations to 30 boiler operating mg/dscm values, ” which suggests that compliance is assess based on the averag e 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 hourl y particulate emissions data for the preceding 30 boiler operating days. ” **Resp onse to Comment**  **40 :**  See response to Comment 3 3 , 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 of43

three runs and the lo west 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 3 6 above for the only remaining operational parameter that applies under the final rule. **10 . Rule**  **l anguage**  **c orrections**  **. 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 onl y 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, ne ither has been sufficiently supported. “ **Response to Comment 42**  **:** The final rule clarifies this issue; see response to Comment 3 3 , above. **Comment 4 3**  **:** Commenter 17638 requests a mass
- based alternative compliance option b y 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 c ommenter notes that Florida h as 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 p art 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 4 3**  **:** While the EPA appreciates the suggested alternative, we have not conducted anal ys es to asses s 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 monitored and tested for compliance. Thus, the EPA does not believe this ty pe of alternative is necessary or supported at this time. **Comment 4 4**  **:** 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 c ommenter 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). Hb i = Total heat input for all units included in the averaging plan for month I , in units of44 MMBtu
. **Response to Comment 4 4**  **:** The rule replaces a 12

- month rolling average with a quarterl y weighted average. As the monthl y weighted average (ERi ) already makes the adjustment suggested b y the commenter, per Equation 3 or Equation 4, the a gency sees no reason for keeping Equation 5, so it has been removed from the rule. **Comment 4 5**  **:** 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, thereb y introducing a disconnect between the average emission rate and heat input value used for weighting purposes. The c ommenter states that Equations 1

– 4 should specify procedures for reducing CEMS data into average values for purposes of the “ Er” term. The c ommenter 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 4 5**  **:** The final rule includes clarification of the emissions averaging proce dures and calculations to be consistent with calculating compliance with the 30 boiler operating day average for emissions rates elsewhere in the rule. The revised procedure also allows for using CEMS data in combination or in lieu of performance testing data for determining compliance with the emissions limits. **Comment 4 6**  **:** 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 ty pically 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.) **Response to Comment 4 6**  **:** The commenter appears to confuse the a gency ’ s standard setting activities (that include UPL calculations) with collection of CEMS data. The compliance options that rel y on use of a 30 boiler operating day rolling average are not at odds with the statistical approach for determining the emissions lim it. 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 a gency to focus on the poorl y operated or problematic EGUs.45

**5A03 -**  **Testing/Monitoring: Fuel analysis methods Commenters**  : 17316, 17386, 17402, 17621, 1771 5, 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**  **n atural**  **g as**  **. Comment 1:**  Commenter s 17316 and 17386 request that the EPA exempt the fuel analy sis 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 ty pe 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 anal ys es if a unit burns a single fuel ty pe, be extended to exemption any

unit which burns only

one fuel typ e, aside from pipeline natural gas ( i.e., burns 2 fuel ty pes, but one is pipeline natural gas). **2 . Initial**  **c ompliance**  **f**

**uel a**  **nalysis .**  **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 anal ys is, 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 anal ys is 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 6 3.10005(c)(4) suggests that such EGUs are exempt from any initial fuel anal ys is, 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 comm enter assumes the EPA intended liquid oil

- fired EGUs demonstrating compliance through fuel anal ys is to conduct an initial demonstration using fuel anal ys is, but that such EGUs that combust only a single fuel ty pe are not required to make any other demonstr ations 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 ty pe of fuel ” from the fuel sampling and anal ys is 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 de fined b y ranks (e.g., bituminous, subbituminous , lignite) or even more narrowl y ranked b y mine location or even coal seam. **Comment 5:** Commenter 17775 suggests for EGUs opting to demonstrate compliance using fuel anal ys is (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 onl y sections of section 63.10011 or Table 8 that could have any applicability to EGUs complying through fuel analy sis 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 EPA46

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 b y 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 periodicall y collecting fuel samples and showing that the actual results meet the limit. **Comment 8:** Commenters 18 014 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 anal ys is 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 ty

pes or blends and suggest EPA clarify this exemption in the final rule. **3 . Fuel**  **s am** **pling p**  **rocedures .**  **Comment 9:** Several c ommenters ( 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) f uel 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 co

firing natural gas if fuel sampling of the natural gas required. **Comment 10:** Commenters 17316 and 1738 6 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 wi ll 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 necessaril y 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 p resent 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 s ystem, 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:** Commenter s 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 anal ys is 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 to47

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 c ommenters 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 anal yz ed 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 sh eet 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 P M 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 oper ator elects to compl y 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 believ es 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**  **m etal emission limits, y** ou 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**  **em ission 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 ty pes and mixtures of fuels b urned 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,48

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 yo u demonstrate compliance through performance stack testing). **Comment 17:** Commenter 19121 bel ieves 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 comm enter states that ASTM has developed methods that utilize automated and continuous sampling s ys tems, and such equipment is present at many coal plants, and the sy stems are bias tested against ASTM standards. The commenter also notes there are also ASTM app roved sample preparation standards utilizing riffle, grinding, and drying equipment designed to meet applicable ASTM methods. **4 . Fuel**  **s am** **pling r**  **equirements f**  **or s**  **ources with CEMS**  **. Comment 18:**  Multiple c ommenters ( 17402, 17725, 17800, 17820 18014 , 18498 ) bel ieve 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 onl y to those units that demonstrate compliance through “performance testing ” for a particular pollutant. The comm enter 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 anal ys is. The commenters note that fu el sampling is certainl y required for oil

- fired sources that demonstrate compliance through fuel anal ys is, 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 generall y 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, thereb y creating ambiguity in whether other parts of the rule that pertain to units using stack test data to comply also appl y to those units using a CEMS for co mpliance. **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 initial49

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 th at EGUs meet operating limits for all relevant control devices and load regardless of the “perfo rmance testing ” option they choose. **Comment 22:** Commenter 17758 notes that proposed section 63.10008 lays out in detail a fuel sampling and anal ys is 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, oxidiz ed 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 oxidiz ed 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 readil y removed in prevalent control technologies). **Comment 24:** Commenter 18015 requests that the EPA clarify the applicability

of the fuel anal ys is requirements; specifically , the commenter recommends that the EPA state in the preamble and the final rule that fuel anal ys is is not required for units that use CEMS to continuousl y compl y 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 separatel y), 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 appl y, 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) speci fied in the paragraph. **5 . Fuel**  **s am** **pling r**  **equirements for s**  **ingle -**  **f uel**  **u nits**  **t hat**  **c om** **ply with o**  **ne or m**  **ore s**  **tandards b**  **ased on**  **s tack**  **t esting**  **. Comment 26:**  Commenter s 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 c ommenters ( 17402, 17820 , 18498 ) believe the rul e is unclear as to whether units that fire a single type of fuel are exempt from all fuel sampling and anal ys is requirements. According to the commenters, the EPA appears to exempt units that fire a single fuel ty pe from conducting fuel50

anal ys is 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 onl y be required every six months, unless a facility changes fuel ty pe. Acco rding 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 ty pe ” in se ction 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 th e 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 ty pe, fuel sampling and anal ys is 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 ty pes 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 hi ghest 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 anal ys is requirements for single fuel EGUs and supplemental fuels. **6 . Low**  **e mitting**  **EGUs .**  **Comment 31:** Several commenters (17402, 17754, 17808) believe the LEE monitoring requirements are overly burdensome. Commenter 17808 believes in many cases, monthl y 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 mo nthly fuel anal ys is 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, anal yz ing fuel monthl y when the fuel suppl y or mixture has not changed seems unnecessary . The commenter states that if the EPA intended to require that LEEs establish and comply with maximum51

fuel input levels as an “ operating limit” under section 63.10011(b), rather than perform monthly fuel anal ys i s, 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 re quirement 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 an d how they

appl y. **Comment 33:** Several c ommenters ( 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. Acc ording to the commenters,, the requirements do not address single

- fuel units, changes in fuel ty pe, or units that burn or co - fire multiple fuels. The commenters assert that presumabl y, LEE units would follow an analogous procedure as non

- LEE units and reas sess 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

- LE E 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 ty pe. For single

- fuel units, the commenters suggest the EPA specify that these uni ts 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 performa nce testing only , rather than monthl y 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 90 th percentile c onfidence 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 c ommenter s ( 19536 , 19537 , 19538 ) believe the EPA should discard its “ Lo w 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 b yproduct 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 sy stems. These would not be detected b y fuel sampling. **Comment 36:** Commenter 17808 recommends that for non - Hg HAP as well, owners/operators o f 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 continuou s compliance and maintain LEE status through monthly fuel anal ys is as well as performance (stack) testing every 5 years. However, in many cases, according to52

the commenter, monthly

fuel testing would be redundant as this requirement would result in the rep etitive 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 alternativel y 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 th en 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**  **o il**  **- b**  **ased EGUs**  **. Comment 38:**  Several c ommenter s ( 17758, 17775 , 18428 ) suggest the alternative fuel anal ys is 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 no t 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 anal ys es to demonstrate initial and continuous compliance with applicable emission limitations, as an alternative to performance stack testing. The commenter request s 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 1 7621 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 anal ytic 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 analy tical methods f

or non - Hg metals in oil are too high to support compliance verification. According to the commenter, in the IC R 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 mill ion 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 IC R 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 me tals concentrations would need to be quantifiable below 0.01 ppmw to demonstrate compliance. According to the commenter, the analy tical techniques currently used for fuel oil samples by most laboratories cannot measure accurately at those levels. The commenter suggests allow ing fuel oil monitoring to be53

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 anal ys es and procedures in the proposed regulatory language (40 CFR section 63.10008) are onl y 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 anal ys is. The commenter believes the language in the preamble to the proposed rule and the proposed regulatory language are inconsistent regarding the availability of the fu el anal ys is 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 M y 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, anal ys es , 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 fue l limits appears applicable onl y t o facilities that choose to comply via fuel anal ys is. The commenter believes if facilities appl y CEMS , accurate compliance can be determined at the emission point and, therefore, the fuel input becomes irrelevant. The comm enter 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**  **f**

**uel a**  **nalysis .**  **Comment 45:** Several c ommenter s ( 17386, 17758, 17760 , 17902 ) believe the monthly fuel anal ys is contained in section 63.10006(s) would be unnecessarily burdensome, costly

and impractical. One commenter suggests requiring fuel anal ys is 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 unlikel y that the composition of the fuel oil will change. Commenter 17386 notes that for large fuel oil storage tanks which receive oil deliveries less frequentl y than monthly the requirement is unjustified and proposes fuel sampling for oil

- fired units shall be performed quarterly onl y 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.54

**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 yearl y stack testing with a monthly fuel sampling. **Comment 47:** Commenter 17807 notes that although they prefer that SO 2 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 currentl y utilize some ty pe of fuel sampling methodology to test their fuels burned, and the chloride content can be anal yz ed using ASTM 4208 /300 along wi th 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 weekl y 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**  **- s**  **pecific f** 

**uel a**  **nalysis p**  **lans .**  **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 process ed 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 b e submitted to the Administrator at least 60 days before the fuel anal ys is. Because some of the information required to be included may change from anal ys is to anal ys is, 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 ty pes anticipated to be combusted and whether the source or fuel supplier will conduct the anal ys is. 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 anal ys is, it may

not be possible for subsequent anal ys is in response to chang es 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 EP A 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 anal ys is 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 full y capable of following and implementing those requirements. The commenter notes there will be hundreds of fuel anal ys is p lans 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, this55

could mean that a source might not be able to complete performance testing before the deadlines specified in the rules. The commenter th erefore urges the EPA to modify this section of the proposed rule to eliminate the requirement for the EPA to approve fuel anal ys is plans prior to conducting testing. **Comment 51:** Commenter 17881 notes that section 63.1008, requiring development of a site specific fuel anal ys is plan, as applicable, is very unclear how to determine if you need a fuel anal ys is plan as section 63.10005 does not stipulate which units are required to conduct fuel analy sis 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**  **t esting and**  **f uel**  **a nalysis**  **. Comment 52:**  Commenter 17775 cites proposed section 63.10011(b) that “ if you demonstrate compliance through performance testing, . . . [y] ou must also conduct fuel an al ys is 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 ty

pes and mixtures used to demonstrate compliance with fuel input levels under section 63.10011(b) and (c). The commenter states that accordingl y, 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 cont ent” 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 18 447 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 yo ur 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 (b y 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 c ontent, 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 te sted, especiall y if the EGU56

operator elects to compl y 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 ty pe 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 yo u must demonstrate initial compliance and establish your operating limits based on these tests. ” **11 . Continuous**  **c ompliance**  **. 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 exemp ted 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 variou s 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 woul d not apply as direct sampling would be used to demonstrate compliance. The commenter believes the monthly compliance demonstration through fuel anal ys is is all that is required to comply with the Hg emission limit instead of trying to theoreticall y pre - qu alify

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 appl y as direct sampling would be used to demo nstrate 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 tryingto pre - qualify a fuel does not work in the real world, as what is sampled for the pre

- qualification anal ys is is most likely not what is reall y burned, as oil is blended in a storage tank prior to burning; the onus of proof of compliance is on the facility
. **12 . Chloride**  **c oncentration**  **v ariability**  **. Comment 59:**  Commenters 17816 and 19114 note HCl CEMS currently are not commerciall y 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, ac cording to the commenters, sources will be forced to either take a fuel limit or an operating parameter limit. The commenters believe the fuel anal ys is 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 co mpliance testing. **13 . Stop**  **b elt**  **s ampling (**  **s ection**  **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 conveyor57

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 adequatel y 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 s ys tem. **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. **C omment 63:**  Commenter 17800 believes the proposed stop belt sampling requirements for collecting composite fuel samples is not reasonable and apparentl y would not allow for the use of continuous belt samplers. According to the commenter, in addition, many b elts 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 e xactly “ 18 inches, ” collection at five locations “uniformly spaced over the surface of the pile, ” and breaking of pieces larger that exactly 3 inches (citing p roposed 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 gre ater 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 currentl y 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 currentl y 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 hav e been following such practices successfull y 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 i s dangerous, logistically

and operationall y intrusive, and unnecessary. **14 . Coal**  **s ampling**  **m ethods**  **.**58

**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 no tes they utilize automated mechanical coal sampling s ys tems that are operated under procedures such as those described in ASTM D2013
. According to the commenter, these automated methods are widel y accepted and do not require the labor

intensive and time

- co nsuming 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 strongl y 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**  **c omments**  **. Comment 69:**  C ommenter 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 inherentl y 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 n ot most lignite units burn a blend of coals, e.g., lignite and PRB; and s econd, 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 ty pically relied upon to classify

distinct coal regions and individual seams don ’ t vary significantl y within a region . According to the commenter, the ASTM D388 method specificall y 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) h ave been independentl y 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 SO 2 , 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.59

**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 co nvert emission concentrations into units of lb /MM Btu . 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 availab le 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

- co mbustion controls. **Comment 74:** Commenter 19114 notes that IGC C 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 c ommenter, if IG CC 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 sy ngas sampling, clean sy

ngas sampling, sy

ngas fired in the combustion turbines, sy ngas fired in a flare, processed sy ngas 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 “ yo ur operating limits are based on ” (citing s ection 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 probabl y 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 p roposed section 63.10008 requires “performance fuel analysis tests ” “ as applicable ” ; Table 6 requires fuel analysis “ as stated in section 63.10008 ” ; and p roposed 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 chlorin e, 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 oil60

before combustion in lieu of installing air pollution control device s ( 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 sy

ngas ) should be an option for IGCC as well based on the same reasoning as to that fuel “ clean

- up ” vs. APC D . 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

- combustio n control. **Response to Comments 1**  **- 76:**  Based on the comments received and a further review of the technical challenges associated with the proposed fuel anal ysis requirements, the EPA has not finalized the proposed fuel anal ys is requirements. Fuel anal ys is of moisture for certain l iquid oil

- fired units remains a compliance assurance option. As the rule no longer requires operating limits for pollutants based on fuel content or fuel anal ys is, the comments summarized above are largel y moot. For low em itting 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 fo r Hg using Method 30B each year. Neither fuel anal ys is 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

- ye ar 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 co ntent 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 yo ur fuel supplier. Should the moisture in yo ur liquid fuel be more than 1.0 percent , you must either: (1) conduct HCl and HF emissions testing quarterl y and develop a site

- specific monitoring plan to monitor appropriate operating parameters to ensure that operations remain consistent with those pres ent during performance testing; or (2) use an HC l CEMS and/or HF CEMS.61

**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**  **t echniques and**  **d etection**  **l evels**  **. Comment 1:**  Commenters 17316 and 17386 state that based on contacts with a number of laboratories, it appears that standard available anal ytic 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 allegedl y addresses the concentration in oil for each regulated HAP metal corresponding to p roposed 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 labo ratories contacted could achieve this detection level. Moreover, the commenter questions the accuracy of anal ys is results determined by the specialized methods used to reach the detection levels required for such a compliance demonstration on fuel oil. **Re sponse to Comment 1:**  The requirements for fuel sampling and anal ys is 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 s ys tems have to be capable of accurately measuring emissions below the limits established by

the EPA and in practice emission control technologies mus t 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 operati onal 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 s ys tems, 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 me asurement 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 thoroughl y di scussed in 4A03 of this document , the new source limits have been revised in order to represent the representative detection level (RDL) instead of the MDLdetermined 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 anal ys es . 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
.62

**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. There is discussion elsewhere in this document of how the agency managed BDL data in anal yzing the floor and developing emissions limits for this rule. **Comme nt 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 allow ance 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 a s high as 50 % . The commenter references U.S. EPA “ Review of National Primary Drinking Water Regulations: Analy tical Methods

- Reassessment of Practical Quantitation Limits, noting that the EPA guidance suggests a multiplier of 5

- 10 times the MDL for determ ining 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 excepti on of a PM CPMS and provides the option for periodic testing for non

- Hg HAPs
. Hg s orbent monitoring allows for sensitivities below the emission standards. **Comment 6:** Commenter 18034 states the proposed emission limits for some of the pollutants are very ne ar 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 emissi on 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 analy tical technique and met all QA/QC criteria of Method 30B in a 4
- hour run. **Comment 7:** Commenter 17715 notes that NI ST traceable standards, gaseous oxidized standards traceable to NI ST and agreed to standard Hg vapor curves are not available, and without them there will be non

- uniform reporting of emissions.63

**Response to Comment 7:**  Itis 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 NI ST
- 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 NI ST elemental mercury reference standards. We agree with the commenters ’ point that NI ST does not currentl y directly certify oxidized mercury gas generators. However, oxidized gas generator NIST traceability is establi shed through the assessment of the individual components of the calibrator. The interim protocols for certifyingmercury 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 NI ST traceability for calibration gases is ba sed on direct comparisons with NI ST reference materials and standards. **Comment 8:** Commenter 17790 believes the EPA should specify specific guidelines for anal ytical detection limits stack testing for non

- Hg HAP metals and how to handle results that are bel ow the detection limit. **Comment 9:** Commenter 17800 believes the non

- Hg metals data collected during the 2010 IC R showed reported detection limits for laboratory anal ys is that were highl y 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 h alf 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 anal ytical finish used. Table 5 will be revised to specify th e 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 thoroughl y discussed in Section 4A03, the emission limits for new and existing sources were set at a minimum of three times the RDL to provide f or 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 ye ars. 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 propo sal. 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).64

**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 thi s 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 anal ys is 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 IC R , the reported detection limits for laboratory anal ys is were highl y variable even for data for the same analy te from the same laboratory. The commenter suggests that to determine compliance on a consis tent 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

anal ysis of all pollutants. Minimum detection limits will improve with future technology

and analy

tical 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 reliab le 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 IC R data set), and accuratel y measuring these concentrations with CEMS is nearly impossible. According to the commenter, to date Hg, PM and particularl y HCl CEMs have not been designed to measure very low pollutant concentrations. The commenter believes that the EPA should recognize the limit ations 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 po tential for numerous non

- compliance events. **Response to Comment 13:** An Hg CEMS or an HCl CEMS are option s for use as the performance test method for the applicable Hg and HCl emission limits. I f 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 f ilterable 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 analy

tic 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.65

**Response to Comment 14:** As further di scussed 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 s uggests 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 limit s to be so stringent that they are actuall y 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 c onsistent 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 greatl y complicated b y the fact that a number of HAP were emitted at levels at or below the reporting limits for the test methods required for colle ction 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 anal ytical 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 sections 4A03/4 of this document , we believe that the procedures used in managing BDL data in establishing the floor values and setting emissions limit and we have discussed this procedure in detail elsewhere in this document. The EPA is not setting standards below the detection limit so those comments are moot. **Comment 17:** C ommenter 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 believe s 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 anal ytical technique and met all QA/QC criteria of Method 30B in a 4
- hour run , meaning that current instruments can measure mercury emissions at the level of the emissions standards
. The agency disagrees with the commenter’s assertion that the mercury emissions limit for new sources would act to ban construction of new coal plants; on the contrary , at least one or more existing EGUs66

reported mercury

emissions at or below the emissions limit for new sources, for values from existing units were used to establish the mercury limits in the rule. **2 . Concerns with**  **s pecific**  **t es**  **t m**  **ethods .**  **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 anal ys is 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 agency disagrees with the commenter’s view that potential issues with the listed EPA Methods renders them less than useful for this rule. The rule identifies potential problematic areas for the Methods, and provides alternatives, both within the Method s and through the use of other means to determine compliance. Should an EGU owner or operator believe the potential issues with emissions testing to be problematic, he or she can choose to use continuous emissions monitoring systems to demonstrate complian ce. The EPA Method 23 is not required for the final rule. The EPA agrees that “extraction, processing and analy sis” 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 thos e 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 S tudent

- 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 sug gests 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 analy tical technique to provide a guideline on choosing the appropriate analy tical technique. The EPA Method 5 MDL was published with the promulgation of Method 5I . The Method 26 and 26A ty pical method detection limits were also published. As more th oroughl y 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 to67

the commenter, this fundamentally differs from masses that fall within the cal ibration 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 fiel d sample anal ys is 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 LO Q ). According to the commenter, all masses determined above the LOQ are of acceptable quality and a known uncertainty of ±10 percent, and converse ly , masses determined using the response factor approach are of unknown quality and uncertainty, they are merel y estimates. **Response to Comment 20:** The a gency agrees with the commenter that this could be a concern, especiall y 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 b y 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 LO Q data collected vary among labs, anal yz ers and anal ys ts. 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 lowe st 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 merel y 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 IC R test ( i.e., 2hr test run collecting 120l of volume) that effluent concentratio ns 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 acc eptable 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/m 3 and 0.08 μg/m 3 are the lowest that can be reasonabl y 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/m 3 could 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 consistentl y provide reliable data for compliance determination for the proposed limit as factors such as blank contamination,68

positive and negative biases due to flue gas interferences , and analy tical errors raise 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 IC R 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**  **:** We agree that there are method detection level capability differences between Methods 26 and 26A and both are allowed by the rule. The source has the option to choose the method and the required sampling periods consistent with expected emis sions levels and the procedures for managing method detection levels in determining compliance. **Comment 23:** Commenter 17621 suggests that Method 29 does not have adequate sensitivity to measure antimony

accurately

at the alternative individual metal MACT l imits 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 coal

fired 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 anal ytical 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 I CR results in the determination of m ethod 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 including the data collected with Method 29 . ASTM 6674
- 02 has been removed from Table 5 for use with comp liance 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 high er sample volume than required minimums listed in Table s 1 and 2.69

**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, 179 28, 18014, 18015, 18021, 18025, 18037, 18426, 18428, 18429, 18437, 18498, 18539, 19033, 19114, 19120, 19121, 19536 , 19537 , 19538, 18023 **1 . Objections to**  **p arametric**  **o perating**  **l imits for**  **u nits with**  **CEMS (**  **s ection 63.10007(c))**  **. Comment 1:**  Numerous c ommenters (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, 18 015, 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 parametri c 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 c ommenters (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 sur rogate. **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 c ompliance 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 othe r 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 “ yo ur operating limits are based on. ” The commenter also states that s ection 63.10011(c)(6) addresses fuel sampling, not operating limits and that s ec tion 63.10011(b)(6), the provision the EPA likely

meant to cite, refers onl y to control devices and not compliance options. Commenter 17868 concludes that the preamble discussion contains numerous inconsistent statements and no rationale b y which one could determine the EPA ’ s intent with respect to these operating limits for units using CEMS and sorbent trap monitoring systems.70

**Comment 4:** Commenter 17718 states that the EPA should require no proof of compliance beyond a properl y 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 commerciall y 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 anal ys is 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 wh ich 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 unit s using CEMS and sorbent trap monitoring s ys tems. For example, according to the commenter, the EPA suggests in the following statements that operating limits apply onl y to units without CEMS:

 IGCC units or units combusting coal or solid oil

- derived fuel wi th 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 SO 2 or HCl CEMS but with SO 2 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 t esting.
 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 c ommenter 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 anal ys is that it presumably believes are consistent with that assessment. **Comment 7:** Several c ommenters (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.71

**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 c ommenters (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 emi ssions 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 s et at high load. These commenters advise that when variable load operations are combined with variable coal properties, operating parameters can differ significantl y 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 th e 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 par t 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 ty pes of monitoring are preferable from a technical and policy

perspective as a means of assuring compliance with applicable requirements because they

can provide data directl y 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 severel y 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 n oncompliance 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 properl y reflective of s ys tems ’ capabilities . The co mmenter notes that current operation must be flexible enough to meet not only load swings but also future regulation s.72

**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 SO 2 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**  **p ollutant**  **t esting**  **. 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 SO 2 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 b y 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 perf ormed 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**  **o bjections to**  **e nforceable**  **p arametric**  **o perating**  **l imits (**  **section 63.10007(c))**  **. Comment**  **15:** Multiple c ommenters (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 c ommenters ( 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 avoid73

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 operation s to allow testing as close as possible to their emission limit by

reducing performance of their controls. These commenters generall y 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 b y 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 c ommenters (17675, 18037, 1 8429) generally believe that the CAM approach (that allows operators to propose excursion levels and response requirements for approval b y 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 b y a manual stack test. Ho wever, 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 b y 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 reasonabl y 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 unreasonabl y 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 op erating 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 i s difficult. The commenter notes that the ability

of its coal generating units to change load quickly and efficientl y is critical in accommodating variable wind energy . The commenter is concerned about the adverse effect on grid74

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 effectivel y 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. Acc ording to the commenter, it may

be difficult to meet these site

- specific limits at all times under all operating conditions. **Comment 23:** Several c ommenters ( 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 clearl y demonstrates this is the only means of assuring compliant emissions. Commenter 17705 states that establishing the app ropriate parametric limits must be done on a case

- by

- case basis as allowed under CAM rules. **Comment 25** : Several c ommenters (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 anal ys is of historical operating data during periods when the control device was operating properl y. **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 site

specific 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 E PA must account for the added costs and burdens sources will inevitably encounter trying to meet site

specific limits.75

**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 effectivel y lowers the numerical MACT floor. According to the commenter, it makes little sense to set a MACT fl oor 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 , completel y 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 SO 2 CEMS data was deemed sufficient b y 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 CEM S , sorbent traps, or CPMS is needed 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 rel y on quarterl y 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 appl y 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 quarterl y testing) or the potential gaps for liquid oil

- fired units. **4 .**  **Requests to make parametric monitoring requirements more like Compliance Assurance**  **Monitoring (**  **CAM )**  **Program. Comment 30:**  Numerous c ommenters (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 c ommenters (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 u sing 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 c ommenters 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.76

2. Multiple c ommenters (17402, 17715, 17689, 17808, 18037, 18539, 19114) believe that the EPA should revisit the way

operating parameters are set during performance tests that are typicall y completed during high

- load, steady

- state conditions because the operating parameters captured during these tests may n ot 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, 17 736, 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 co ncerned 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 c ommenters (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 underl ying emissions limit. Several c ommenters (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 F R 54,900, 54,907, 54,926
- 27. Multiple c ommenters (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 widel y with little effect on emissions. The c ommenters 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 c ommenters conclude that without a clear correlation between the proposed operating parameters and emission limits, imposition of those values as enforceable limits unreasonabl y 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 (l east 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 which77

are unnecessary

or inappropriate, with parameters that are either already m onitored 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 simpl y 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 h ourly 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. Th e 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 c ommenters (17402, 17627, 17757, 17821, 18023 , 1803 7, 18539, 19114) refer to existing requirements under 40 CFR part 64 commonl y 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 op erators 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 specificall y 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 c ommenters (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 b y 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 adequatel y accounts for variability due to norm al 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 c ommenters provide as another ex ample 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 c ommenters 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 mal functions). 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, 180 25) 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 metals78

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 operatin g 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 dy namicall y 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 th e 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 leve l may not be possible or appropriate at all times, and could damage the control technology
. 8. Several c ommenters (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 c ommenters 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 c ommenters (17775, 17800, 17 820, 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 o r 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 b y the owner or operator. Where parameter monitoring is chosen, we believe that co ntinuous 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 similarl y 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 P art 63. This would include the possibility

of adapting existing CAM plans that may rel y on different parameters. Finall y, 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;79

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 quarterl y testing to demonstrate compliance, yo u will propose a site

- specific operating parameter monitoring plan for yo ur 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**  **t otal**  **s econdary**  **e lectric**  **p ower (**  **TSEP )**  **r equirements (**  **s ection 63.100010(h)(2)(iii))**  **. Comment 31:**  Several c ommenters (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 sy stem 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 power ed 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 co mpliance at all loads. **Comment 32:** Several c ommenters (17775, 17800, 17868, 18428) request that the agency review the discussion on ESP performance in a report b y McRanie Consulting entitled “ Comments on the Proposed Utility MACT Rule

- Operating Parameter s ” (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 directl y related to PM removal performance (particularl y for the modern multi

- section ESPs that are likel y to be installed to comply with a proposed MACT standard), and the total amount of power is not nearl y as important as the location at which the power is being applied in the ESP. The c ommenters 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 highl y 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, especiall y with a wet FGD following the ESP. According to the commenter, none of the ESP parameters are likel y 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
.80

**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 currentl y regulated. **Comment 36:** Commenter 17808 agrees with the principle underl ying the proposed parametric constraints on ESPs (i.e., that maximizing power input and electric field st rength will generall y 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 s ys tem 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 mois ture 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 dam age 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. **Comm ent 38:**  Commenter 17772 notes that total secondary electric power is a poor measure of ESP performance. According to the commenter, this is especiall y 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 fl y 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 tes t day

if a larger number of fl y 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 poorl y relative to the comp liance 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 se condary

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 b y 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 routinel y sees in the operation of its own units. The commenter states that precipitator operation is complicated even further with the addition of s orbents 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 ch ange in the total secondary power to the ESP but not necessaril y a reduction in removal efficiency. The commenter states that the proposed rule should instead require site

- specific plans to be developed81

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 Li mits 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 mo nitoring 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 an d 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 seco ndary 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 entirel y 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 op erating 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 p erformance. The commenter states that lower power generall y means poorer performance, but ESPs are segmented into many el ectrical 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 ty pe 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 additio n 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 Monitorin g (CAM) Protocol for an Electrostatic82

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 complianc e with the NSPS , it also should be sufficient under subpart UUUUU
. **Response to Comments 3 1**  **- 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**  **l im** **its for w**  **et s**  **crubbers ( s**  **ection 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 appl y 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 SO 2 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 SO 2 , 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 c ommenter notes acid gases such as HCl and HF are strong acids and very readily dissolve in water, whereas SO 2 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 likel y to be removed in ty pical 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 effectivel y removed by contact wi th 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 SO 2 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 appropriatel y describe the operation of an FGD sy stem. For example, the commenter suggests that st ations may

elect to use parameters such as number of absorber recirculation pumps in service, measured SO 2 levels from CEMS measurements, or other facility specific measurements. **Comment 46:** Commenter 17821 states that there is ambiguity in what the EPA w ants to restrict. There are two potential liquid flows in an FGD system; the first is the amount of chemical reagent that is added83

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 SO 2 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 SO 2 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 re inforced 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 ab le to provide more accurate readings immediatel y after installation, but the harsh conditions of the FGD will cause them to lose accuracy quickl y. 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 ty pically does not have enough straight lengths of pipe to allow for the installation of highl y 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 sy stem, 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 s ort 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 relativel y 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 by passed. According to the commenter, these parameters will adequatel y ensure that the FGD operation will properl y remove the acid gases that will be regulated in the final rule. **Comment 47:** Commenter 17821 states that re stricting 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,84

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 tr

ue, 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 l ower 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; p ressure drop is more a function of mist eliminator cleanliness than acid gas removal. The commenter notes that there may be steady state s ystems, such as waste combustors , where measuring pressure drop could be useful. The c ommenter 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 agen cies and contain more appropriate requirements such as maintaining a minimum number of recirculation pumps in service, eliminating any by passes 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 flow

rate 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 c ommenters (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 particularl y 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 c ommenters (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 ty pes of wet scrubbers and that the parameters may not be directl y 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 accuratel y 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.85

**Comment 51:** Commenters 17775 and 17881 s tate 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 c ommenters note that pressure drop is not used for control purposes, it is used to determine when cleaning is required and is not necessaril y accurate for assessing scrubber performance. Commenter 17775 states that the EPA must also recognize that Chiyoda s crubbers operate on a completel y different set of parameters than typical spray towers and that L/G is a more useful indicator for some typ es 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 vesse l, not the effectiveness of the slurry spray . **Comment 5 2**  **:** Commenter 18023 states that pressure drop and liquid flow rate are not indicators of the level of PM control being achieved b y 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 b y wet scrubbers ( Commenter refers to Figure 26 in its comment). According to the commenter, PM control by a modern jet

- sparging ty pe 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 liquid

to - gas ratio). The c ommenter further notes that liquid flow rate is not a universal indicator of the PM control achieved b y wet scrubbers. In the commenter ’ s experience, PM removal by a modern spray

tower- ty pe scrubber varies widely for different liquid flow rat es. 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 b y a wet scrubber, and the establishment of these operating limits would unnecessarily limit the range of key FGD operating parameters. The c ommenter states that HCl co ntrol 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 sub mergence suggests that there is also no correlation between HCl emissions and liquid flow rate. **Response to Comments 4 4**  **- 5**  **2 :**  The comments are moot, as the rule no longer includes specific requirements for parametric monitoring or operational limits for ac id gas control devices. **7 . Operating**  **l imits for**  **l ow**  **- emitting**  **EGUs (** **LEEs )**  **. Comment 5**  **3** : 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 properl y. 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 re cent 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 comm enter , this result is not consistent with the impact of minor variations in operating limits, and the EPA should86

remove all operating limits from the rule, and in particular from application to LEEs , where such standards are especiall y inappropriate. **Comme nt 5**  **4** : 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 exi sting 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 5 5**  : 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 5 6**  **:** 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 f ollowing 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 c ommenter, 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 LE Es . According to the commenter, proposed section 63.10021(a)(17) states that, for LEEs , results of emissions tests and fuel analy sis

- presumabl y 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 LE Es suggest they are not required to establish or comply with operating limits. Specifi cally , 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 analy sis monthly
. Commenter 17775 states that if the EPA intended to require that LEEs perform monthly fuel anal ys is 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. Th e commenter believes that anal yz ing fuel monthly when the fuel suppl y 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 analy sis is an operating limit and not a demonstration of compliance using fuel anal ys is under section 63.10011. 4. Commenter 17775 also st ates that the EPA needs to remove the monthly fuel sampling and anal ys is requirement in section 63.10006(c). According to the commenter, if the EPA intended to require that87

LEEs establish and comply with operating limits other than maximum fuel input level s, the EPA needs to issue a proposal that explains the purpose of those limits and how they apply
. **Comment 5 7**  **:** Several c ommenter s ( 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 anal ys is indicates HAP emissions are variable. Monthly testing does not reveal any information about emissions between the monthly tests. According to the commenter s , 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 commenter s 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 commenter s , if the EPA were to provide reduced monitoring for certain low

- emitting uni ts, it should use a UPLfor 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 5**  **3 -**  **5 7**  **:** The comments are inapplicable because the rule no longer requires operating limits for LEEs
. **8 . Oil**  **- f**  **ired o**  **perating p**  **aramete r c**  **omments .**  **Comment 5 8**  **:** 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 5 9**  **:** Commenter 18428 states that it is not clear whether operating parameters and fuel input limits in proposed section 63.10011(b) to appl y to oil

- fired unit s. According to the commenter, the preamble statement suggests that operating parameters do not appl y ( “ 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 oil

fired 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 5 8**  **- 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 quarterl y 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 ac id gas standards. **9 . Minimum**  **s orbent**  **i njection**  **r ates**  **. 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 are88

normally set as a mass flow per volume of flue gas, such as a pound of sorb ent 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. Interestingl y enough, the same mass feed rate of sorbent may actually be more effective at l ow flue gas flow rates, because it has more time to react due to the lower velocity
. However it will also increase the amount of b yproduct 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 becaus e the material can clump or surge, short term measurements such as a 15
- minute interval are too small to absorb all these fluctuations. Finall y, DSI is also closel y 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 6 1**  **:** Several c ommenters (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 injecti on 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 phys ical 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 SO 2 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 stre am 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, so urces should be able to maintain the flexibility necessary

to meet all of their emissions obligations. **Comment 6 2**  : 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. The89

commenters state that the EPA finalized a load factor adjustment in the Industrial Boiler MACT for sorbent and carbon injection; specificall y, 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 hourl y average ” by a new term called the “ load fraction ” (see section 63.7575). **Comment 6 3**  **:** Several c ommenters (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 inje ction rate may be set based on temporary atmospheric conditions requiring more injection for SO 3 control; however proposed Table 4 would require the injection rate based on SO 3 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 6 4**  : 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 6 5**  **:** 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 -**  **6 5**  **:** These comments are inapplicable because the rule no longer requires operating limits for sorbent injection. **10 . PM**  **CEMS o**  **perating l** **imits ( s**  **ection 63.10011(d) and t**  **able 4, p**  **arameter 8) .**  **Comment 6 6**  **:** Several c ommenters (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 1 7775 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 “high est 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 uncorrelat ed CEMS
. **Response to Comment 6 6**  **:** 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 hourl y 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 this90

approach. The final rule does provide for the use of a PM CEMS to determ ine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion). **11 . CPMS**  **a veraging**  **t imes**  **. Comment 6**  **7 :**  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 averag e of the three minimum (or maximum) values from the three runs for each applicable parameter . . . . ” 75 FR 25,029/3. The c ommenter 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 previousl y 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 varianc e 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 6 7**  **:** 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 quarterl y 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 acc ordance 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**  **m oisture**  **m easurement**  **t echnique**  **. Comment 6**  **8 :**  Commenter 17715 proposes an add itional option be available for measuring moisture: if the stack is saturated, a source should be able to use temperature, absolute pressure, and a ps ychrometric chart to determine moisture; temperature and pressure transmitters can be calibrated with NI ST traceable equipment; during periods when the stack is not saturated, default factors listed in the rule could be used.91

**Response to Comment 6 8**  **:** 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**  **r equirements for**  **p arametric**  **m onitoring**  **d evices**  **. Comment 6**  **9** : Several c ommenters (17716, 17725, 18014, 18498) state that source s 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 6 9**  **:** 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 quarterl y 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 generall y for a daily performance evaluation o f 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**  **r ule with**  **d ata**  **g athered**  **d uring 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 bur ning the typ e of fuel or mixture of fuels that has the highest content of chlorine, fluorine, non

Hg 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 conduc ted 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 continuousl y after that point, there is no reason to require worst case testing conditions. **Response to Comment 70**  **:** The agency maintains that it has adequatel y incorporated variability into the final standards in response to other comments on this issue. **15. Frequency of**  **s tack**  **t ests**  **. Comment**  **7 1**  : 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 EGU92

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 especiall y excessive if/when the unit is subject to any additional monitoring requirements. **Comment 7 2**  **:** Commenter 17775 states that proposed fuel input limits and frequent periodic stack te sting 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 P M 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 annuall y unless such a test is triggered b y a change in the maximum fuel input as a result of a change in fuel ty

pe. **Comment 7 3**  **:** 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 so urce 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 addres s 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 7 4**  **:** Commenter 17902 states that testing should be allowed on a less frequent 3

- year or 5
- ye ar 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 7 5**  **:** 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 s ys tem is developed, emissions93

testing once a ye ar or every other year should be sufficient, and even if no emission control sy stem is in place, unless a significant change in the fuel characteristics occurs, emissions testing once a year or every other year should also b e 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 7 1**  **- 7**  **5 :**  The agency agrees that fuel input and frequent periodic stack testing requirements could be duplicative; therefore, the rule no longer requires fuel anal ys is for pollutants. The rule requires quarterl y 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 quarterl y 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**  **pa rameters**  **d uring**  **SSM .**  **Comment 7 6**  **:** Commenter 17886 states that during startup, shutdowns, and malfunction periods use of e stablished 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 7 7**  **:** Several c ommenters (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 EP A 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 s tartup 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 period s 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 frequentl y used loads, an d 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 7**  **6 and**  **77 :**  As mentioned elsewhere, the final rule no longer requires continuous measurement of operating parameters, except when PM CPMS are used and when a liquid oil

- fired EGU without an FGD uses a combination of emissions testing and continuous operating parameter monitoring to demonstrate compliance. Because work practice standards appl y during periods of startup and shutdown, the EPA has clarified in the final rule that the PM CPMS operating limit does not apply during such periods. Instead, for coal and other so lid fuels, the work practice standards for such periods will apply , together with the monitoring and recordkeeping required to document94

compliance with those work practices. The final rule also provides for sources to appl y affirmative defense of excess emissions including deviations from PM CPMS measured operating limits relative to process malfunctions. **17 . Operating**  **l imits**  **b ased on**  **t otal PM**  **. Comment 7**  **8 :**  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 inv olved 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 filterabl e 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 suppl y and operations. **Response to Comment 7 8**  **:** 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**  **c larification**  **on m**  **ultiple l**  **oad t**  **esting ( s**  **ection 63.10007) .**  **Comment 7 9**  : 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, onl y 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 8 1**  **:** Commenter 17805 states that the section 63.10007 (Tables 5 and 7) contains complian ce demonstration requirements, and specificall y, 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,95

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 generall y contains lower heat content. Therefore, the commenter asserts, running a performance test solel y 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 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

- ty pe and within coal

- ty

pe before finalizing these monitoring requirements. **Comment 8 2**  **:** Commenter 17800 states that many units in the U.S. utility system are load following or cycling units that change load on a dail y basis and that many o f 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 co st of that kind of extensive testing. **R esponse to Comments 79**  **- 8**  **2 :**  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 woul d be able to use the previous correlations for its operating parameters when the unit’s load changed. **19 . Miscellaneous**  **. Comment 8**  **3 :**  Several c ommenter s ( 19536 , 19537 , 19538 ) states that the monitoring of operating parameters as proposed under some scenarios does not assure continuous compliance with emissions limits that are only

measured annuall y 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 frequentl y than monthl y (or upon a change of fuel ty pe) under any

of the compliance scenarios. Moreover, the commenter notes that the HAP content of fuel is highl y variable even within fuel types. **Response to Comment 83 :**  We understand that there is variability in the HAP metals content in coal supplies and we believe that we were able to take that variability into account to a large degree with the extensive database of emissions values and the statistical procedures used in establishing the floor and the final emissions limitations. We believe that sources who demonstrate compliance with these limits must apply

the control measures including use of fuels that are consistent with the control measures applied by

the sources used in developing the limit s. The commenter provided no information on how the variability

of fuel HAP metals content can vary significantl y be yond that found in the database used in setting the floor or to the extent that a source demonstrating compliance under the various complian ce monitoring measures allowed in the final rule will have undetected excess emissions.96

**Comment 8 4**  **:** 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 emplo ying direct 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 currentl y proposed with 12

- hour block avera ging periods. **Response to Comment 8 4**  **:** 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 perio d based on the parameters being monitored. **Comment 8 5**  **:** 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 , SO 2 , total non

- Hg HAP metals, and individual non

Hg 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 rev ise these standards on a unit

- by

- unit basis. **Comment 8 6**  : 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 manifestl y does not permit the a genc y to circumv ent 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 s hort 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.97

**Response to Comments 8 5**  **and 86**  **:** The final rule no longer includes the use of PM as a site specific emissions surrogate for HAP metals. Instead, the final rule allows the source to choose and compl y with one of three numerical emissions limits

- total non Hg HAP metals, individual non Hg HAP metals or filterable PM. The rule no longer requires the source to develop any surrogacy

relationship to use one or another emissions limit. **Comment 8 7**  **:** 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 s ys tems, 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), anal yz e, and provide a record of process or control sy stem p arameters. ” 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 8 7**  **:** The final rule in this section refers to “ CMS ” , and is referring to continuous emission monitoring systems that are used f or 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 8 8**  **:** 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 8 8**  **:** Given the simplific ation of the operating limit and parameter monitoring provisions in the final rule, the EPA does not believe this comment remains applicable. **Comment 8 9**  **:** 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 comp liance test results show compliance with the emission limit). **Response to Comment 8 9**  **:** 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 ty p e of special allowance. **Comment 9**  **0 :**  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 9 0**  **:** This comment is moot given the changes to the operating limits required under the final rule. **Comment 9 1**  **:** Commenter 17881 states under Table 4

– Operating Limits for EGUs , with respect to PM CEMS , that for con centration based emission or operating limits, it is normally appropriate to correct the98

concentration back to a reference O 2/CO 2 level for purposes of consistency (i.e., the diluent gas levels will affect the concentration). **Response to Comment 9 1**  **:** There is no need to report the data from a PM CPMS in PM concentration values. **Comment 9 2**  **:** 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 9 2**  **:** 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 9 3**  **:** 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 C omment 93**  **:** These comments are moot given the changes in the final rule, as discussed above. **Comment 9 4**  **:** Co mmenter 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 9 4**  **:** These comments are moot given the changes in the final rule, as di scussed above. The one circumstance in which the rule relies on flexible parameter selection is for liquid oil

fired 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 9 5**  **:** Commenter 17925 states that parametric monit oring should be applied as an action indicator and not applied as a compliance monitor because they do not give a true indication of compliance especiall y 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 parametricall y of PM filterable emissions. However, the commenter states, other equipment on units such as FGD s ys tems (wet scrubbers) or DSI for ESP ash res istivity 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 the99

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 EPA does not explain how the 10 % number was obtained and how the range would be used for compliance. **Response to Comment 9 5**  **:** These comments are moot given the changes in the final rule, as discussed above. See also response to Comment 30 in this section. **Comment 9 6**  **:** Commenter 17923 recommends that the operational limitations of the air pollution control sy stems reference the manufacture recommendations. According to the commenter, the methodology

required b y the proposed rule would significantl y limit operational flexibility and significantl y increase the emissions testing require d at affected facilities. **Response to Comment 9 6**  **:** These comments are moot given the changes in the final rule, as discussed above. **Comment 9 7**  **:** 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 potentiall y 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 languag e 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 9 7**  **:** 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 c ommenter 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. Acco rding 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 associat ed 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 Easterl y, 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 timel y compliance, while also assuring that consumers are not adversely affected. ”100

In concert with the sentiment expressed by Commissioner Easterl y, the commenter recommends that states be provided the flexibility to approve liquid flow monitoring and other portions of the 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 s ection. **Response to Comment 9 8**  **:** 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 choo se acid gas emissions testing and must provide continuous parameter monitoring of their flue gas desulfurization sy stems. 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 9 9**  **:** Commenter 19033 states that 63.10010 (h)(2)(ii)(D) is overly prescriptive. According to the commenter, EGU operators may have experienc e that pressure drop sensors may provide reliable output at a less frequent cleaning frequency than daily

and alternativel y, systems equipped with an auto purge s ys tem would not require the dail y 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 c ommenter 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 s ys tem, 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 9**  **9 :**  These comments are moot given the chang es 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 strongl y recommends that approval of alternatives to work practice standards and alternative operating parameters be delegated to the state or local agencies for multiple reasons.101

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 b y individual operators; while it can articulate direction for 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 properl y appl y 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 approv al 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 10 1**  **:** Commenter 17752 requests that the EPA provide guidance on how to operate a baghouse to obtain the three different PM concentrations. **Response to Comment 10 1**  **:** The co mment is moot, as the rule no longer requires control device operational parameters to be monitored.102

**5A05a -**  **Testing/Monitoring: Operating parameter monitoring (bag leak detection systems) Commenters**  : 17704, 17716, 17725, 17737, 17775, 17868, 17871, 18 014, 18498 **Comment 1** : Several c ommenters (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 specifi c ty pe 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

- dy namic 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 onl y 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 usuall y be cleared in only

a few minutes by

removing a single compartment from service. **Comment 5** : Commenter 17737 strongl y objects to any requirement to use BLDS to demonstrate compliance. The c ommenter 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 c ommenter suggests the use of opacity measurement in place of PM CEMS or BLDS as compliance assurance monitors. The c ommenter 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 e lect 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 to103

the commenter, in other rulemakings, the EPA has asserted that while COMS “ cannot directl y 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 F R 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 th e 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 requirement s. 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 NSP S

– 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 appli cable to BLDS
.104

**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, 17 808, 17843, 17868, 17877, 17881, 17930, 18014, 18025, 18039, 18421, 18428, 18449, 18498, 18023 **1 . Requested**  **c larifications and**  **c orrections**  **. Comment 1:**  Commenter 18014 advises that proposed sections 63.10010(f) and 63.10021(h)(ii) have contradicting requirements for quarterl y accuracy determinations and dail y calibration drift tests. **Comment 2:** Several c ommenters (17728, 17758, 17775, 17868) state that all referen ces in the proposal to 40 CFR Part 60 , Procedure 5 ( e.g ., section 63.10021(a)(14)(ii)) should be deleted because the quarterl y 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 day s 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 m onitoring plan 21 days prior to initial certification testing or recertification testing, whereas proposed section 63.10000(d) requires submission of the monitoring plan 60 day s before the initial “performance evaluation. ” 3. According to the commenter, propo sed 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. Specificall y, 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 s ys tem 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 - of

control ” also is used to determine what data may be used to report emissions and what constitutes a dev iation 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 relevant105

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 analy sis by the EPA to establish an appropriate foundation for Hg mo nitoring 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 b y 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 demons trating compliance. The commenters state that Method 29 measures total Hg whereas Method 30B measures onl y 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 c ommenters (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 c ommenters 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

-pha se Hg measured b y 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 principall y 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 s ys tem 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 O ntario Hydro Method testing for Hg is not applicable for other types of affected units.106

**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 s ys tem sections (i.e., 40 CFR 63.10005(d)(4)

- (6)). The commenters note that there are so rbent trap monitoring s ys tem 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 b y clarifying the lan guage in the final rule. **2 . Technical**  **r eview of**  **a ppendix A and**  **i ncorporation of**  **p art 75**  **p rovisions**  **. Comment 7:**  Several c ommenters ( 17752, 17775, 18014 ) find similarities between Hg CEMS requirements in Appendix A and the now

- vacated CAMR provisions of Part 75 . The commenters generall y 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 requirem ents 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 specificall y allows for use of backup monitor s. 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 s ys tems. Several c ommenters (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 weekl y s ys tem integrity checks. Commenter 17775 beli eves 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.107

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 specificall y 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 be fore data are invalidated because that would provide an EGU time to schedule and perform a test if one were triggered unexpectedl y b y a unit startup or shutdown, and such a grace period would be consistent with provisions for linearity checks, 3

- level syst em 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 sy stem 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 s ys tem or data quality
. 1. The consultant recommends removing the second sentence of section 3.1.7 because the recommended nominal span ratio yi elds 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 NI ST 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 NI ST 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 CO 2 and O 2 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 provisio ns, 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 O 2 , CO 2 , 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 co mpanies to the misconception that all of108

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 likel y 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 con ducting 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/m 3 but > 0.1 μg/m 3 , the alternative breakthrough criteria could be < 50 percent of the section 1 Hg mass. For concentrations < 0.1μg/m 3 , 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 adv ance 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 b y 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 generall y finds section 7.1.10 to be confusing. 12. The cons ultant 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 c ommenters (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); C ommenters 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 p art 75 approaches. For the concerns raised with the system integrity check requirement, the final rule retains the weekl y s ys tem 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. Oper ating days are much easier to track than operating hours. The test can be done at any time during the 7 th 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 slightl y to provide for a workable standard that can adjust over time as industry

- standard detection limits may

change. For It em 3, the EPA agre es, 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 revisions109

general ly 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 . S ection 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 day s, readings exceeding the “ Span ” value resulted in invalid data, and the chart recorder or the 20 mA loop pegged, clamping th e data at the maximum span value. The commenter notes that much has changed with both instrumentation and data acquisition sy stems. 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 digitall y, 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 cau se it to read a subsequent stack concentration value of, say 1 μg/m3 any less accuratel y 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 NI ST can provide.) Commenter 18449 states that, despite the past practice, any requirement to run dual spans i s 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.110

3. Many s ys tems have separate ionic calibrators. If two ionic calibrators are required, the total could become four separate calibrators per s ys tem, which is impractical. The commenter believes the EPA should take this opportunity to finall y 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 dy namic 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 accuratel y, (within x percent) the data would be deemed vali d 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 “ty pe approval ” or one time on

- site demonstration would be sufficient. **Respon se 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 full

scale 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 capab le 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 p art 75 (see Appendix A section 7.2). The c ommenter notes that in the Cement MACT the EPA has not required th e submittal of hourly data for any

of the CAA section 112 listed pollutants. According to the commenter, the reporting requirements in these rules rel y solel y on the recordkeeping and reporting requirements contained in 40 CFR part 63, subpart A and 40 CFR p art 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 hourl y measured Hg concentrations is superfluous and the EPA has provided no reas on for this treatment. The commenter recommends the EPA revise Appendix A to subpart UUUUU and require onl y 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 b y a number of commenters
. See further discussion of this decision under responses to c omment s 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, CO 2 or O 2 , and moisture monitors is invalid (see 86 FR 25033). The commenter notes that its p art 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 p art 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 s ys tem 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 (dail y calibrations, quarterl y linearity checks, and annual RATAs ) would be appropriate and simplify

ongoing QA tests to a consistent set of requirements. Further, according to the commenter,111

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 t o 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 quarterl y sorbent trap test (in non - RATA quarters) along with the quarterl y 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 convert er and if daily calibrations are not done with a NI ST
traceable source of oxidized Hg. The s ys tem integrity test assesses the efficiency with which the converter reduces oxidized Hg to elemental Hg; conversion efficiency must be confirmed as poor efficienc y 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 7 th 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 s**  **pecifications .**  **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 equivalentl y 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 th at period of stabilization, significant drift (false trending of data) can occur making accurate reporting of data nearly impossible. The commenter states that currentl y, Appendix A of the proposed rule contains onl y the requirement that entities report wh en 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 s ys tems 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 reliabi lity 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
.112

**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 s ys tem 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 accuratel y measureable c oncentrations. 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 C EMS
. The commenter contends that the proposed limit is fundamentall y immeasurable and states that the EPA should set a Hg emission level that is measurable and supported b y sound scientific data pertaining to CEMS technology
. **Comment 15:** Several c ommenters (17638, 17681, 17930) state that Hg CEMS are not sufficientl y 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 s ys tems provide accurate and audited continuous monitoring for Hg emissions. Even though these CEMS are currentl y 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 L OW HG LEVEL S ” . The commenter s tates that while it is likely that the quantification limits of Hg CEMS will improve as more s ys tems 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 sy stems 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 th at 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 1 4**  **- 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 s ys tem to monitor for continuous compliance. There are data in the draft report cited b y one of the commenters , “ DETERMINING THE VARIABILITY OF CMMS AT LOW HG LEVEL S, ” 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
.113

**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 sy stems 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 correctl y, 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 m et. 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 1 9:**  Commenter 17761 states that based on their more than 4 years of experience with Hg CEMS at the Scott Energy Center Unit 4 Hg CEMS can overstate actual emissions, demonstrates significant variability , does not necessarily correlate with stack testing mea surements (20

- 25 % higher than through stack testing) , and will have difficulty meeting the aforementioned 95 % availability requirements. **Response to Comment 19:** See response to C omments 12 and 13 above
. **Comment 20:** Commenter 17805 states that based on their experience with Hg CEM S 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 NI ST traceable calibration gases are available. The commenter also believes the certific ation requirement for the monitoring s ys tem NI ST certified calibrator b y an offsite third party vendor will create challenges for s ys tems 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 SO 2 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 NI ST traceability

of elemental and oxidized Hg gas generators based on its work with NI ST and numerous other stakeholders. To the extent that the commenter or others believe an alternative calibration approach can provide eq uivalent results, then the commenter may appl y 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 c ommenter 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 may114

argue that their monitoring s ys tems are full y functional, the commenter ’ s experience is that for these ty pes of applications the vendor infrastructure, industry capabi lities, 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
- OAR
2009
- 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 s ys tem computers already in place. However, we would prefer to use the 40 CFR Part 60 deviation

- b ased 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 s ys tem. 4. Commenter supports disabling the bias adjustment for all air toxic s data because bias adjustment is only appropriate for emissions trading programs. 5. Commenter agrees that hours when a monitoring sy stem is out of service should simply be counted as hours of monitor down time, to be counted against the percent monitor avai lability
. 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 wi ll 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 NI ST 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 sorb ent 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 electroni c reporting of data. See further discussion under section 5B04 of this document
. 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 successfull y 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, th e EPA creates a false dichotomy stating that it considered two options:115

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, O 2 or CO 2 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 a genc y. ” 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 s econd 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 every thing the EPA described under Option 1. The commenter asserts that sources would like ly 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 generall y, 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 L ewis & Clark Station to the Montana Department of Environmental Quality for about 2 years. However, the s ystem 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 2 3**  **:** Commenter 17626 states th at Hg limits need to be set to be consistent with the technology

not onl y 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 su pports 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 s ys tem technology to monitor for continuous compliance. See section 5A06 for further discussion of Hg CE Ms and sorbent trap monitoring. **Comment 2 4**  **:** Commenter 17637 states that it is not precisel y determined whether test methods exist that are accurate, reliable and consistent enough to ensure compliance with the stated emission limits. Hg stack testing and o ther 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

- and

day

- out environment is still unproven. **Response to Comment 2 4**  **:** 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 12 B which116

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 C EMS and sorbent trap monitoring. **4 . QA**  **r equirements for**  **e lemental and HgCl**  **2 g**  **enerators .**  **Comment 2 5**  **:** 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 NI ST traceability protocol ’ s 8
- quarter recertification interval for HgCl 2 “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 des igned to accept calibration gas from a generic “ Field Reference Generator, ” or cylinder gas standard (NI ST 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 NI ST reference methods. According to the commenter, this requires specialized equipment and knowledge generally available onl y from the manufacturer and consequently, the “ send

- to - manufacturer

- for

- recertification ” prere quisite is the onl y 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, co nfiguring 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 fo r these certification activities. A significant concern for the commenter is the potential for generator and Hg anal yz er contamination, and equipment damage during disassembly , shipping, and reassembl y . According to the commenter, the elemental and HgCl 2 g enerators 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 NI ST traceability protocol ’ s user generator re certification interval provisions are overl y restrictive. Consequently, the commenter advocates that the proposed NI ST traceability specifications referenced in Appendix A only become effective when they become final and that the “
... or an interim version o

f that protocol” phrase in Appendix A, sections 3.1.4 and 3.1.5 definitions be deleted. **Comment 2 6**  **:** Commenter 17197 also recommends that the interim NI ST 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 NI ST traceability protocols contain a RATA perfor mance 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 NI ST certification as long as the Hg CEMS is able to achieve the alternate RATA incentive performance117

specification and other periodic QA/QC requirements (i.e., dail y calibration, weekl y 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 2**  **5 and**  **26 :**  The EPA disagrees. The interim NI ST 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 gen erator 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 effectivel y accomplished. **5 . Monitoring**  **c hallenges for**  **n ew**  **u nit Hg**  **l imits**  **. Comment 2**  **7 :**  Commenter 17622 believes that Hg CEMS are sup erior 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 emissi ons 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 b e 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 NI ST standard at 0.5 μg/m3 only recently being available. Commenter 17622 goes on to state that the EPA NI ST protocol for traceability of Hg generators has not been implemented at Hg concentrations <0.5 μg/m3 . According to the commenter, more testing, and possibl y development and evaluation o f commerciall y- available Hg generators, is needed to ensure that NI ST 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 confidentl y or reliabl y employed for monitoring, control and reporting of prospective new EGUs emissions under the proposed Utility MACT . According to the commenter, there are clearl y both challenges and concerns about the traceability of commercially

- available Hg CEMS required to effectivel y administer the proposed existing unit emission limits. The commenter recommends that the EPA develop a strategic initiative with NI ST , targeting lower

- level Hg ( i.e., <0.5 μg/m3 ) calibration and standards traceability and support for Hg CEMS and sorbent trap methods. **Comment 2 8**  **:** Commenter 17758 states that the proposed new source Hg limit cannot be measured by any current or plann ed instrument, and even if a new unit could meet the limit, there is no way to assess compliance. **Response to Comments 2 7**  **and 28**  **:** The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. The EPA believes the record clearl y shows these to be proven technologies, each providing certain advantages. For existing and some of the new unit limit standards,118

the level of the NI ST traceable Hg standard is adequate and consi stent 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 “ DETERMININ G THE VARIABILITY OF CMMS AT L OW 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 2 9**  **:** 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 2 9**  **:** The EPA acknowledges this support. See further discussion of sorbent trap monitoring option, below. **Comment 30**  **:** Several c ommenters (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 NI ST
- traceable calibration gases and the lack of any NI ST
traceable calibration gases corresponding to the propose d 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 IC R ; see https://utility

macticr.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 NI ST
- traceable calibration gases at the appropriate concentrati on 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 s ys tem meeting the specifications in PS 12B
. **Response to Comment**  **30 :**  See response to Comments 2 7 and 2 8 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 deve loped standards for which there are not accurate and reliable monitoring methodologies for demonstrating compliance. **Response to Comment 31**  **:** The final rule allows for sources to use Hg CEMS or sorbent monitoring traps at the choice of the source operator. Sorbent trap monitoring has been shown to be highl y reliable and accurate for long term monitoring of HG emissions. Those options should provide sources with the flexibility to select and operate the monitoring s ys tem that provides effective data collecti on sufficient to demonstrate compliance. We understand the concern about the technical hurdles with applying new technologies but we disagree that the Hg CEMS technology is not ready for this application. S ee also the response to Comments 14
- 17, above and 32
- 34, below
.119

**6 . Sorbent**  **t raps**  **. Comment 3**  **2 :**  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 offer a more consistent and accurate means for monitoring compliance. The commenter states that consequentl y, 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 believe s 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 ye ar, and the commenter provides a lengthy list of problems encountered with Hg CEMS deplo ym ents and highlights how sorbent traps do not encounter these problems. **Comment 3 3**  **:** Commenter 18023 states that a sorbent trap - based Hg monitoring s ys tem 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 s ys tems 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 c ompliance becomes problematic. According to the commenter, s orbent trap based Hg monitoring systems have the potential for losing at least seven day s ’ and as much as fourteen day s ’ 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 3 4**  **:** 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 3 5**  **:** Commenter 18421 strongl y 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 emissio ns 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 s ystem 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 currentl y 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 Emiss ions 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 o r consent decrees. **Comment 3 6**  **:** Commenter supports the inclusion of sorbent trap monitoring s ys tems 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 in120

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 anal yz er and Hg lamp failures, design issues that result in a time consuming process to diagnose problems, the need for continual recertification of th e 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 sy stem including reliable design with no sample transport issues (the sample is collected at the end of the probe in the traps), the system is simple, problems are diagnosed easily an d quickl y, the s ys tem is appropriate for wet stacks and the s ys tem provides accurate Hg data. **Response to Comments 3 2**  **- 3**  **6 :**  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, PS 12B addresses this situation. As a result, achieving the monitoring method ’ s measurement perfor

mance requirements ensures data of known and acceptable quality
. The EPA disagrees that a s ys tematic 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 significantl y better than that required b y 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 app roved regulatory requirement that has gone through notice and comment rulemaking as an appropriate set of requirements for a sorbent trap monitoring s ys tem. The EPA is not revising PS 12B as part of this rulemaking. The requirement to utilize the same ty pe of sorbent material in the sorbent trap monitoring s ys tem as will be used in the future for dail y operations simply provides for an additional check on the overall s ys tem and procedures. If Method 30B is employed as the reference test method to conduct th e 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 method

specific performance criteria are met. Moreover, recent testing conducted as part of the Utility MACT ICR demonstrated that Hg concentrations well below 0.1 μg/m 3 (100 ng/m 3 ) were reliabl y measured. In addition, RATA requirements for Hg concentrations less than 0.5 μg/m 3 are a component of Appendix A in the final rule and are known to be consistent with the measurement performance capabilities of Method 30B . For NI ST capability issues, see earlier response to Comments 2 7 , 2 8, and 30
. **Comment 3 7**  **:** Commenter 17757 suggests that quarterl y performance tests and anal ys es of sorbent trap monitoring data would be adequate to determine compliance with an annual emission limit. **Response to Comment 3 7**  **:** The EPA disagrees. Monitoring technology adequate to show continu ous 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.121

**Comment 3 8**  **:** Commenter 17775 supports use of sorbent trap monitoring systems and relian ce on PS 12B , subject to the following comments. According to the commenter: 1. First, the EPA should explicitly provide an option for use of backup monitoring s ys tems to allow sources to plan for the possibility of significant monitoring s ys tem 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 p ercent breakthrough for effluent concentrations above 1 μg/m3 and 20 percent for concentrations below 1 μg/m3, and a s 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 IC R , 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 app roach 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 IC R 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 Meth od 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 bagh ouses and scrubbers may achieve Hg emissions levels below 0.5 μg/m3 . According to the commenter, in order for sorbent trap monitoring s ystems 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 3 8**  **:** See the responses to Comment 7, above. **Comment 3 9**  **:** 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 b e exposed continuously for (ty picall y) 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 anal ytical instrumentation.122

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 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 s ys tematic 11 percent difference in sensitivity between the Tekran CEM which used a NI ST traceable elemental gas generator for calibration, and the sorbent traps, which used a NI ST 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 typ e 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 ty pes yi eld different results, this is an indication of a severe problem somewhere. According to the commenter, it may be desirable, fro m 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. NI ST 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 NI ST 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 NI ST calibrator only and that vendor and user calibrators would have still higher uncertainties. Absent major developments, the commenter does not believe the NI ST traceable gases be available to validate low ng/m3 measurements. **Response to Comment 3 9**  **:** See response to C omments 3 2
- 3 6 above
. **7 . Provisions for Hg**  **CEMS on**  **b ypass**  **s tacks**  **. Comment**  **40 :**  Commenter 18023 states that the final rule should clarify the provisions for units with a main stack and a b yp ass stack regarding use of the maximum potential concentration (MPC ) for each hour in which the b ypass 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 by pass stack measures a number higher than the MPC . The commenter also asserts that the EPA should specify that when multiple units are controlled b y the same device and less than all of those units are b eing by passed only

the MPC for the units being b ypassed, should be reported. According to the commenter, MPC should not be used for any of this since the MPC approach is onl y used for emission trading programs; a lower confidence interval ty

pe of value sho uld be used instead for conditions where a b ypass 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 by pass 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 s ys tem on a b ypass stack.123

According to the commenter, installation of CEMS on a by pass stack can be problematic from a number of perspectives. According to the commenter, in addition to the costs of the additional monitoring system, by

pass stacks will not be used with sufficient frequency to perform those periodic QA tests that require unit operation ( e.g ., RATAs and linearity checks). The commenter asserts that correlation of a PM CEMS on a by

pass stack would be nearl y impossible to accomplish without significant operation with by pass (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 b ypass stacks is more suited to an emissions trading program. Rather than require the use of the MPC to estimate emissions from the b ypass stack, the final rule now requires use of one of two options: (1) direct monitoring of both the main stack and the by pass stack for Hg or (2) counting of by pass 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 by pass 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 CE MS 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**  **b ias**  **a djustments**  **. Comment 4**  **2 :**  Commenter 18023 states that the final rule should no t 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 ad justment 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 4 3**  **:** Commenter 17805 agrees with the EPA that application of a bias adj ustment for Hg emissions is not necessary . It is the commenter ’ s understanding that a bias adjustment, as used for SO 2 emissions in the Acid Rain Program, was primarily intended to assist with ensuring emissions were adjusted properl y 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 4 2 and 43**  **:** No bias adjustment or bias test is required under the final rule. **9 . General**  **c oncerns**  **. Comment 4**  **4 :**  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 accuratel y at the proposed MACT limit for existing coal

- fired EGUs but that CMM would neither be able to measure Hg124

accuratel y 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 liq uid oil

- fired EGUs
. **Response to Comment 4 4**  **:** The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. The EPA believes the record clearl y shows these to be proven technologies, each providing certain advantages. For existing and some of the new unit limit standards, the level of the NI ST traceable Hg standard is adequate and consi stent 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 “ DETE RMINING THE VARIABILITY OF CMMS AT L OW 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 4 5**  **:** Commenter 17747 states that the cycle time test unfairl y excludes m onitoring 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 accuratel y 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 nearl y continuousl y, excluding onl y the time required for the tape to advance from the sampling area to the anal ys is area (~ 20 sec). The sample is typically gathered for 15 minutes and then anal yz ed 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 accuratel y and precisel y and whether emissions are nearl y constantl y 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 quickl y 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 currentl y 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 do es 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 cop y 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 for125

up to 14 days before ending the traps to a lab for Hg anal ys is. According to the commenter, this would potentially

allow 4

- 6 weeks to elapse before Hg data would be generated and reported, and it clearl y does not make any sense to allow up to 6 weeks or more for data to be reported under one method of 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 cyc le times. **Response to Comment 4 5**  **:** 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 4 6**  **:** Commenter 18428 states that an alternative to using CEMS for compliance, the EPA should allow fuel sampling and anal ys is for Hg determining Hg emissions from coal

- fired units, particularl y 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 4 6**  **:** 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 s ys tem, or LEE testing for existing units with very low emissions. **Comment 4 7**  **:** 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 indu stry 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 rel y on unproven HCl CEMS, that HCl CEMS are not commerciall y 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 4 7**  **:** 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.126

**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**  **i ssues**  **. 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 anal ys is 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 a fter 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 sens e, 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 a s 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:** Comment er 18449 states that under “ Calculation of Mercury Mass Emissions ” on page 251 45 the rule requires that reported concentration averages for both CEMS and sorbent methods be rounded, to the nearest tenth but that i t 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 sub

microgram 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 b y RATA testing. According to the commenter, h ourl y 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 m ore 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**  **e mission**  **r ate**  **.**127

**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 thos e 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 anal ys is in order to determine site

- specific fuel factors. The commenter states that th e 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 a pplicable 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 pre ceding diluent capping provisions, these sections would appear to alway s 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. Sec tion 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 directl y 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**  **p eriod**  **. Comment 5:**  Several c ommenters (17770, 17820, 17886) note that p art 75 has a grace period for s ystem 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 properl y. According to the commenter, i f the unit is not fully base

- loaded, this will be difficult ; m o st 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 conc erns raised with the sy stem integrity check requirement, the final rule retains the weekl y s ystem integrity check requirement, without a grace period. However, to add flexibility, the required frequency of the test has been changed from once every 168 oper ating hours to128

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 7 th 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**  **r eporting**  **u nder**  **S ection 7 of**  **A ppendix A**  **. Comment 6:**  Commenter 17881 requests clarification of the recordkeeping and reporting provisions contained in a

ppendix 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 s ys tems, or all m onitoring s ys tems 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 s ys tems 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 leas t 3 years from the date of each record. According to the commenter, h aving two different retention schedules for the same data elements (i.e., flow rate data, diluent data, etc.) will simply lead to confusion and potential non

compliance, especiall y in cas es where a facility currentl y 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 s ys tems 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 c ommenter 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, whi ch 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 clearl y 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 c ommenter notes that under section 7.1.1.2.1 the identification of controls should be specific to those ty pes 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 h ow the collection of information on NO X controls, for example, would be relevant under the proposed EGU MACT
. 6. According to the commenter, f ormulas used to calculate emissions and heat input under section 7.1.1.2.1 only

need formula s 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, r ather than leaving it to the discretion of the regulated entity to determine whether certain data elements are needed, the EPA should clearl y specify which data elements are necessary for each of the Hg emission limit forms (i.e., lb/TBtu and lb/GWhr).129

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, a ppendix 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 s ys tems are used, the recordkeeping provisions of p art 75 generall y appl y to those s ys tems. 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 s ys tems in accordance with the requirements of section 63.10020(b) and the general monitoring operation provision s that apply across p art 63. **5 . Recommendations**  **- A** **ppendix A .**  **Comment 7:** Commenter 17725 recommends that the EPA add a subsection to Appendix A section 7.1.5.2.3 that clearl y 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, f or 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 dail y calibration standard (20

–30 percent of span value). 2. The c ommenter recommends quarterl y, instead of weekl y, oxidized Hg (Hg+2) converter checks. According to the commenter, NI ST
- traceable Hg+2 in the Tekran Hg monitoring s ys tems is currentl y limited to ~2.5 ug/m3 , but Hg+2 will be < 0.5 ug/m3 after controls to achieve compliance with the prop osed 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 C AMR 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, c alibrating a s ys tem at more than 5 times the measurable concentration would produce accuracy problems and filter contamination if conducted weekl y 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 calib ration gases. The span value is set starting with the Hg concentration (μg/m 3 ) corresponding to twice the level of the standard. This value is then rounded upward, either to the next130

highest integer, the next highest multiple of 5 μg/m 3 , or to the next highest multiple of 10 μg/m 3 . For instance, if the level of the standard corresponds to a concentration of 1.2 μg/m 3 , as suggested b y the commenter, the span value could either be set at either 3 μg/m 3 , 5 μg/m 3 , or 10 μg/m 3 . I f it is set at 3 μg/m 3 , a mid

- lev el calibration gas with a concentration of 50 to 60% of the span value (i.e., 1.5 to 1.8 μg/m 3

-- which is in close proximity to the level of the standard) could be used for dail y calibrations. We believe this addresses the commenter ’ s concerns. Regarding the s ys tem integrity check, the EPA does not agree with the commenter that a quarterl y test frequency is sufficient. To obtain accurate data with a Hg CEMS that has a converter, you must ensure that the converter is working properl y. The s ys tem integrity check provides that assurance. Therefore, it is not appropriate to allow long time intervals between converter checks. If a quarterl y test frequency were implemented, there could be more than five months between successive sy stem integrity checks, e.g., if the test is done in earl y J anuary (1 st quarter) and the next one is not done until late June (2 nd 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 CE MS 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 yearl y 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 practice s. **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 p art 60 or 75 without any

additional requirements. **Response to Comment 9**  **:** The commenter is referring to the additional monitoring s ys tems 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 moi sture) are needed to convert Hg concentrations to the units of the emission standards. The final rule mandates that all of these monitoring sy stems 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 s ys tems 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 certif ication testing is required under Subpart UUUUU for previously

- certified Part 75 sy stems 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 generall y supports the EPA ’ s attempt to provide consistency between this proposal and Part 75 but notes that not all of the p art 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 quarterl y accuracy determinations and cal ibration drift tests in accordance with Part 60 , Appendix F, Procedure 5. According to the commenters, the quarterl y and daily requirements in Procedure 5 are duplicative of and conflict with some of the proposed requirements in Appendix A , and u se of131

Proc edure 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 s ystems and the provisions for use of conditional data validation. According to the commenter, these options have been used under Part 75 for ye ars 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 guidanc e 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, replac ements, adjustments, linearization , reprogramming, relocation, etc.) to conditionally validate data prior to completion of all required tests b y performing a successful “probationary calibration error test. ” According to the commenter, this provision has b een crucial to maintaining good data availability under Part 75 , by avoiding invalidating data after a monitoring s ys tem has been confirmed to be operating properl y 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 p art 75 options discussed in items 2 through 4 of this comment. **Comment 1 1**  **:** Commenters 19121 and 19122 support the monitoring requirements for Hg outside of p art 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 bel ieve 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 anal ysis 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 clearl y 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 NI ST 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. C ommenter 19121 recommends that owners/operators have 30 operating day s to perform a diagnostic linearity check after change of span value. 4. Commenters recommend that if CO 2 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. ”132

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 1 1**  **:** Regarding changes 1) through 5) suggested b y 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 well

established procedure that provides a robust statistical basis for determining the accuracy of a CEMS, and is familiar to, and widely accepted by , the regulated communi ty 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 complia nce options: (a) install and certify

a continuous moisture monitoring s ys tem; (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 anal yz er has been retained, but a clearly defined windo w 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 inco rporated 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 exclusivel y 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 se ctions of Part 75, but only for the additional monitoring s ys tems that are needed to convert Hg concentration to units of the standard (i.e., diluent gas, flow rate, and moisture s ys tems). Similar cross

- referencing of Part 75 is not possible for Hg emissio n rate calculations because, as explained in the previous paragraph, Part 75 no longer includes Hg monitoring provisions.133

**Comment 1 2**  **:** Commenter 17800 states that the EPA needs to remove the requirement for a NI ST traceable oxidized Hg standard from the certification tests (s ee 86 FR 25034 ) . The commenter is not aware of any oxidize d standard for Hg , let alone a “NI ST
- traceable oxidized Hg standard”
. **Response to Comment 1 2**  **:** The definition of a “NI ST
- 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 HgCl 2 solutions or chlorine gas cylinders), and for individual components of the gas generator which m easure 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 b y EPA and industry as an interim methodology . Further research is needed to develop direct NI ST traceability for oxidized Hg calibration gas standards. **Comment 1**  **3** : Commenter 17821 states that section 3.2.1.4.3 proposes to require that the full “ range ” of the Hg anal yz er be capable of measuring the MPC values that are defined in sec tion 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 ful l scale value can be defined to match with the 4

- 20 mA output signal used for data recording , b ut that this setting is not a span range setting in the anal yz er. According to the commenter, m odern Hg anal yz ers have a measurement range that is limited only b y the lower and upper detection limits of the measurement sensors within the anal yz er. Commenter understands the need to determine the accuracy of an Hg anal yz er 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 anal yz er , 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 1**  **4 :**  Co mmenter 17821 recommends that the EPA define the “range ” of the Hg CEMS as a range from zero to the appropriate MPC ( s ee section 3.1.13 )
. According to the commenter, a source would then perform linearity checks “ across the range as determined b y these rules ” instead of across the anal yz er ’ s entire measurement capability
. The commenter states that m odern Hg anal yz ers have a large measurement range , and the commenter does not believe that EPA intended for sources to test the anal yz er across its entire ran ge of measurement but rather across the “ span ” or full “range ” defined for use with compliance of these proposed rules. **Response to Comments 1 3**  **- 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 lim its in s ubpart 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 b y two, and then rounding off the result appropriately . Flexibility is provided; the span value (in units of μg/m 3 ) may be rounded to either the next highest integer, the next134

highest multiple of 5 μg/m 3 , or the next highest multiple of 10 μg/m 3 . I f better accuracy at the lower end of the scale is desir ed, rounding off the span value to the next highest integer or multiple of 5 μg/m 3 may be preferable to rounding to the next highest multiple of 10 μg/m 3 , 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 1 5**  **:** 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 alternativel y rounding the span value to the next highest interval of 10. According to the commenter, b ased 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 any where between 2 and 10 μg/m3 as long as that range falls within acceptable limitations of the NI ST 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 p art 75 has an annual requirement for the majority of anal yz er readings to be between 20 and 80 percent of full

- scale , which sh ould not apply to Hg. **Response to Comment 1 5**  **:** In the final rule, greater flexibility in setting the span value is provided; the span value (μg/m 3 ) is twice the Hg concentration corresponding to the emissions standard, rounded to either the next highest integer, the next highest multiple of 5 μg/m 3 , or the next highest multiple of 10 μg/m 3 . For certain existing units, the estimated Hg concentration corresponding to the standard is about 1.5 μg/m 3 . Therefore, the span value could be set to either 2.0, 5.0, o r 10.0 μg/m 3 . I f the span value is set at 5.0 μg/m 3 , the required QA tests (i.e., dail y calibrations, linearity checks and system integrity checks) will be performed in the 0

- 5 μg/m 3 portion of the measurement scale (as suggested b y the commenter). Then, p rovided 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 anal yz er ’ s full

- scale range. **Comment 1 6**  **:** Commenter 17821 opposes the requirement under section 3.2.3.3. to set the span for a CO 2 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 CO 2 concentration of approximately

14 percent in the flue gas , and 1.25 times 14 is only 17.5 %
. The commenter states that o ther regulations, such as 40 CFR 60 and 40 CFR 75, require the span of a CO 2 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 CO 2 monitor for compliance with these proposed rules, or conduct a separate span calibration check on an existing CO 2 monitor in order to compl y with all appl icable requirements. Commenter encourages the EPA to define a span of 20 percent for CO 2 monitors used for compliance with these proposed rules. **Response to Comment 1 6**  **:** The final rule does not include the requirement to set the CO 2 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 p art 75. Part 75 span values for CO 2 or O 2 monitors are therefore acceptable for Subpart UUUUU and there i s no conflict between the135

regulations. Essentially

all coal

- fired utility

units already

have certified p art 75 CO 2 or O 2 monitors in place to meet Acid Rain Program requirements. **Comment 1 7**  **:** Commenters 17821 and 17881 object to the requirement at section 7.2.5.1 to submit quarterl y 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 an d 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 stat es that the EPA does not justify the requirement to electronically

submit data under section 7.2.4. **Response to Comment 1 7**  **:** The EPA disagrees. These provisions provide extremely useful compliance oversight information regardless of whether compliance is m arket

- 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 hourl y 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 1 8**  **:** Comment er 18449 states that the Appendix A Performance Specification appears to replace PS
- 12A in this MACT but not in the other recentl y 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 1 8**  **:** 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 rel y 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 re ferenced as it is essentially identical to the former Appendix K of Part 75, which was to be implemented through ECMPS under CAMR. **Comment 1 9**  **:** Commenter 18449 states that the requirement to report readings of either CO 2 of O 2 , on any constant basis is unn ecessary . 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 CO 2 or O 2 concentration does not in any way facilitate this calculation but adds unnecessary

variables that will increase the uncertainty and calculation error
. The commenter states136

that c orrected (CO 2 or O 2 ) pollutant concentrations are not used in any of the subsequent mass emissions calculations being proposed by the EPA for concentration based Hg anal yz ers. The co mmenter states that s tack velocities determined using pitot tubes or other measurement devices are not measured on a constant O 2 basis. Thus, according to the commenter, the stack volumes would need to be recalculated on a 7 percent O 2 basis in order to al low calculation of the mass emission rate. The commenter states that the sorbent trap reference method does not report concentrations on a 7 percent O 2 basis and that thus both the reference and CEMS values would have to be corrected to 7 percent O 2 . According to the commenter, i f the Hg CEMS intrinsically produces a concentration corrected to 7 percent CO 2 , these results must be back corrected to yi eld an as

- is value to allow comparison. This is a needless step that complicates matters and introduces errors. The commenter states that m ost existing CEMS do not have an O 2 monitor. According to the commenter, i t is unnecessary and punitive to require the addition of an O 2 monitor to a Hg CEM , which will reduce reliability and accuracy of the overall sy stem. According to the commenter, all commercially available dilution

- based Hg CEMS anal yz ers 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 CO 2 or O 2 as a dilution ratio check is not required. **Response to Comment 1 9**  **:** 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 O 2 monitor is required in incorre ct; the final rule allows the diluent monitor to measure either O 2 or CO 2 . 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 need ed in that case. **Comment 20**  **:** Commenter 18449 states that under the RATA testing section 4.1.1.5 the procedure should require onl y 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 anal yz ers will not report on this basis , and thus any requirement to correct to some reference CO 2 (or O 2 ) 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 accuratel y it measures Hg concentrations. Therefore the RATAs must be done on a concentration basis, comparing the μg/m 3 readings from the reference method to the μg/m 3 readings from the monitor. This is clearly stated in sections 4.1.1.5.2 and 4.1.2.4 of Appendix A. **Comment 2**  **1:** Commenter 19114 states that the EPA appears to have overlooked many of the issues that were reso lved in the earlier CAMR rulemaking process. The commenter attach ed 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 comme nter, 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 negative137

data. According to the commenter, i f instrument drift and allowable calibration error tolerances are included, it is possible to be within the anal ys is tolerance and read a legitimate negative value.
 Commenter recommends the use of part 72 definitions for CO 2 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 mois ture. According to the commenter, i f the stack is saturated, a source should be able to use temperature, absolute pressure, and a ps ychrometric 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, d uring periods when the stack is not saturated, default factors listed in the rule could be used. **Response to Comment 2**  **1:** Regarding the three i ssues raised b y 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 wi ll instruct sources to use MODC 21 and report zero Hg concentration when a negative value is read b y a CEMS that is not out

- of

- control. 2. There are no definitions for “ CO 2 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 f inal rule allows the “ additional option ” for measuring moisture described b y 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 4 0 CFR 75.11. The affected source may either: (a) install and certify a continuous moisture monitoring sy stem; (b) use an applicable fuel

specific 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 ps ychrometric 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 (CO 2 or O 2 ) 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 meas ured on the same basis, asserts the commenter, a stack moisture monitoring s ys tem 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 2 3**  **:** Commenter 17881 states that the requirements of section 63.10010 for main and b ypass stacks conflict directly

with those in Appendix A (section 2.4.2 of Appendix A allows installation of a138

CEMS on the main stack and the use of maximum potential Hg concentration whenever the b ypass 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 independentl y show compliance with the applicable EGU emission limits, and this could result in situations of seeming non

compliance. The commenter questions whether, f or 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 2 3**  **:** 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 b y 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 s ys tems (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 surfac e similar to those found in 40 CFR p art 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 p art 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 p art 75 provisions. **Response to Comment 2 4**  : 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 p art 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 s ubpart UUUUU. **Comment 2 5**  **:** Commenter 17881 states that the cycle time test provisions of p art 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 2 5**  **:** 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 2 6**  **:** 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 NI ST, and suggests the number of spans be minimized.139

Commenter 18449 states that utility MACT spans should be fixed at 5, 10, 20, and 40 ug/m3. (Commenter 184 49 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 fo rced to nearest multiple of 10.) Commenter 18449 states that CAMR also required Hg calibration gases be traceable to NIST, however, NI ST at that time had no idea how to certify Hg generators or calibration gases and had to develop the methodology , procedur e, and processes, with no protocols in place until well after the start of the program, so that the EPA was forced to defer the NI ST traceability requirement for a ye ar. 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 NI ST can onl y 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 NI ST 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 ne eded 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

ch loride 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 NI ST c ould accuratel y 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 NI ST traceable. The commenter states th at this approach can remain, but the ability of NI ST 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 certif ications. The commenter states that certifications of elemental calibrators b y N IS T over the range 0.5 to 38 μg/m3 have been “routine ” for several ye ars, but it recently took three separate attempts with NI ST and over one year for the commenter to have a p air 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. Th e EPA Interim Traceability Protocols currently

state: “ For CEMS applications, this protocol applies only to Hg monitoring s ystem span values greater than or equal to 5.0 micrograms per cubic meter (μg/m3) ” According to the commenter, this must be changed i f 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 r eason 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 by140

the NI ST Gas Metrology

Group, and the other, recently proposed by

another group within NI ST (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 valu e. 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 NI ST will have to be able to certify elemental Hg concentrations less than 0.5 μg/m 3 at this time. No span values (i.e., a span value less than 5 μg/m 3 ) that would require certified elemental Hg concentrations less than 0.5 μg/m 3 are required b y 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/m 3 , NI ST 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 NI ST to expand the range of NIST elemental Hg reference con centrations that can be certified and certified elemental Hg concentrations ranging from 0.5 μg/m 3 to 300 μg/m 3 are now available. Concerning Item 3, the EPA agrees that NI ST 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 certifyingoxidized 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 currentl y 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/m 3 are not required b y 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 NI ST 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.141

**5A07a -**  **Testing/Monito ring: 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, 18 023 **1 . Support of**  **u se of PM CEMS**  **d uring**  **s tartup and**  **s hutdown**  **. Comment 1:**  Commenter 17975 supports the proposed requirement to use PM CEMS on EGUs that elect to compl y 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 s hutdown. **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 numerical 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**  **i ndicator/CAM**  **. Comment 2:**  Multiple c ommenters (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 alternativel y, 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 c ommenters (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 c ommenters (17402, 17716, 17737, 17775, 17886) believe current PM CEMS technology

is useful as a c ompliance assurance monitoring tool that can trigger requirements for investigation and corrective action. **Comment 5:** Several c ommenters (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 site

specific utility MACT compliance plan, and periodic stack testing. **Response to Comment s 2**  **- 5:**  The final rule re quires 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 for142

an alternative to use opacity or parametric monitoring at a specific site in lieu of required monitoring 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). **3 . Requests for**  **c larification on**  **e stablishment of P**  **M CEMS o**  **perating l** **imits .**  **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 Com ment 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 measurem ents. 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 “ non Hg 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 n ot 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 c ommenters (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 poorl y 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 source s 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 “ simpl y nonsensical. ” The commenter believes it is unreasonable for the EPA to seek comment on s uch 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

-propos e the rule for public comment because the commenter cannot effectivel y provide comment without further definition.143

**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 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 c ommenters (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 M ethod 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 analys es 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 expressl y provide that the op erating 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 c onsistent 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 compl y 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 fo r 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 c ompliance 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 EGUs
. 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 SO 2 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 SO 2 would be measured with a CEMS certified and operated in accordance with p art 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 of144

compliance that a facility would be required to meet on a continuous basis. According to the commenters, this is inconsistent with the purpose of an emission standard , which allows for fluctuations in emissions over a 30

- day period and improperl y i mposes two MACT standards on sources. **Response to Comment 10:** The comments are inapplicable , as the final rule no longe r contains a condensable PM emissions limit and, for those source owners or operators who choose to use SO 2 CEMS, no operating limit exists and no parameter monitoring is required. **Comment 1**  **1 :**  Commenter 17623 states that the total PM standard is unclear an d 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 emissi on 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, o ne 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 i f, 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 P M 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 1 1**  **:** Under the final rule, you may elect to compl y 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 p erformance 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 1 2**  **:** Commenter 17795 states that there is conflicting language in the proposal. According to the commenter, p ages 25029
- 25030 indicate that ESP and fabric filter parameter monitoring is required for al l units not using HCl CEMS , but the language from page 25031 states that parameter monitoring is required onl y if units are not using PM CEMS
. According to the commenter, f abric 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 c ommenter 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.145

**Response to Comment 1 2**  **:** Control equipment parameters are not monitored under the final rule, so this concern is moot. **4 . Concerns with**  **u sing PM CEMS**  **d ata to**  **d etermine**  **c om** **pliance with n**  **on -**  **Hg m**  **etals s**  **tandard .**  **Comment 1 3**  **:** Commenter 17621 states that the merit s 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 IC R 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, m ost IC R test contractors used OTM
- 28 , a few used the original Method 202 , and b ecause none o f the IC R 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 M ethod 202 (condensable PM ) had much higher variability than Method 5 (filterable PM) for replicate test runs ( EPRI , 2011) and that in the IC R 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 adequatel y and requires additional research. The commenter states that l aboratory studies conducted by EP RI pointed to a potential negative bias in OTM
- 28 , which did not effectively capture SO 3 ( EPRI , 2009). , and that o nly

about half of the SO 3 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 increasingl y prevalent in power plants as wet FGD systems (which tend to produce SO 3 ) are added. The commenter states that a total PM limit is problematic for compliance monitoring, as continuous PM monitors measure onl y filterable PM. According to the commenter, s ince condensable PM emissions are a product of the coal sulfur content and other factors (e.g., ash properties, SCR SO 2 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 IC R 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 IC R
. According to the commenter, the IC R database does not contain sufficient historical c ondensable 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 IC R 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, a s many of the l owest 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 a s a result, there is considerable uncertainty146

regarding the true emissions of filterable PM from the power ind ustry
. The commenter states that the compliance method for filterable PM specified in the proposed rule is Method 5, while the IC R test data include filterable PM results from Methods 5, 29, and OTM
- 27
. According to the commenter, to 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 1 4**  **:** 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 f ollowing 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 c ommenter further notes the comments submitted by EPRI in this docket provide detailed anal ys is justifying the use of filterable PM as an adequate surrogate for all non

- Hg metals. The commenter states that among the key conclusi ons 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, particularl y Hg and selenium. **Comment 1 5**  **:** Commenter 17197 believes the proposed PM CEMS operating limit determination method is unworkable, arbitrary , likely overl y restrictive, and non

- representative. The c ommenter believes the better solution is replacing the proposed total PM limit with a filterable

- onl y 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 b y using the simultaneous EPA Method 5 and Method 202 st ack testing results to establish the EGU ’ s filterable

to - total PM ratio. According to the commenter, the PM CEMS operating limit (filterable PM) would be appropriatel y set b y 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 f

or 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, s etting the PM CEMS operating limit using this alternate methodology

is more representative because it utilizes all three performance test runs and no t 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 1 6**  **:** Several c ommenters (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 appears147

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 th at setting an enforceable limit on a surrogate seems refutable during enforcement proceedings. Several c ommenters (17623, 17677, 17681) suggest requiring another stack test for total PM within 60 days of exceeding the PM CEMS operating limit rather than de eming the source out of compliance with the HAP emissions limit. Commenters (17676, 18023 ) believe that annual compliance tests are sufficient to ensure compli ance. **Comment 1 7**  **:** Several c ommenters (17689, 17704, 17813, 18014) state that the proposed PM total approach is unworkable for several reasons. According to the commenters, M ethods 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 M ethod 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 , s o , in effect , M ethod 5 measurements when compared to PM CEMS measurements over full unit operating conditions is not appropriate. Several c ommenters (17689, 17702, 17704, 17813) state that the PM standard should be based on a PM filterable limit only
. **Comment 1 8**  **:** Comm enter 17737 states that PM CEMS provide an indirect measure b y “ 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 emi ssion standard. Commenter provides an anal ys is 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 Comm ents, EPA
- HQ
- OAR
- 2002
- 0058
- 2880 at 51
- 54; EPA
- HQ
OAR
- 2005
- 0031
- 0246, at 3
- 10). According to the commenter, f or 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 demonstrat e d false exceedance of the PM limit where the true PM level should have be in compliance. **Response to Comment s**  **1 3**  **- 1**  **8 :**  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 establ ish 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 bas ed 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 1 9**  **:** 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 l ikely 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 c ommenters ( 17737, 17790, 18014 ) state that use of the EPA ’ s148

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 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 1 9**  **:** 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 i f 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 artificiall y low PM standard for units using PM CEMS
. The commenter states that the compliance method should match th e 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 compl y 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 te st 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 o nce 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 filterabl e PM emission limit if the source elects to use this approach (see the final preamble for further discussion). **Comment 2 1**  **:** 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, f or 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 app roached. 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 note s that while section 63.10011(d) indicates that the operating limit will be bas ed 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 2 1**  **:** Under the final rule, you may elect to compl y 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 to149

determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final p reamble for further discussion). **Comment 2 2**  **:** Several c ommenters (17402, 17775, 17790) support use of PM as a surrogate for non

- Hg HAP metals. Other c ommenters (17402, 17675, 17716) request that the agency not require regulated units to install and use PM CEMS as the continuous compliance determination method. Several c ommenters (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 f ollowing issues relevant to the use of PM CEMS as a direct indicator of compliance following periodic performance tests: 1. Multiple c ommenters (17402, 17675, 17681, 17696, 17716, 17728, 17737, 17752, 17775, 17790, 17868, 18023 ) note the inaccuracy of PM CEMS at low concentrations; 2. Multiple c ommenters (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. C ommenters (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 c ommenters (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 c ommenters (17402, 1 7716, 17728, 17737, 17752, 17775, 18023 ) note the differences in measurement methods or conditions that can affect monitor calibration; 5. Multiple c ommenters (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 c ommenters (176 96, 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, SO 2 , HCl , and Hg during periods of PS
11 testing; 9. Commenter 18023 states there is a lack of NI ST traceable PM daily calibration standards: 10. Commenters 18023 and 17790 state the use of PM CEMS is cumbersome, expensive, and includes highl y variable calibration procedures. **Response to Comment 2 2**  **:** PM CEMS are no longer required under the final rule. You may elect to comply with an optional operating limit for PM. I f 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 meas ured 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 no t need150

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 2 3**  **:** Commenter 17737 states that the EPA should establish a separate standard for periods of startup and shutdown. According to the commenter, h owever, if the EPA promulgates a rule that requires use of PM CEMS as a compliance method d uring 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 2 3**  **:** The comment is moot, as the rule no longer has emissions limits applicable during peri ods of startup or shutdown. **Comment 2 4**  **:** 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 clearl y 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 accuratel y represents the actual emissions from the source and test methods should be clarified and not combine different testing and measurement components. **Response to Comment 2 4**  **:** PM CEMS are no longer required under the final rule. You may elect to comply with an optional operating limit for PM. I f 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 oper ating 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 2 5**  **:** 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, h owever , if total PM is retained the EPA sh ould 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 2**  **5 :**  The rule has a filterable, not total, PM emissions limit. **Comment 2 6**  **:** 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 averag e 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
.151

**Response to Comment 2 6**  **:** 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). **5 . Compliance**  **c osts if PM CEMS are not**  **a ppropriate**  **m onitors for**  **n on**  **- Hg HAP**  **m etals**  **. Comment 2**  **7 :**  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 seriou sly 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 2 7**  **:** PM CEMS are no longer required under the final rule
. You may elect to comply wi th an optional operating limit for PM. I f 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 no n - 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**  **a bout the**  **c ommercial**  **r ead**  **i ness of PM**  **CEMS .**  **Comment 2 8**  **:** Comment er 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 ye ars 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 EP A requirements. The commenter states that information from the IC AC 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 s ys tems for monitoring compliance with the applicable provisions of the proposed rule. **Response to Comment 2 8**  **:** See response to comment 37. **Comment 2 9**  **:** 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 onl y found four that clearl y d ealt with PM CEMS , from 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 nee ds 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 similar152

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 f

ilterable 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 th is portion of the PM emissions are critical for the mitigation of health effects associated with PM 2.5 . 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 PM 2.5 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

c ompanies in the U.S . have now installed or are planning to install PM CEMs
. The commenter questions how many different ty

pes of EGUs have PM CEMS (broken down b y unit configuration and fuel type). Finall y 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 2 9**  **:** Under the final rule, you may elect to compl y 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 final rule also includes the option to install and operate P M CEMS if the source chooses to comply with the filterable PM emissions limit. To apply this option, the source would have to meet Performance Specification 11 and procedure 2 of 40 CFR part 60 appendices B and F, respectivel y. **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, P S
- 11 requires a minimum of 15 Method 5 test runs to develop a calibration curve for the CEMS and a s 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 c ommenter asserts that w et 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 off

specification gy

psum. According to the commenter, in these cases, the calibration curve for the PM CEMS consists of the normal operating point and an artificial zero.153

According to the commenter there is not a lot of documentation available on the installed PM CEMS equipment; however, all of the systems now instal led on wet stacks have indicated some plugging problems. The commenter asserts that u suall y this has been handled b y 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, espec iall y where cross

- stack installations are possible , though o ne 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 filterabl e PM emission that can be accuratel y and precisel y measured b y 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 coal

fired EGUs (0.03 lb/MMBtu), but may not be sensitive enough to measure at the proposed total PM lim it for new coal

- fired EGUs (approximately 0.005 lb/MMBtu). Commenter notes that while a lower detection limit for Method 5 can be obtained b y extending the sampling time, longer sampling times will increase the time required to conduct the full 15 runs req uired b y 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 compl y with an optional operating limit for PM. I f you use this method to demonstrate continuous complian ce, 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 c ommenter 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, i f the EPA intends that a PM CEMS be used to assure compliance with the PM limit in Table 2, it ne eds 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 p art 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 w et scrubber technology will provide condensable PM remo val, 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 3 1**  **:** The final rule no longer requires a PM CEMS for compliance monitoring
. Under the final rule, you may elect to compl y with an optional operating limit for PM. I f 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

- Hg154

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 perf ormance 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 3 2**  **:** 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 b y conducting a three

- level Method 5 test but that unlike gaseous moni tors ( e.g ., SO 2 or NO X 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 correspondin g relief from current emission limitations and reporting requirements. **Response to Comment 3 2**  **:** The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to compl y with an optional operating limit for PM. I f 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 app licable 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 det ermine 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 Proce dure 2. Procedure 2 describes the 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 3 3**  **:** 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 also155

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 3 4**  **:** Commenter 17790 states that there is insufficient reliability in PM CEMS to give accurate data for EGUs with low PM emissions ( i.e., EGUs w ith FGD ). The commenter states that its Monroe Power Plant is currentl y 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 sub

standard performance such as plugged monitors and extended down time. **Response to Comment 3 4**  **:** The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to compl y with an optional operating limit for PM. I f 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 mea sured 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 n ot 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 w ould 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 3 5**  **:** Several c ommenters (17681, 17638, 18831) disagree with using PM CEMS for compliance for the following reasons . According to the commenters : 1. The co mmenter s believe PM CEMS have not proven to be reliable for the electric utility industry , 2. The ins truments are very expensive, 3. The instrum ents 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 3 5**  **:** The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to compl y with an optional operating limit for PM. I f you use this156

method to demonstrate continuous compliance, you must install a PM CPMS and establ ish 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 bas ed 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, thereb y demonstrating that an acceptable level of accuracy is achieved. PS

- 11 provides the steps in obtaining a reliable successful correlation with reference methods, thereb y 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 3 6**  **:** 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 relative ly 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 sy stem operating period and consequently , the performance testing time period may not represent ty

pical PM control efficiencies. The commenter states that the testing might occur during a highl y controlled period, resulting in an overl y 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 s ys tem ’ s effe ctiveness might be very effective and the EPA Method 5 and Method 202 testing show very low filterable and total PM emission rates while conversel y, hypothetical “ Facility B ’ s ” baghouse particulate control effectiveness might be compromised during the EPA Method 5 and Method 202 performance testing, barel y 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 Co mment 3**  **6 :**  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 this157

approach (see the final preamble for further discussion). Sources also may opt for quarterly

testing with re ference methods to determine compliance. **Comment 3 7**  **:** Commenter 17975 states that they have discussed with vendors, the ability of the two primary ty pes 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 v endors have assured the commenter that if the specifications call for measurements of high concentrations of PM then they can su ppl y the appropriate instrument packages. Commenter notes that there is nothing inherentl y 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, especiall y for units with ESPs. Commenter provides a short explanation of both ty pes of CEMS
. **Response to Comment 3 7**  **:** As mentioned els ewhere, the comment is moot, for the final rule no longer contains emissions limits applicable during startup or shutdown periods and provides for affirmative defense in the event of excess emissions that occur during a malfunction. **Comment 3 8**  **:** 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 c ommercially 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 anal ys es or bimonthly Method 29 stack tests. **Response to Comment 3 8**  **:** 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 3 9**  **:** 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 widel y deployed across the utility

industry and because th e agency has made use of PM CEMS optional under 40 CFR p art 60 , subparts D and Da
. The c ommenter 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

- ye ar demonstration period for PM CEMS . According to the commenter the language in the consent decree acknowledges that PM CEMS technology

is still in development. The c ommenter 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 highl y efficient PM controls. The commenter states that the PS

- 11 procedures place source operators at risk of exce eding 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 3 9**  **:** The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to compl y with an optional operatin g limit for PM. I f you use this158

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 mu st 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 o f 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 co mmenters 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, thereb y demonstrating th at an acceptable level of accuracy is achieved. PS

- 11 provides the steps in obtaining a reliable successful correlation with reference methods, thereb y ensuring compliance data that is sufficient to determine compliance with PM emission limits. Most all su ccessful 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 c ommenters (17402, 17681, 17716, 17737, 17758, 17820, 18014) characterize PM CEMS as not measuring PM directl y, 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 compl y with an optional operating limit for PM. I f 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 th e 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 h ave 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 stati stical criteria, thereb y demonstrating that an acceptable level of accuracy is achieved. PS

- 11 provides the steps in obtaining a159

reliable successful correlation with reference methods, thereb y ensuring compliance data that is sufficient to determine compli ance 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 4 1**  **:** Multiple c ommenters (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 ref lected 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 Comm ent 4**  **1 :**  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 i s 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

- f uel 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 4 2**  **:** Several c ommenters (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
. **Response to Comment 4 2**  **:** The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to compl y with an optional operating limit for PM. I f 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 P M CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable160

PM emission limit if the source elects to use this approach (see the final preamble for further discussion). **Comment 4 3**  **:** Commenter 177 61 states that if emission reductions are mandated, it must be recognized that PM CEMS have not been widel y deplo ye d and their utilization has been largel y limited to requirements imposed b y the EPA in NSR consent decrees with escape clauses in place. The c ommenter 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 currentl y 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 4 3**  **:** 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 adequatel y reliable technology

and are have not been widel y 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, thereb y 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 compl iance 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, thereb y ensuring reliable compliance data. **Comment 4 4**  **:** 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 F R 7908 (Feb. 16, 2005) (justifying the use of COMS because CEMS are “ significantl y 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 PM CEMS . The commenter also asserts that it is also unclear how a range of PM concentrations can be created during perform ance testing when a fabric filter baghouse is used for particulate control. **Response to Comment 4 4**  **:** 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 c orrelation 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 and161

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 train s 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 4 5**  **:** 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 4 5**  **:** 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 adequatel y 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, thereb y 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 acc eptable limits, thereby ensuring reliable compliance data. Under the final rule we have dropped the requirement for monthly stack tests. **Comment 4 6**  **:** Commenter 18935 recommends that the EPA develop a guidance document for performance specification testing o f PM CEMS that reflects recent experience with current control technologies and emission levels. The c ommenter also suggests that sources be allowed a phase in period for PM CEMS , perhaps allowing sources to conduct frequent periodic monitoring b y 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 sy stems perform consistently and reliabl y when matched to source characteristics

– changing operations to produce alternate emission levels is not an eas y 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 i f 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 reall y designed for ambient particulate monitoring). **Response to Comment 4 6**  **:** PM CEMS are no longer required unde r the final rule. You may elect to comply with an optional operating limit for PM. I f 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 P M, 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. I f yo u 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 c**  **ertification i**  **ssues .** 162

**Comment 4 7**  **:** Commenters 17800 and 17914 request clarification on the procedures to be used for certification of PM CEMS
. Inorder 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 b y P S
- 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 temporaril y, partially disable fabric filters not equipped with flue gas bypass dampers to generate higher PM emissions. In addition, state the c ommenters, 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 s ynthetic 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. **Comme nt 4**  **8 :**  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 o f post combustion emissions control, IGCC sy ngas - 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 b y GE on a comb ustion turbine), but these sy stems 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 4 7**  **- 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 estab lish 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. I f yo u 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. 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 employin g 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).163

**7 . Pr**  **oblems with “**  **f**

**loating l** **imits .**  **” Comment 4**  **9 :**  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. A ccording to commenters, a s 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 b y 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 t arget 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. I f you use this method to demonstrate continuous compli ance, 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 yo u use a PM CPMS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test onc e annuall y 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 subsequ ent performance tests and this could result in progressivel y 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 emissi ons 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. I f 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 l iquid 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 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 5 1**  **:** Several c ommenters (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 commenter s it is conceivable that an EGU could meet the164

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 emissi ons rate (as determined b y PM CEMS ) indefinitely . The commenters state that the “ operating limit” for filterable PM reflects a limit on the only fraction of total PM removed b y 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, especiall y in units like power generation equipment that must operate for extended periods between maintenance out ages. The commenter conjectures that the “ EPA apparentl y assumes that condensable PM is both an indeterminate and widel y 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 relativel y fixed increment during normal operation. Based on the commenter ’ s assumption that the condensable PM rate is relativel y constant, the commenter recommends that the condensable PM emission rate ( lb condensable PM/MMBtu) measured b y the reference method in the most recent performance test should be utilized as a constant value in the following equation to determine the hourl y 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) + (fPM from 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 5 2**  **:** 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 177 16 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 5 1**  **- 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 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 o nce 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 filterabl e PM emission limit if the source elects to use this approach (see the final preamble for further discussion).165

**Comment 5 3**  **:** 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 highe st potential filterable PM limit where condensable emissions are reduced to zero. **Response to Comment 5 3**  **:** 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 5 4**  **:** 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 alway s occurs. **Response to Comment 5 4**  **:** The a gency disagrees with the commenters, for the PM emissions limit includes a variability

component determined using ICR Part II data and the UPLcalculation. **Comment 5 5**  **:** 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 th e 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 go al of the regulation should be to ensure that facilities maintain emissions below the given emission standard in the regulation; this is achieved b y having a facility demonstrate that filterable PM measured with a CEMS in combination with condensable PM me asured 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 t hat 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 con densable PM thereby passing the performance test; the unit would then have to meet a 0.008 lb/MM BTU 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/MM BTU for filterable P M and 0.01 lb/MM BTU for condensable PM, thereby passing the performance test; this unit would then have a 0.02 lb/MM BTU 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 p roposed rule governs ongoing operations does not give the unit with the baghouse credit for its low emissions. According to the commenter, the limits for the baghouse unit should be calculated as the proposed Total PM limit, 0.03 lb/MM BTU , less the condens able fraction, 0.012 lb/MM BTU , to give the source its filterable PM CEMS limit of 0.018 lb/MM BTU; this approach would meet the spirit of the proposed rule b y limiting a source to the MACT floor, while giving the source credit for good performance
. **Respons e to Comment 5**  **5 :**  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 compl y with an optional operating limit for PM. See the response to Comment 53 above
.166

**Comment 5 6**  **:** Multipl e c ommenters (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 ye ars of operation (even with frequent maintenance). 2. According to the commenters, the source ’ s margi n 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 op erate 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 barel y 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 g oal of uniform standards. 6. According to the commenters, an exceedance of the PM CEMS operating limit does not necessaril y indicate actual emissions were above the underl yi ng PM standard or non

- Hg HAP standard. **Response to Comment 5 6**  **:** The final rule requires the use of a PM CPMS for an operational limit and does not enforce a numeric PM limit
. I f 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 filtera ble 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 perfo rmance 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 re

establish the operating limit during each performance test
. Any degradation of the control equipment will be accounted for in the yearl y reestablishment of the PM operational limit and the compliance margin will change accordingl y . 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 th e operating limit during the initial compliance test for filterable PM, total non

- mercury HAP metals, or individual non

- mercury HAP metals using the167

highest 1

- hour average measured, along with allowing more than one operational limit for different load con ditions, 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 quarterl y emissions testing. **Comment 5 7**  **:** Commenter 17808 recommends changing the treatment of condensable PM for units using PM CEMS to establish an operating limit on filterable PM . The c ommenter 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 po wer 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 c ould 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 5 7**  **:** 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 5 8**  **:** 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 CE MS 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 b y PM performance tests, which are the only process that can measure b oth filterable and condensable particulates. 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 5 8**  **:** Measurement of condensable PM is no longer required under the rule.168

**8 . Variability of**  **r eference**  **m ethod**  **d ata from**  **s crubbed**  **u nits**  **. Comment 5**  **9 :**  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 highl y variable and consistently low PM data, the commenter believes it will be nearl y 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 5 9**  **:** Measurement of condensable PM is no longer required under the new rule. The final rule does inclu de 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 highl y 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 PM 2.5 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 6 1**  **:** 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, ty

pically 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 compl iance margin. The commenter states that the EPA has not justified this ty pe of requirement and it must be eliminated from the final rule. **Response to Comment 6 1**  **:** 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**  **a vailability**  **c riteria**  **. Comment 6**  **2 :**  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 6 2**  **:** PM CEMS are no longer required in the final rule. **10 . Table 4**  **r equirement to**  **c onvert PM CEMS**  **r eadings to**  **d ry**  **b asis**  **. Comment 6**  **3 :**  Several c ommenters ( 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 because169

most PM CEMS do not measure on a dry basis but are correlated to “mg/w scm. ” 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 t est 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 anal yz er response (mg/wacm , mg/wscm , etc.) or lb/MMBtu values as an indicator. **Comment 64** : Comm enter 17881 states that under section 63.10021(a)(11)(ii) diluent data (O 2/CO 2 ) is only needed for the lb/MM Btu rate calculation or concentration values corrected back to a diluents gas concentration (which is not the case, as the PM filterable operating l imit is mg/dscm and is not corrected back to a specific diluent level). **Response to Comments 6 3**  **- 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. f** 

**abric f**  **ilters .**  **Comment 6 5**  : Commenter 17705 has concerns because while ESPs are highly effective control technologies, they

may not be as consistent in its day

- to - day performanc e as fabric filter technology
. According to the commenter, this difference is not a problem at currentl y 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 c ommenter doubts that even utilities with EGUs equipped with fabric filters can be confident they

can demonstrate continuous comp liance if the PM operating limit requirement is implemented as proposed by the EPA. **Response to Comment 6 5**  **:** 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 quarterl y performance testing in place of these continuous monitoring options. **12 . Direct**  **m easurement**  **. Comment 6**  **6 :**  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 f it with the requirements and purpose of the law. **Response to Comment 6 6**  **:** Consistent with the CAA, the rule requires monitoring sufficient to assure compliance with the emissions limits and that the sources will maintain emissions reductions on a continuou s basis. The rule applies continuous emissions monitoring effectively with a focus on the HAP170

(Hg) of interest and allows for other monitoring in a manner consistent with the CAA. We also believe that implementing this rule with the required frequent testing, including HAP metals, and continuous emissions monitoring will provide a significant increase in the amount of directl y measured emissions data over the current database. The rule also requires electronic reporting of monitoring and testing data direc tly to the EPA so that we will have these data in hand for supporting subsequent regulatory reviews. **Comment 6 7**  **:** 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) currentl y discusses the use of PM CEMS for demonstrating compliance with the applicable emission limits in Ta bles 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) c onsistent 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 6 7**  **:** We have edited the final rule so that the text is consist ent with the format of the required measurements. Note also that m easurement of condensable PM is no t required in the final rule and PM CEMS are no longer required in the final rule. Th e final rule does provide for the use of a PM CEMS to determine compli ance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion). **13 . Clarification on**  **u se o**  **f p**  **arametric m**  **onitoring in l** **ieu of CEMS**  **. Comment 6**  **8 :**  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 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 chang e 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 example171

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

v ariation 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 c ommenter 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 c ommenter 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 6 8**  **:** Measurement of condensable PM is no t 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 6 9**  **:** Commenter 19033 recommends that the operating requirements for ESP power input, as documented during performance tests, onl y be applicable during periods of PM CEMS downtime, so that it can be demonstrated that the ESP is operating properl y during such PM CEMS downtime events. The commenter state s that s uch a provision would be patterned after the Part 75 requirements that address demonstration that the APCD is operating properl y, so that SO 2 substitution values can be supported during periods of SO 2 CEMS downtime. **Response to Comment 6 9**  **:** Parameter monitoring of ESP parameters is no t 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, includin g bag leak detectors, is no t required in the final rule. **14 . Corrections**  **. Comment 7**  **1 :**  Commenter 18014 states that Table 8 erroneousl y references “ QA Procedure 5 ” for the PM CEMS QA/QC requirements. According to the commenter, this reference should be chan ged to “ Procedure 2. ” **Response to Comment 71 :**  This reference has been removed in the final rule. **Comment 7 2**  **:** 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 7 2**  **:** The final rule requires a 30

- boiler operating day rolling average for the PM CPMS monitoring. **Comment 7 3**  **:** 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)).172

**Response to Comment 7 3**  **:** 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 compl y with the QA requirements in PS 11. Howev er, 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 7 4**  **:** Several c ommenter s ( 19536 , 19537 , 19538 ) state 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 commenter s 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
- ye ar 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 commenter s , HAP such as selenium, which the EPA admits is frequently present in the gases , would not be measured either directly with Method 29 or indirectl y through a surrogate when PM CEMS is used to determine compliance. The commenter s also state that initial performance compliance provisions are missing from Table 5 for PM CEMS
. **Response to Comment 7 4**  **:** You may elect to comply

with an optional operating limit for PM. I f 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 compliance shal l 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**  **- y**  **ear t**  **est r**  **equirement .**  **Comment 7 5**  **:** 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 overl y 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 m onitoring option, require stack testing every 2 ye ars instead of 5 ye ars to establish compliance with metal emission limits relative to filterable PM emissions. The commenter states that u sing a CEMS approach is premised on the EPA ’ s ability to establish a relationship between filterable PM and metals emissions on a sector

- wide basis and s ources 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 m onitoring approach the EPA should eliminate any requirement for testing and setting of pollution control equipment operating parameters.173

**Response to Comment 7 5**  **:** 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 7 6**  **:** 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 7**  **6 :**  The comment is moot, as the rule does no t 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**  **s urrogate Method 202**  **. Comment 7**  **7 :**  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 accuratel y 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 cons truct a test method that will be accurate and repeatable for in

- stack measurements. **Response to Comment 7 7**  **:** While the agency disagrees with the suggestion that Method 202 is “incapable of accuratel y measuring the condensate in a replicable fashion routine ly ,” the comment is moot, as the final rule does no t contain a total PM emissions limit. **17 . Miscellaneous**  **. Comment 7**  **8 :**  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, anal yzing, 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 s ys tem that use s 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 adequatel y measure these emissions in this 15 minute timef rame. The commenter states that the EPA should allow some flexibility in this requirement to allow for monitoring extremely low levels of filterable PM emissions. **Response to Comment 7 8**  **:** Measurement of condensable PM is no t required in the final rule. PM CEMS are no t required in the final rule. **Comment 7 9**  **:** 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.174

**Response to Comment 7 9**  **:** 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 d as an “ indicator of compliance ” for an “ appropriate ” filterable PM limit, to identify when investigation and corrective action are 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 8 1**  **:** 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 reali ty

there is very

little flexibility in light of the problematic and unproven nature of these monitoring technologies. Commenter 17736 states the EPA cannot rel y on unproven HCl CEMS, that HCl CEMS are not commerciall y available to measure HCl emissions fro m coal

- fired EGUs, and no HCl CEMS were used to collect the data the EPA used to establish the HCl standard. **Response to Comment 8 1**  **:** The agency disagrees with the commenters. As mentioned elsewhere, the agency finds that the operation and maintenance issue s 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 option s to demonstrate compliance exist for those EGU owners or operators who choose not to use CEMS.175

**5A07b -**  **Testing/Monitoring: Application of multi -**  **metals CEMS Commenters**  : 17283, 17747, 19536 , 19537 , 19538 **1 . In**  **f avor of**  **m ulti**  **- m**  **etals 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 availabi lity of multi

metal CEMS, the fact that multi

- metal CEMS represent substantially enhanced monitoring and PM is not an appropriate surrogate for HAP metals emissions in an increasingl y 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., directl y monitoring the HAP pollutant of c oncern on a continuous basis). **Response to Comment 2:** Short term multi

- metal CEMS demonstrations have historicall y 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 expressl y allowing the use multi

- metals CEMS once a multi

- metals performance specification has been promulgated. According to the commenter, the incorporation of this ty pe 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 woul d 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 Co mment 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 multi

metal 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 the176

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 i s 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 n ot to use CEMS or the other instrumental methods, performance testing is required. **2 . Individual**  **m etals**  **. Comment 5:**  Commenter 17283 states that monitoring onl y 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 particularl y 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 indiscriminatel y 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. **Respons e to Comments 5**  **and 6:**  Note that the final rule no longer applies a numerical emissions limit during startup and shutdown much reducing concerns about limited measurement of particulate Hg. 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, chemicall y, very similar to sulfur. In the high temperature combustion environment, selenium is likely to be present as gas phase SeO 2 (as, similarly , sulfur is likel y to be present as gaseous SO 2 ). Much like SO 2 , SeO 2 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 SeO 2 acid gas, forming a particulate that is easily removed in the PM control device. Eastern bituminous coals ty picall y contain insufficient free Ca to completely neutralize the SeO 2 and the much increased levels of SO 2 in that flue gas. However, because SeO 2 behaves very similarl y to its sulfur analog, SO 2 , it can be expected to also be removed effectivel y in standard FGD technologies (wet scrubbers, dry scrubbers, DSI , etc.). Therefore, selenium will either fall in to the category of ‘‘ non - Hg metal HAP ’’ and be effectivel y removed in a PM control device, or it will fall into the category of ‘‘ acid gas HAP ’’ as gaseous SeO 2 and be effectively removed using FGD technologies. We specificall y reviewed the Method 29 data fro m the utility boiler IC R 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 loc ation 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.177

**3 . Concerns**  **a bout**  **u se of PM as a**  **s urrogate**  **. 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 by passing 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. **Re sponse 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 sourc e. 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 re liable 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 dramaticall y 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 directl y and continuousl y. **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 properl y conducted in the field. The cost of using this method is actually much more economical, per anal yt e than many other test methods that the EPA employs to measure emissions. **Comment 9:** Several c ommenter s ( 19536 , 19537 , 19538 ) state that total PM is not an appropriate surrogate for non

- Hg metal HAP and those HAP can be accuratel y measured by CEMS. According to the commenter, if the EP A 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 11.178

**5A08 -**  **Testing/Monitoring: Application of SO 2**  **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**  **e xisting**  **IGCC u**  **nits to u**  **se SO 2**  **CEM S**  **o ption**  **. Comment 1:**  Commenter 17191 believes it is appropriate for the EPA to include the SO 2 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 SO 2 monitoring for existing IGCCs , that SO 2 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

- S tate Air Pollution Rule). The commenter stresses the importance of the SO 2 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 rel y on existing SO 2 monitors for acid gas compliance rather than incurring the cost of installing HCl monitors that have little or no long

- term demonstrated “ real world” rel iability. The commenter requests that the SO 2 CEMS monitoring option be included for the existing IG CCs as a matter of equity and fairness. As these data are readil y available to the EPA and interested public, there is no basis for the EPA ’ s preamble justi fication for not including the option. While the commenter specificall y references their IGCC unit, they do note that it is one of only two IGCC EGUs currently

operating that are included in the existing IG CC 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 SO 2 CEMS limit. The commenter notes that their IGCC system uses a sulfur removal s ys tem upstream o f the combustion of the sy ngas ; th e removed sulfur is captured and sold as molten sulfur for reuse. A ccording to the commenter, a s 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 SO 2 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 th e regulation that need to be amended so that existing IG CC 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 revi sion before final rule issuance that would prohibit existing IGCC SO 2 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 gas179

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 SO 2 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 clearl y defined in the final rule. **Response to Comments 1 -**  **2:** The EPA disagrees with the commenter s ’ suggestions First, the premise upon which the rule allo ws for SO 2 monitoring in lieu of HCl monitoring of the exhaust of a wet or dry FGD unit is that the FGD preferentiall y removes HCl over SO 2 . That means that SO 2 control is a certain indicator of similar or better HCl control when the control measure is a w et 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 SO 2 data from existing IGCC units to correlate with HCl emissions. The SO 2 data pne 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 SO 2 as an indicator of HCl control. The preamble to the proposed rule fully explains the rationale for this limitation. **2 . SO**  **2 CEMS**  **c ertification**  **. Comment 3:**  Commenter 17677 states that section 63.10010(e) creates some confusion about certification of SO 2 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 gen eral p art 60 and p art 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 SO 2 monitoring. The commenter states that section 63.10010(e)(6)(ii) of the proposed regulations states that one “must perform the linearity check te st required in Appendix A to p art 75 on the SO 2 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 , the EPA acknowledged that span at these low values loses its significance. The commenter believes the180

proposed requirements should be replaced with the Part 75 exemption. According to the commenter p art 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 anal yzer 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 deter

mine that the anal yz er is linear. The c ommenter 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 SO 2 CEMs for compliance at emission standard levels. **Comment 5:** Commenter 17758 states that it is confusing why, despite using continuous SO 2 monitors successfull y for more than 20 years, the EPA has propos ed additional QA requirements. The commenter states that in proposed section 63.10010(e)(6) the EPA has added several problematic additional QA requirements for SO 2 CEMS that are not currentl y specified in Appendices A or B of 40 CFR p art 75
. The commenter notes the following:

 Section 63.10010(e)(6)(i)

– According to the commenter, the proposed Utility MACT rule would require the SO 2 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 SO 2 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 speci fication 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 SO 2 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 SO 2 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 s ys tems to accommodate the new calibration gas cylinders, and will increase calibration gas costs, not only in the capital cost o f 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 s ys tem will be incurred by the utility . According to the commenter, this requirement is unnecessary and will not improve the quality of SO 2 data being colle cted. The commenter states that current guidelines in 40 CFR Part 75 ensure that the majority of emission measurements made b y an SO 2 CEMS fall within a certain percentage of the monitor ’ s calibrated span and that users are required to evaluate the span of the SO 2 CEMS181

on annual basis, which has proved sufficient in maintaining the overall integrity and accuracy of the SO 2 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 nominall y near the standard. The EPA disagrees that a linearity check is unnecessary to ensure quality assurance of the SO 2 CEMs for compliance at emission standard levels and will retain that requirement. In addition, sources may choose to compl y with HCl CEMS or periodi c HCl testing in lieu of updating their SO 2 CEMS system to check linearity quarterl y. **3 . Revisions to**  **FGD a**  **pplicability .**  **Comment 6:** C ommenters 17728 and 17775 support the EPA ’ s inclusion of an option for use of an SO 2 CEMS to comply

with a surrogate limit for SO 2 ; 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 SO 2 control device malfunctions or that must by pass controls during the initial portions of startups or to perform maintenance (which generally require b yp ass of the entire control unit). The commenter states that for units without a by pass stack, any resulting emissions would be monitored in the main stack with the SO 2 CEMS; f or units with a by

pass stacks, temporary

by pass 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 SO 2 emissions are accounted for those emissions will reflect the potential for higher HCl as well, and any unit complying with th e 30
- day rolling average SO 2 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 us e of a b ypass stack during periods of malfunction or maintenance, provided SO 2 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 SO 2 controls intermittently, and not to disqualify EGUs that experience SO 2 control device malfunctions or that must operate without control devices during periods of EGU startup and shutdown. Commenter 17714 st ates that the EPA should clarify that operation of FGD technology is onl y 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 SO 2 limit, the EPA should qualify that that “ at all times ” is not intended to disqualify units that experience control malfunctions or that by pass 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 SO 2 limit to demonstrate compliance with the acid gas HAP emission limitation. The commenters believe that if a unit can demonstrate compliance with the applicable SO 2 limit based on monitored emissions from the by pass and the182

scrubbed stack, a source should be allowed to exhaust to the by pass stack, at least, on a limited basis, as many of these stacks are already equipped with SO 2 CEMS
. One commenter notes that exhausting to the by pass stack is a necessary

option in many

cases, and provides four examples. **C omment 8:**  Several c ommenters ( 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 SO 2 controls intermittently, and not to disqualify EGUs that experience SO 2 control device malfunctions or that must turn off controls to perform maintenance. The commenter s note the higher SO 2 recorded b y the CEMS during such periods will reflect the potential for higher HCl as well, and as long as the SO 2 CEMS meets the surrogate standard for HCl these FGD off periods should not disqualify an EGU from using an SO 2 as a surrogate. The commenters suggest the EPA make clear that the existence of a by pass stack does not disqualify

an EGU from complying with the standard. **Comment 9:** Commenter 17886 supports the option to use SO 2 CEMS to comply with a surrogate SO 2 limit; however, the commenter believes use of a by pass 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 by pass stack is in use. **Commen t 10:**  Commenter 18037 does not support the requirement that SO 2 controls must be operated at all times if the SO 2 surrogate is selected. The commenter believes that so long as a facility complies with SO 2 emissions limits, operators should have the flexibi lity to operate SO 2 controls in any mode to meet the compliance limit. The commenter recommends that the EPA remove the continuous control requirements regarding SO 2 from the proposed rule. The commenter believes this additional requirement is superfluous if SO 2 is a reasonable surrogate, and if facilities monitor SO 2 continuously using reliable CEMS . The commenter believes an EGU that demonstrates compliance with SO 2 limits, but whose SO 2 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 SO 2 limit and clarify that FGD by

pass is allowed during times of FGD forced outage. The commenter believes these changes would allow very limited continued operation through the b yp ass during upset conditions. **Comment 12:** Commenter 18023 believes that for PC units, the EPA should allow a scrubbed unit to by pass for a short time and allow the source to use the SO 2 monitors in the by pass 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 by

pass stack. If a unit that by passes controls for a short period of time is capabl e of meeting the MACT SO 2 limit, then scrubber b yp ass 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 ” langu age. The intent is that the FGD be operated during all boiler operations and not operated intermittently , seasonall y, or on some other non

- fulltime basis. Thus, this alternate limit is allowed even if b yp ass 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 s ys tem must be in accordance with the work practice standards during those periods ( i.e., the s ys tem must be engaged before coal or residual oil is burned in the boiler unit).183

**4 . SO**  **2 as**  **s urrogate**  **. Comment 13:**  Commenter 17730 agrees with the proposal by the EPA to use SO 2 as a surrogate as one of the options for measuring the acid g ases category of HAP . The commenter also appreciates the proposals reliance on the SO 2 CEMS as the basis of ongoing compliance with the requirements. The commenter believes SO 2 emissions were well correlated with the acid gases in the anal ys is of the EPA ICR test data. SO 2 CEMS are used b y the commenter to measure the emissions of SO 2 , and the commenter believes they produce accurate emission e stimates. **Comment 14:** Commenter 17758 believes there is no basis for testing of the surrogate SO 2 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 SO 2 CEMS but with installed systems that use wet or dry flue gas desulfurization technology” to conduct “ all applicable performance tests for SO 2 and HCl emissions ” at least every year and to “ conduct SO 2 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 SO 2 CEMS as a surrogate monitoring technology for HAP acid gases . **Comment 16:** Several c ommenter s ( 19536 , 19537 , 19538 ) endorses SO 2 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 anal yz ers, it is reason able to expect that equipment will be available to measure SO 2 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 , respectivel y), even accounting for the dilution extractive sampling s ys tems. The commenter notes that at the emission levels ty pically 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 quarterl y on SO 2 analyzers with span values less than 30 ppm SO 2 that are currentl y certified to report under 40 CFR p art 75 rules. The commenter recommends the EPA add a subsection to section 63.10010(e) that clearl y s tates that 40 CFR p art 75 data substitution procedures and bias adjustment factors are not to be used to calculate the 30 boiler operating day average SO 2 emission rate. **Comment 19:** Commenter 17886 recommends the EPA clarify that provisions in section 63.10006(k) do not apply

to E GUs with SO 2 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 SO 2 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 SO 2 limit and proposed Tables 1 and 2 clearl y provide sources the option of meeting an HCl or an SO 2 standard. Commenter 17775 also believes the EPA does not explain what it means by EGUs “without184

SO 2 CEMS ” or what significance those SO 2 CEMS have for EGUs not choosing to comply with the surrogate SO 2 limit. The commenter suggests that virtually all coal

- fired EGUs covered b y this proposed rule already have SO 2 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 SO 2 CEMS , but not HCl CEMS , from proposed requirements appl icable 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 s ys tem that measures a surrogate for a pollutant (e.g., an SO 2 monitor)
. ” **Comment 21:** Commenter 17881 notes for those units with an SO 2 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. **Resp onse to Comments 1**  **3 -**  **21:** The EPA appreciates the support for the use of SO 2 as an alternate equivalent standard and reliance on an SO 2 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 SO 2 testing requirements do not apply , and vice versa. **5 . Part 75**  **c oncerns**  **. Comment 22:**  Commenter 17722 supports inclusion of 40 CFR p art 75 monitoring provisions for SO 2 CEMS ; ho wever, the commenter does not support the addition of new p art 75 requirements. The commenter cites section 63.10010(e)(6), which requires additional provisions not currentl y needed for an SO 2 CEMS under p art 75
. The commenter notes that a s a comprehensive monitoring rule, p art 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 p art 75 SO 2 collected data is accepted by the EPA as credible evidence of compliance with Acid Rain provisions, it should also be ac ceptable 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 c ommenters ( 17725, 18014 , 18498 ) suggest that while the rule allows the use of Part 75 SO 2 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 p art 75 on the SO 2 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 p art 75 affected sources has completed initial certification years ago and has been collecting “ quality

- assured ” dat a 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 p art 75
. Commenter 17820 believes requiring these tests will complicate compliance for EGUs currently compl ying with p art 75 and without providing any added accuracy to the measurement. Commenter 17790 suggests these requirements be removed for companies that plan to use th eir p art 75 SO 2 CEMS . The commenter notes185

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 quarterl y linearity testing and that CEMS are meeting the 7

- day calibration error specification on a daily basis during their dail y 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 Acquis ition and Handling S ys tems ( DAHS ). In addition, the commenter notes p art 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 SO 2 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 th ese QA/QC requirements beyond what p art 75 requires. The commenter believes the fourth linearity calibration injection standard is overl y 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 SO 2 CEMS meeting p art 75 , but imposes linearity and 7

- day calibration error test requirements not required under p art 75 . The commenter cites 67 F R 40394 and 40408

- 09 (June 12, 2002) in which the EPA specificall y exempted CEMS with spans of 50 ppm or less from the 7

- day calibration error requirement under p art 75 because it was no longer necessary . The commenter also cites 63 F R 28032 and 28061/3 (May 21, 1998) where the EPA specificall y 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 relev ant 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 p art 75 without providing any added accuracy to the measurement. **Comment 27:** Commenters 17775 an d 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 p art 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 p art 75 , Appendix A section 2.1.1. The commenters believe there is nothing to be gained b y potentially

adding a fourth calibration gas, and since existing SO 2 CEMS and the accompanying DAHS have not been certified using a fourth calibration gas, and are not currentl y design ed to support a fourth calibration gas, this new requirement would unnecessarily increase costs for SO 2 CEMS . The commenters believe the EPA must remove these requirements, or issue for comment a proposal that provides some rationale for requiring these te sts in this context. **Comment 28:** Commenter 17821 strongl y 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 impl y that more accurate measurements would be obtained b y the SO 2 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 b y186

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 ea ch and every quarter. Commenter 17821 additionally states the alternative limit when using an SO 2 emissions system for compliance with an HCl limit under these proposed rules is defined in terms of lb/MMBtu
. SO 2 and diluent monitors (O 2 or CO 2 ) 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 SO 2 or diluent monitor for linearity at a fourth concentration level “nominally at the concentrati on level equivalent to the applicable emission limit” would be extremely subjective. The commenter states that c oncentrations of SO 2 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 currentl y using SO 2 monitoring s ys tems in compliance with 40 CFR 75 are required to deve lop 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 ty pically performed. Additionally , states the commenter, all sources equipped with SO 2 emission control systems utilize dual range SO 2 monitoring s ys tems (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 SO 2 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 SO 2 emission control sy stem. The commenter believes very low concentrations of SO 2 will dictate very low range meas urement on these dual range anal yz ers, 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. Th e commenter states that p art 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 SO 2 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 p art 75 SO 2 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 sy stems (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 p art 75 and concluded that these tests were not appropriate for level

- level emissions monitoring sy stems. Commenter 17881 believes the provisions of section 63.10010(e)(iii) which would also require that at leas t 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 non sensical, as the vast majority of p art 75 SO 2187

CEMS installed on units with add

- on SO 2 control devices will be dual

- range instruments. As such, states the commenter, the high level range of these instruments will generall y be reflective of SO 2 emissions without add

- on SO 2 controls, which will surely be much higher than the applicable SO 2 emission limit, and thus , the SO 2 CEMS will be calibrated over an aggregate (i.e., low and high) measurement range which encompasses the applicable SO 2 emissio n limit, and this should be adequate to ensure the accuracy of the SO 2 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 p art 75 , Appendix A, section 2.1.1.4(f) for those dual span units with SO 2 emissions controls. According to the commenter, this would essentially ensure that any EGU which elects to compl y with a surrogat e SO 2 limit (which inherentl y requires add

on SO 2 controls) has quality assured SO 2 measurement ranges which encompass the applicable SO 2 emission limit. Commenter 17881 believes the concept of a calibration gas with a concentration nominally equivalent to the applicable SO 2 emission limit is unworkable, as the SO 2 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 b y boile r 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 SO 2 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 63.1 0010(e)(6)(i) thru (iii) will require additional calibration error and linearity check tests that are not currentl y required under 40 CFR p art 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 SO 2 CEMS requirements beyond the QA/QC requirements and guidance in the existing federal regulations for 40 CFR p art 75
. **Comment 31:** Commenter 17868 suggests the EPA allow all p art 75 exceptions. The commenter notes proposed section 63.10010(e) allows use of an SO 2 meeting p art 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 SO 2 CEMS , which are similar to proposed section 63.1 0010(e), except this provision does not reference the p art 75 option. One commenter suggests the EPA reference the p art 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 p art 75 on the SO 2 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 p art 75
. One commenter provides an example and proposes the requirement should be removed and replaced with the p art 75 exemption. **Comment 34:** Several c ommenters ( 17725, 18014 , 1 8498 ) reference section 63.10010(e)(6)(iii), which states “the initial and quarterl y linearity checks required under Appendix B of Part 75 must include a188

calibration gas (at a fourth level, if ne cessary) 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 clearl y defined. The commenters state that p art 75 has requirements in place to ensure that the anal yz er span is set to obtain accurate and representative data. Commenter 17725 notes this requirement will significantly increase SO 2 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 SO 2 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. A ccording to the commenter, any

emission limit will reside in the lower range of a dual range anal yz er, which is typ ically 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 s ys tem. **Comment 36:** Commenter 17821 supports the EPA ’ s inclusion of the option to operate, maintain, and quality assure an SO 2 monitoring s ys tem under 40 CFR 75 if the source operates such a s ys tem for compliance with Acid Rain. **Comment 37:** Commenter 17886 suggests the EPA harmonize the SO 2 CEMS requirements with p art 75 as most if not all EGUs should already have these systems in place meeting p art 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 SO 2 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 SO 2 is never mentioned in Appendix A. **Comment 39:** Commenter 17881 objects to subjecting p art 75 monitoring systems to the data reduction procedures in section 63.10010(e)(4), as these procedures are in part inconsistent with the p art 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 maintenanc e or quality activities are conducted in a given hour and onl y 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 p art 75 subject sources to maintain two separate sets of data based upon two different validation regimes is overl y burdensome and unwarranted, and suggests p art 75 SO 2 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 p art 75 missing data shall not be used in calculating the 30 boiler operating day

average SO 2 emission rate. A ccording 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 SO 2 CEMS
.189

**Response to Comments 2 2**  **- 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 SO 2 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 p art 75 reporting. The 7

- day calibration error test is removed as unnecess ary . As noted elsewhere in this response to comments document, the final rule confirms that the bias adjustment and substitute data provisions under p art 75 do not apply when using an SO 2 CEMS to demonstrate compliance with the SO 2 emission limit in this rule.190

**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, 17 800, 17813, 17820, 17821, 17851, 17868, 17881, 17886, 18014, 18037, 18443, 18539, 19114, 18023 **1 .**  **HCl CEMS**  **is not p**  **roven t**  **echnology .**  **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 n ot 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 onl y leaves the choice of HCl CEM S . 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 compl y 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 ty pes of instruments currentl y 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 reliabl y demonstrate compliance with the standard. **Comment 8:** Several commenters (17718, 17627, 17715, 18037, 18539) state HCl CEMS currently are not commerciall y 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 or191

an operating parameter limit. The commenters state the fuel anal ys is 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:** Commenter s 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 b y the EPA to establish the HCl standard, and there is no information about HCl emis sions 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, especiall y 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 c ommenters ( 17383, 17724 , 17820 ) are concerned that HCl monitors are not a proven option in the electric utility industry
. According to the commenter s , while these monitors exist and have operated on other sources, the electric utility sector presents distinct challenges. Commenter 17724 questions the need for SO 2 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 accuratel y measure compliance with the proposed standard. **Comment 12:** Several c ommenters ( 17728, 17775 , 17820 ) bel ieve 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 comment ers believe that currently , HCl CEMS are not capable of measuring accuratel y at concentrations below 2 ppm . **Comment 14:** Several c ommenters ( 17775, 17868 , 17820 ) are concerned about the ability of HCl CEMS to accuratel y 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 SO 2 or NO X 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 CEMS192

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 NH 3 interactions with HCl creating problems for dilution sampling systems. The c ommenter also discusses the MCS 100 E Multi Component Analy

zers 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 HC l 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 NO X . Unlike HCl , NO X is not water soluble or temperature dependant prior to anal ys is. The commenter notes their industry has more than 30 years of experience monitoring NO X and limits of 2.0 ppm are challenging to demonstrate on a continuous basis. According to the commenter, measuring a highl y 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 emi ssion reduction measurements produced b y 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 ran ge 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 l imits 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 E PA during the IC R process. No HCl continuous monitors were used to collect any of the data used b y 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 lo ad 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, FT IR 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 approach193

and, as such, does not lend itsel f to daily QA/QC procedures ty

pical 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 analy zers to be stack mounted, which will provide a maintenance and availability challenge. According to the commenter, most anal yz ers 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 NI ST does not have any HCl standards, and the lowest concentration of EPA Protocol HCl gas advertis ed b y 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) anal yz er, 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) s eeking approval for an alternative HCl monitoring procedure through section 63.7 f., 3) monitoring SO 2 continuously as a surrogate for HCl at facilities equipped with wet scrubber control technology for SO 2, and 4) frequent reference method testing. In cluding 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 2 2**  **:** 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 anal yz ers 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, affordabl e option for low level HCl measurement (0

- 10 ppm), they will adopt it more readil y. The EPA should help try to prove this point out over the coming months. **Response to Comment 2 2**  **:** The EPA acknowledges that certain applications of HCl CEMS will require further demonstrations and advances for this technology and is currentl y working on HCl PS for technologies other than FTIR
. **2 . Concerns over**  **l ack of**  **p erformance**  **s pecification**  **. Comment 2**  **3 :**  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
.194

**Comment 2 4**  **:** Commenter 174 02 states the absence of such requirements makes it difficult for regulated units to comment on how they might compl y with the proposed QA/QC specifications in the context of the Utility MACT rule. **Comment 2 5**  **:** 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 reasonabl y be expected to purchase and install HCl CEMS and rely on them for compliance determinations. **Comment 2 6**  **:** Several c ommenters ( 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 sy stems that measure pollutant emissions in units of mass per unit of time. The commenters state the lack of a per formance specification for HCl CEMS (coupled with limited utility HCl CEMS operating experience, particularl y for compliance near the detection limits of the systems) makes it difficult to provide meaningful comments. **Comment 2 7**  **:** Commenter 17729 recommends the EPA should not require compliance monitors for which an EPA performance specification does not exist. **Comment 2 8**  **:** Several c ommenters ( 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 a s the EPA acknowledges in the preamble, PS 15 applies only to FTIR CEMS . PS 6 applies to continuous emission rate monitoring s ys tems ( “ CERM ” ), which measure mass emissions rate per unit of time, not conventional CEMS . The comm enters 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 procur e appropriate instrumentation. The commenters state that in order to provide an HCl CEMS option, the EPA say s “ 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 F R 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 2 9**  **:** Several c ommenters ( 17775, 17795, 17800, 17820 , 17868 ) support the EPA ’ s decision to convene a workgroup of interested stakeholde rs 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 3 1**  **:** 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 3 2**  **:** Commenter 17881 has generally heard that the FTIR technology associated with PS 16 is no t a viable option at this point in time due to concerns about detection limits in EGU exhaust gas1 95

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 earl y a s 1/1/2012, and believes it is highly unlikel y 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 3 3**  **:** 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 currentl y no federal re gulations require the use of HCl CEMS without express exemptions, alternatives and caveats. The commenter provides examples including the Portland Cement NESHAP , CI SWI NSPS and the proposed NESHAP for Poly vinyl Chloride and Copoly

mer 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 F R 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 3 4**  **:** 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 FT IR is not a practical monitoring option, using an HCl CEMS is not a realistic option for companies to co nsider w ithout another option. According to the commenter, therefore many sources would have to revert to either using SO 2 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 ty pical CEMS technician found at a power generation facility . The commenter notes that some states, including Indiana and Pennsylvania, have approv ed 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 3 5**  **:** 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 promul gated. 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 m akes more sense to temporaril y use a preliminary test method already approved for HCl CEMs than to use an already promulgated performance specification that may not appl y. The commenter suggests that the EPA modify the final rule to allow the use of OTM 22 and 23 instead of PS 15.196

**Comment 3 6**  **:** 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 2**  **3 -**  **3 6**  **:** See Response to Comments 1
- 21 under 5A09 of this document
. **3 . Proposed**  **a lternatives**  **. Comment 3**  **7 :**  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 do es not change during the ye ar. The commenter states that i f a new fuel is introduced a new stack test could be required. **Response to Comment 3**  **7 :**  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 b y the commenter
. **Comment 3 8**  **:** 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 3**  **8 :**  Sources may petition for an alternative specification consistent with the provisions of section 63.7. **Comment 3 9**  **:** Commenter 17724 questions the need for SO 2 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 SO 2 monitoring or scrubber parametric monitoring in conjunction with fuel anal ys is as a continuous compliance option, and that the EPA should not categorically create secondary compliance monitoring. **Response to Comment 3**  **9 :**  If an SO 2 CEMS is used consistent with the alternative SO 2 limit included in the rule, no parameter monitoring requirement applies. **Comment 40 :**  Commenter 17715 supports SO 2 as a surrogate for HCl at scrubbed units. **Response to Comment**  **40 :**  The EPA acknowledges the commenter ’ s support. **Comment 4 1**  **:** 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 4**  **1 :**  The final rule eliminates the fuel sampling option. A source may use an SO 2 CEMS where an FGD is installed, may use HCl CEMS , or may

conduct periodic testing to demonstrate compliance.197

**Comment 4 2**  **:** 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 CF R 63.8(f). **Response to Comment 4**  **2 :**  The EPA has set forth PS 15, which uses a Fourier Transform Infrared (FTIR) anal yz er 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 4 3**  **:** 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 b y the time EGUs need to make decisions about their compliance options. **Response to Comment 4**  **3 :**  See resp onse to Comment 4 2 , directly above. **Comment 4 4**  **:** 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 CO 2 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 woul d require multipass measurement cells to achieve sufficient path length for the required sensitivity . Currently , states the commenter, the onl y installation on a U.S
. EGU is an in situ TDL on a dry

stack, and in that application, there was sufficient inten sity 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 likel y 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 p erformance specification. **Comment 4 5**  **:** 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 t echnologies such as Tunable Diode Laser Spectroscopy ( TDL S ) and Ion Mobility Spectroscop y ( IMS ) are showing great promise as a suitable replacement for selective gas components such as HCl and HF
.198

**Response to Comments 4**  **4 -**  **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 recommend s 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 4 7**  **:** 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 SO 2 limit, if a unit uses a CEMS device to demonstrate compliance with SO 2 limits. A ccording to the commenter, a s drafted, proposed section 63.9991(a)(1)(i) limits the units that can comply with an alternative SO 2 limit to those that have “wet or dry FGD technology

installed on the unit. ” **Response to Comments 4 6**  **- 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 ty pe of deliberate violation of the regulations is considered unlikel y 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 SO 2 alternate equivalent standard option where that applies. **5 . Additional**  **c oncerns**  **. Comment 4**  **8 :**  Commenter 16513 notes that PSEG Bridgeport Harbor 3 is required to compl y with the SO 2 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. A s a result, states the commenter, PSEG Bridgeport Harbor 3 currentl y meets the Utility NESHAP ’ s SO 2 limit of 0.20 lb/MMBtu for coal

fired 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**  **4 8**  **:** The use of the SO 2 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 SO 2 ensures proper operation of the control device. Inthe situation described, without an FGD installed, the unit would not qualify for the SO 2 alternate equivalent standard and must meet the HCl limit. The source can demonstrate compliance using an HCl CEMS or periodic HCl testing.199

**Comment 4 9**  **:** 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 controll ed by pass stacks. The commenter identifies a facility that is currentl y 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 by pass stack. According to the commenter, within the proposed language of 40 CFR 63.10010(a)(4), it appears the facility ’ s by pass stack would be required to install similar monitoring systems as the main common stack, but without FGD technology on the by pass stack, it appears that the current 40 CFR p art 75 SO 2 CEMS located on the by pass 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 apparentl y 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 4**  **9 :**  The EPA has modified the requirements for monitoring a by pass stack. Under the final rule, the installation of a monitor on a by pass stack is not required. **Comment 50**  **:** Commenter 17881 suggests section 63.10011 (b)(1), relating to es tablishment of a maximum chlorine fuel input, should only appl y to units which are not complying with the SO 2 surrogate or are not rel yi ng on an HCl CEMS
. **Response to Comment**  **50 :**  Under the final rule, no fuel input operating limits apply
. The source may b e required to conduct a new performance test where there is a significant change in fuel use that could result in emission increases. **Comment 5 1**  **:** 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 rel y on unproven HCl CEMS, that HCl CEMS are not commerciall y 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 5 1**  **:** The agency disagree s 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 g as 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.200

**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, 178 56, 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 CEM**  S
. **Comment 1:** Several c ommenters (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 p art 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 SO 2 , 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 appli cations 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 m etals 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 requirem ents in PS 11. **2 . Opposition**  **ba sed on**  **t esting**  **r equirements**  **. 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 p art 75 conditionall y valid data (for SO 2 , CO 2 , O 2 , or flow monitors) fo r EGU MACT recordkeeping and reporting purposes.201

According to the commenter, a clearer approach would allow quality

- assured data from a CEMS certified and operated in accordance to 40 CFR p art 75 to be used for compliance with the exception of bias

- adjuste d 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 p art 75 are applied for purposes of compl ying with these standards. **3 . Opposition**  **b ased on**  **l imitations to the**  **t echnologies**  **. 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 con ditions 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 rel y on a set maximum limit over 30 days as the proposed limit. According to the commenter, Hg anal yz er performance has been so unpredictable that utility companies that have cont inued 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 NI ST Traceability protocols, and early elemental Hg Vendor Prime calib rator 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 legall y available. Sorb ent trap monitoring is allowed if a source owner or operator chooses to use that monitoring option. The interim NI ST traceability protocols have been publicall y released and represent the results of a collaborative process for establishing protocols amongs t 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 hy bridized 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 P M 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 fo r 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 technology202

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 lo w 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 re quirement 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 additi onal 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 . Th e commenter states that currentl y 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 SO 2 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 SO 2 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 1 2**  **:** Commenter 17757 states that there is no effectiv e 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 limited203

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. A ccording to the commenters, a properl y i nstalled and calibrated CEMS should suffice. Clarification on this point is necessary . **Comment 1 3**  **:** 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 1 4**  **:** Commenters 17800 and 17902 state that while CEMS for Hg and PM are available commerciall y, 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 ty pical SO 2 or NO X CEMS . According to the commenters, f urther 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**  **- 1**  **4 :**  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 SO 2 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 document on those issues. **4 . Opposition**  **b ased on**  **o perating**  **l imit**  **r equirements**  **. Comment 1**  **5 :**  Numerous c ommenters (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 reduc e 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 b eing controlled through a surrogate because such tests are redundant and unnecessary

for compliance with the proposed utility MACT
. **Comment 1 6**  **:** Commenters 19120 and 17881 request clarification of the applicability of monitoring and operating limits to unit s using CEMS for compliance monitoring. **Comment 1 7**  **:** Several c ommenters (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 to ol, with the HCl limit using HCl CEMS or an SO 2 CEMS for ongoing compliance, or with the Hg limit using a Hg CEMS or a sorbent trap s ys tem to also comply with an operating load limit or with control device operating parameter limits for PM, HCl , or Hg controls.204

**Comment 1 8**  **:** 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 1 9**  **:** Multiple c ommenters (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 co ntinuously

measured by

a CEMS
. **Comment 2**  **1:** Commenter 18023 proposes that operating limits should be a trigger for maintenance or inspection only
. **Comment 2 2**  **:** 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 2 3**  **:** Commenter 17 928 states that stack testing is unnecessary to assure compliance if a unit installs or uses CEMS
. **Response to Comments 1 5**  **- 2**  **3 :**  The final rule clarifies that where a CEMS is used for a given pollutant (including an alternate equivalent standard in the cas e of SO 2 ) 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 oil

fired units , the remaining fuel anal ys is, operating limit an d 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 s ection 5A05 in this document. As noted elsewhere, no operating parameter requirements appl y when a CEMS is used to demonstrate compliance for an applicable pollutant. **5 . Opposition**  **b ased on**  **a veraging**  **t im**  **es .**  **Comment 2 4**  **:** 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 op erating days. According to the commenter, i f compliance is based on dail y periods rather than hourly

periods, a single (abnormall y high or low) hourl y measurement could be the basis of a daily period that could improperl y bias the resulting 30

- day average. The commenter states that u sing hourly averages as the basis fo r the 30

- day boiler operating day

rolling averages removes the potential for skewed results from day s containing onl y a few unit operating hours and consequentl y yi elds representative emission rates for the 30

- day compliance demonstration period.205

**Comment 2 6**  **:** Commenter 17740 does not support compliance demonstration with the tested average PM value using a 30

- boiler operating day PM average. **Comment 2 7**  **:** 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 2 4**  **- 2**  **7 :**  The final rule maintains the 30

- day rolling average using hourl y values (unless a source chooses to apply emissions averaging of Hg emissions for multiple units in the EGUs designed for coal ≥ 8,300 Btu/lb subcategory)
. This averaging period enables short

- term variability to be averaged out, and this averaging period is consistent with the periods already used in subpart Da of the NSPS. Sources are required to monitor during all operating periods when continuous monitoring is used to demonstrate compliance. See the preamble for discussion of alternative averaging times. **6 . Opposition**  **b ased on**  **b ias**  **a djustments**  **. Comment 2**  **8 :**  Several c ommenters (17881, 17796, 18023 ) supp ort eliminating the bias adjustment for mercury , HCl , and PM CEMS since it is believed that bias adjustment of data has onl y been utilized with trading s ys tem based rules where mass emissions are being totaled
. **Comment 2 9**  **:** 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 2 8**  **- 30**  **:** There is no bias adjustment factor applied for purposes of this rule. **7 . Opposition**  **b ased on**  **c om** **pliance r**  **equirements .**  **Comment 31**  **:** Commenter 16849 disagrees with the EPA about the ability of Hg CEMS to reach compliance within the first 30 day s of operation. According to the commenter, w ith the needed adjustments and repairs to Hg CEMS and the additional operation of multiple control devices, p lant 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 after the effective date o f the final rule. Such an extended period provides ample opportunity for the typ es of adjustments suggested b y the commenter
. For new units, the rule likewise provides up to 180 days for demonstrating initial compliance. **Comment 3 2**  **:** Commenter 17716 disagre es with the EPA about showing on

- going compliance b y combining CEMS data with non - CEMS data to demonstrate compliance. **Response to Comment 3 2**  **:** 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.206

**Comment 3 3**  **:** 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 s ys tems 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 complianc e 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 SO 2 CEMS , or wi th the Hg limit using Hg CEMS or a sorbent trap s ys tem to also comply with fuel input limits for metals, chlorine or Hg. **Response to Comment 3 3**  **:** The comments are moot because the rule no longer requires fuel anal ysis or operating limits. **Comment 3 4**  **:** Commenter 17775 notes that the EPA does not propose separate continuous compliance requirements for HF CEMS
. **Response to Comment 3 4**  **:** Section 63.10010(d) addresses operating requirements for HF CEMS
. **Comment 3 5**  **:** Several c ommenters (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 comm enters, 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 3 5**  **:** 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 flexib ility 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 3 6**  **:** 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 3 6**  **:** The comments are moot because the rule no longer requires fuel anal ysis or operating limits. **Comment 3 7**  **:** 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 determination. The commenter states that the uncertainty associated with the use of these technologies further illustrat es 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 anal ys is, emission207

control monitoring, and the installation of CEMS , to provide sufficient assurance that actual emissions limits are being met. **Response to Comment 3 7**  **:** 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 3 8**  **:** Commenter 17881 states that the EPA needs to clarify whether fuel anal ys is 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 3 8**  **:** The comments are moot because the rule no longer requires fuel anal ysis or operating limits. **8 . Opposition**  **b ased on**  **monitoring r equirements**  **. Comment 3**  **9 :**  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 justificati on 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 EPA
HQ
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- 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 expensiv e relative to traditional CEMS calibration gases . According to the commenter, lowest available concentrations are significantl y higher than proposed limits. Commenter 17758 recommends that the EPA allow use of SO 2 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 parameter s 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
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- 0234. **Response to Comments 3 9**  **- 41**  **:** As stated elsewhere in response to more detailed comments, source owners or operators who use CEMS to demonstrate continuous compliance are not req uired 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 SO 2 CEMS instead of an208

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 4 2**  **:** Commenters 17716 and 18449 state that section 63.10021(a)(10)(ii) does not include a reference to CO 2 contrary to the requirements in section 63.10010(b) which allow the use of O 2 or CO 2 . According to the commenters, the majority of Part 75 affected coal

- fired units utilize dilution

extractive CEMS which are equipped with CO 2 analyzers, and dilution

- extractive CEMS cannot measure O 2 as a diluent
. **Response to Comment 4 2**  **:** The final rule addresses this oversight. **Comment 4 3**  **:** 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 determinati on of exhaust gas moisture content in 40 CFR p art 75 , section 75.11(b)(1). **Response to Comment 4 3**  **:** 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 unit

specific default in those cases. **Comment 4 4**  **:** Commenters 17881 and 19114 state that the proposed regulation referring to “ fuel

specific CO 2 concentration ” in section 63.10005(l) has following flaws:
a. According to the commenters, the proposed rule does not contain any such default CO 2 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 CO 2 concentration ” based upon the equivalent O 2 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 s hutdown (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. **Comment 4 5**  **:** 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,209

s uch additional monitoring is redundant and creates an unnecessary burden on these sources and as such should be removed from the r ule. **Response to Comment 4 5**  : The EPA agrees, and the final rule clarifies this approach. **9 . Opposition**  **b ased on QA/QC**  **r equirements**  **. Comment 4**  **6 :**  Several c ommenters (17716, 17881, 18014) state that the O 2 and CO 2 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
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- 0234. According to the commenters, the following text should be added to Table 5 of the docket entry EPA
- HQ
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2009
- 0234, as applicable: “Alternativel y, for an affected source that is also subject to the O 2 or CO 2 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 O 2 or CO 2 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 4 6**  **:** The final rule includes language comparable to the requested language for an O 2 or CO 2 CEMS
. For the SO 2 CEMS , see responses to similar comments under 5A08 of this document
. **Comment 4 7**  **:** Commenter 17716 disagrees with the EPA about additional QA/QC requirements for use of SO 2 CEMS . The commenter states that although use of S O 2 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 SO 2 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 ye ars, the benefit to this requirement is not apparent. **Response to Com ment 4**  **7 :**  This requirement has been removed in the final rule based on 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 4 8**  **:** 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 r ules, 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 cos ts with no evidence of any benefit. **Response to Comment 4 8**  **:** The EPA has attempted to harmonize the CEMS requirements under this rule primaril y with the Part 75 CEMS requirements that already appl y to most of the affected EGUs under this rule. **10 . Oppositi**  **on b**  **ased on s**  **ampling .**  **Comment 4 9**  **:** 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 boiler, just downstream of the combustion process, is not an appropriate location where a “representative210

sample ” can be collected. Commenter 17316 recommends that “representative samples ” should be obtained by

locatin g 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 iss ues 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 rel ying on surrogates for compliance demonstration. **Response to Comments 4 9**  **- 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 5 2**  **:** 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 anal ys is requirements. **Response to Comment 5 2**  **:** This comment is moot because the fuel anal ysis requirements are not included in the final rule. **Comment 5 3**  **:** 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 equipm ent); 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 Comme nt 5**  **3 :**  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**  **c larification on**  **o perational**  **l imitations**  **. Comment 5**  **4 :**  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 requirements in Table 4 of part 63 subpart UUUUU are unnecessary , requiring unneeded record keeping211

that does not improve compliance and should be eliminated from this rule. The commenter states that if the unit chooses to install and properl y 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 s ys tems 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 5 4**  **:** Where a CEMS is used, EPA largel y 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 p art of the QA requirements in PS 11. **12 . Requirements for**  **b ypass**  **s tacks**  **. Comment 5**  **5 :**  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 by pass stacks. The commenter states that within the proposed language of section 63.10010(a)(4), it appears that a by pass stack would be required to install similar monitoring s ys tems as the main common stack. According to the commenter, without flue grade sulphurization technology on the by pass stack, it appears that the current 40 CFR Part 75 SO 2 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 5 6**  **:** Commenters 17772 and 17873 state that PM CEMS do not operate properl y 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 by pass 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 occasionall y flow through by pass stacks, the EPA should develop work place standards that would put parameters around how often and when b ypass stacks can be emplo yed. **Comment 57 :**  Commenter 17781 states that the periods of EGU startup and shutdown resulting in FGD by

pass, as well as reasonable periods of FGD malfunction which are addressed in an appropriate manner, should not disqualify an EGU from using the SO 2 surrogate for HCl
.212

**Response to Comments 55 -**  **57:** The final rule provides an option to monitor a b ypass stack or to treat any hour in which the unit by passes 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 b ypass operations. **13 . Opposition based on**  **m aintenance**  **r equirements**  **. Comment 5**  **8 :**  Commenters 17775 and 17800 state that the EPA did not account for the fact that EGUs need to perform maintenance, in addition to re quired QA/QC, in order to keep monitoring systems running properl y. 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 period s ” from operating requirements. **Response to Comment 5 8**  **:** 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**  **c larification on**  **m onitoring,**  **r ecordkeeping and**  **r eporting**  **r equirements**  **. Comment 5**  **9 :**  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, f

acilities which use CEMS for monitoring of a regulated pol lutant or surrogate should not require fuel sampling, parameter monitoring, or compliance with fuel or operational limits. **Response to Comment 5 9**  **:** 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 SO 2/ 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 cor rected 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 SO 2 , CO 2 , O 2 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 P art 75 procedures for the CEMS and sorbent trap monitoring systems used to compl y with this rule, including the use of the conditionally valid data procedures. **15 . Lack of**  **v ariability**  **.**213

**Comment 6 2**  **:** 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 b y 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 6 2**  **:** 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 s ys tem, and the HCl CEMS, the EPA disagrees. This issue is discussed in more detail in the comment sections directly related to Hg CEMS and HCl CEMS. **16. Missin g i**  **nformation .**  **Comment 6 3**  **:** 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 6 3**  **:** There is no requirement to calculate PM mass emissi ons; 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 . Recommendatio**  **ns .**  **Comment 6 4**  **:** 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 SO 2 monitoring as a surrogate for acid gas HAP be included as an option for IGCCs as it is for other categories that have SO 2 data available. **Comment 67 :**  Commenter 17197 recommends that a footnote be added to Table 5 of the docket entry EPA
- HQ
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- 0234 that states “ Dail y calculate a new 30

- boiler operating day rolling average of all of the hourl y CEMs emissions data for the preceding 30

- boiler operating days. ” **Comment 68 :**  Commenter 17265 is requesting clarification of whether CEMS are warranted across

- the

board 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

an d accuracy

of the data.214

**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 alternativ e 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
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- 0234 and strongl y 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 l imits, 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, w ithout 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 C FR 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.215

**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 anal ys is for liquid oil

- f ired 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 s ys tem. **Comment 82 :**  Commenter 17775 recommends that the EPA should eliminate the redundancy between section 63.10010(a)(4) and Appendix A section 2. **Comme nt 83**  **:** Commenter 17775 recommends that the EPA include provisions similar to 40 CFR Part 75 that allow EGUs that are otherwise usin g CEMS to report a site

- specific default value during b yp ass in lieu of installing and maintaining CEMS on the by pass stack. **Comment 84 :**  Commenter 17776 recommends that the EPA should revise the requirement to use PM CEMS for demonstrating continuous compl iance with the total PM limit. PM CEMS can only anal yz e 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. **Co mment 86**  **:** Several c ommenters (17725, 17820, 18014, 19033) recommend that section 63.10010(b)(5) should be revised to include CO 2 , f or example, “the average of all of the hourl y ox yg en 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 CO 2 records. **Comment 8 7**  **:** Commenters (17718, 18037, 18539) recommend that performance testing should be conducted annually

for each of the stacks instead of every other month as currentl y 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 sh ould 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 O 2 (and CO 2 ) emissions. O 2 (and CO 2 ) concentration dat a are ty

picall y 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 from216

long

- term O 2 or CO 2 averages and long

- term SO 2 or NO X 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 fl ow 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 9**  **1 :**  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 6 4**  **- 9**  **1 :**  The EPA has considered all of these various recommendations in finalizing the proposed monitoring requirements. Ingeneral, the final rule builds on the proposed requirements b y 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 h as 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**  **c larifications of**  **r ule**  **. Comment 9**  **2 :**  Commenters 17718 and 17881 request that the EPA clarify when the 30

- day

operating period begins if the s ys tems are already certified (e.g., current SO 2 or PM CEMS being used for 40 CFR Part 75 and/or 40 CFR Part 60 monitoring programs). **Response to Comment 9 2**  **:** 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 9 3**  **:** Commenter 17718 states that the EPA should clarify whether initial testing of the b yp ass emissions needs to be tested within the 180

- day timeframe described in the proposed language and that alternativel y, setting a firm testing timeframe on bypass stack emissions seems overl y burdensome. Ac cording to the commenter, creating emissions (and incurring costs) b y s witching a unit into b ypass mode that would not otherwise have been used simply in order to perform emission testing appears to create unnecessary

burden. **Response to Comment 9 3**  **:** Under the final rule, you may elect to monitor the by

pass stack or treat hours in which the b ypass is used as monitor downtime. The EGU owner or operator remains subject to the 30 boiler operating day rolling average during by pass operations
. To report data from any217

monitoring on a b ypass stack, you do need to have a certified monitoring s ystem. 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 9 4**  **:** 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 O 2 or the corresponding fuel

- specific CO 2 concentration ” are to be us ed 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 CO 2 concentration. ” **Response to Comment 9 4**  **:** Becau se of the revisions related to startup and shutdown provisions, the cited language is no longer applicable. **Comment 9 5**  **:** Commenter 17820 cites that Table 8 states that the source is to convert “hourl y 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 hourl y particulate emiss ions data for the preceding 30 boiler operating days. ” The commenter states that this requirement needs to be clarified. **Response to Comment 9 5**  **:** The referenced language in the proposed rule is not used in the final rule. Provisions in Appendix A and Appen dix B to the final rule describe the procedure for calculating 30

- day averages where an Hg CEMS, sorbent trap monitoring s ys tem, or HCl CEMS are used for compliance. Overall, the language in the final rule ensures a uniform approach for calculating average s from CEMS data and from a PM CPMS.218

**5A11 -**  **Testing/Monitoring: Disable bias tests for Hg, HCl, and PM CEMS Commenters**  : 17718, 17740, 17816, 17820, 17873, 17877, 17881, 17909 **1 . Support for**  **e liminating**  **b ias**  **t ests**  **. Comment 1:**  Multiple c ommenters (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 b ias 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**  **b ias**  **t est**  **c omments**  **. Comment 4:**  Commenter 17881 states that the proposed EGU MACT rule appe ars to be silent on the concept of whether SO 2 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 C ode 5A12.219

**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**  **n o**  **n eed for**  **m issing**  **d ata**  **s ubstitution**  **. Comment 1:**  S everal c ommenters ( 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 on

going 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**  **m issing**  **d ata**  **s ubstitution**  **. Comment 3:**  Commenter 17620 suggests that sources should be required to infer emissions during monitor downtime at the highest dail y 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 substituti on is essential to properl y account for all mass emissions for the pollutant in question, but for the proposed rule, compliance with HAP emissions limitations takes place over a relativel y long period of time. The commenter ’ s opinion is that it is appropri ate 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 applica ble 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 c ommenters ( 17316, 17821, 17881 ) state that there are conditions other than those listed in section 63.10020(b) that are legitimate reasons for monitoring s ys tem 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 recovery220

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 s ys tem availability

or monitor downtime. The commenter states that this is because: (1) Hg monitor repairs take much longer to recover and settle once the s ys tem is returned to service than current CEMS anal yz ers for NO X and SO 2 , (2) QA/QC activities take longer to perform, especially with the required calibrator checks, and (3) the s orbent trap versus continuous moni tor issue is almost an apples to oranges argument regarding availability

with missing day s/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 availab ility

should be calculated and recorded for tracking purposes but penalties should not be associated with them, especiall y with the limited experience performing QA/QC with these devices. **Comment 8**  **:** Commenter 18023 states that under section 6.1.3 Data Red uction 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 6 3.10020(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 relativel y 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 s ys tem 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 day s of the averag ing 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 b y exceptions allowed in the final rule. On the issue of appl ying a data substi tution 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 monito ring 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 o r 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 s uch gaps are deviations from the rule but such gaps can lead to uncertainty about compliance status.221

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.222

**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, fluo rine 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 c onstant, so long as any add
- on controls are operating properl y, it would seem reasonable and appropriate to proportion up the HAP content of the fuel combusted during performance testing, b y 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 analy sis or operating limits based on non

- Hg metals content of fuel. The onl y fuel monitoring provision in the final rule is an option for liquid fuel units to use fuel moisture monitoring. If yo u combust liquid fuels and yo u wish to demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel moisture content of fuel in place of quarterl y 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 anal ys is for each ty pe of fuel burned. ” The commenter notes that oil is a homogeneous fuel that is relativel y consistent (from shipment to shipment), and therefore such frequent fuel sampling and anal ys is for oil

- fired EGUs is not warranted. **Comment 3:** Commenter 17316 states that the monthly fuel anal ys is required in section 63.10006(s) contradicts the discussion of this topic in the preamble (FR page 25053 c olumn1 ) which specifies that (after the initial compliance demonstration b y fuel anal ys is)], the EPA “ is proposing a source be required to recalculate the fuel pollutant content only if it burns a ne w fuel ty

pe or fuel mixture. ” The commenter is concerned that this requirement is unjustified for sites that receive oil deliveries less frequentl y than monthl y. 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.223

**Response to Comments 2 -**  **3:** Much of these comments are moot because the rule no longer requires fuel sampl ing; however, the agency agrees that fuel moisture sampling (if that option is selected by a source) need onl y occur on delivery of a new shipment of fuel oil. **Comment 4:** Commenter 17870 asks for clarification of the rule allowing fuel anal ys es to demonstr ate 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 perfor m 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 lim its separately

or in combination based on fuel anal ys is rather than performance stack testing, upon request b y 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 an d operating limits based on those fuel anal ys es , 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 limi ted 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 emission s performance. In addition, if an EGU has an oil

- fired capacity factor of less than 8 percent evaluated on a 24 month block average , then the onl y 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 re sponses to operating parameter monitoring under Comment Code 5A06 in this document.224

**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, 1787 3, 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**  **c oncerned**  **a bout the**  **p roposed**  **fre quency of p**  **erformance t**  **ests .**  **Comment 1:** Numerous c ommenters (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 and 17804 state that the r ule would significantly

increase the workload of state agencies b y 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 biannuall y. . **Comment 3** : Several c ommenters (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 b elieves 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 fairl y consistent despite potential variability in fuels and operations. Commenter 17402 believes that annual Method 29 stack testing combined with existing permit requirements (to properl y 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 bi

monthly testing requirements will force dual. The commenter states that f irst, 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 pe riods of high electric demand. According to the commenter, m onthly testing would result in significant economic burdens. For example, commenter 17803 ’ s cost of the uneconomic oil consumed during the 2010 IC R testing last year was approximately $2

- 3 million. Second, states the225

commenter, inflexible testing schedules may induce units to run solely for testing purposes, l eading to increased emissions. Acco rding 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 environmentall y 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 c ommenters (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 oil

fired 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 b y 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 c ommenters (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 h as 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 c ommenters (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 multip le 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 relativel y 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 t ests 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 significantl y higher than in the continental U.S. and that the commenter paid a 20 percent premium to perform the ICR testing.226

**Comment 9:** Several c ommenters (17760, 17881, 18477) note that annual testing would be consistent with the industrial boiler MACT ( DDDDD ), stationary combustion turbine MACT (YYYY), and the RI CE 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 ye ar are too cold. According to the commenters, severe we ather 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 frequentl y 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, quarterl y 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 unnecessari ly repeating testing of the same conditions. **Comment 11:** Commenter 18502 recommends that the EPA reduce the compliance testing requirements based on the relativel y small size and emissions and remoteness of non

- continental EGUs burning liquid oil. **Response to Comments 1**  **- 11**  : Inresponse 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 w ith an annual oil

- fired capacity factor of less than 8 percent. These units are subject onl y t o the performance tune

- up work practice standard in the final rule
. Second, the optional periodic testing requirements have been made consistent between controlle d and uncontrolled sources, with a reduced frequency of quarterl y 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:** Comm enter 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 compl ying with Hg, HCl or SO 2 CEMs. For sources electing to use PM CPMS, the performance testing frequency has been reduced to annual testing. **Comment 13:** Multiple c ommenters (17638, 17681, 17690, 17716, 17725, 155, 156, 17758, 17760, 17803, 17820, 17870, 179 02, 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 frequentl y than onc e 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 of227

quarterl y performance testing. In addition, the final rule has removed all requirements f or duplicative testing of a HAP and a separate alternate equivalent standard (such as filterable PM and HAP metals). **Comment 14** : Multiple c ommenters (17716, 17725, 155, 17820, 18498, 17775, 17800) request that the testing provisions in the final rule incor porate a grace period simi lar 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 final rule allows for testing grace periods consistent with those allowed in part 75. **Comment 15:** Several c ommenters (17716, 17821, 17881) state that the speci fic testing deadlines that are provided in section 63.10006(n) will be overl y 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 provid e 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 recommen ds 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 specificall y 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 previousl y explained, the optional periodic testing requirements have been made consistent between controlled and uncontrolled sources, with a reduced frequency of quarterl y 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 fisc al 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 quarterl y in the second year, and biannual the third year if HCl emissions are measured to be non

- detectable for all tests conducted. Accordingl y, 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 SO 2 CEMS, as the bi

- monthly performance tests are not required for continuously

monitored surrogates.228

**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 frequ ent, 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 gen erating 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 alternativ e 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 proc edures and operating parameters are established, compliance will be assured b y 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 b y 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 H Cl
. **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 ye ar 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 pu blished data for 2008, 2009, and 2010 shows at least 34 residual oil

- fired units whose 3

- ye ar annual capacity factors are 5 percent or less. **Comment 23:** Several c ommenters (17316, 17870, 18428) state that oil is a homogeneous and reasonabl y 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 anal ys is 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 annuall y. ” However, there is no reference to this annual testing in the proposed rule. Given the229

extremely low level o f 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 significantl y and annual testing should be sufficient for monitoring the non

- Hg metals. **Comment 25:** Several c ommenters (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 s ys tems are required to complete stack test less frequentl y than units with add

- on control systems, but for units without add

- on control s ys tems, the emissions of HCl , HF, and non

- Hg metals are most closely

tied to fue l 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. Comment er 17402 provides suggested revisions to proposed section 63.10006 and section 63.10021 outlining a methodology for using monthly

fuel anal yses 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 closel y 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 quarterl y basis to allow more substantial analysis of gathered data and to reduce potential burdens resulting from more frequent laboratory anal ys es and test report submittals. **Comment 27:** Commenter 17737 states that a monthly testing frequency

is unmanageable for units that do not have SO 2 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 SO 2 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 ty pe of fuel being burned and to perform monthl y fuel anal ys es 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 p roposed section 63.10006(t) because historically , testing firms and labs have not handled the high volumes of work implicit in this compliance option.230

**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 n otes 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 ye ars, then frequenc y is relaxed to every 3 ye ars.  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 (CI SW I 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 (CI SWI 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 unnecessaril y 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 c ommenters (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 t o 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.231

**General Response to Comments 1 -**  **34:** For stack test frequency , the EPA has modified the final rule to require quarterl y 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 onl y for the emis sion limit that the source is compl ying 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**  **t esting**  **s ection 63.10006(j)**  **. Comment 35**  : Commenter 17821 request s 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 SO 2 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 SO 2 CEMS as an alternative to an HCl CEMS , the commenter recommends that the EPA sh ould 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 sSO 2 monitor and a reduced SO 2 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 SO 2 )
. 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 p otential 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

oth er 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 anal ys is 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 wis h to demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel moisture content of each shipment of fuel in place of quarterl y stack testing, you may develop a unit

- specific approach utilizing fuel moisture content measurements, col lect 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 anal ys is as a compliance option. However, if you combust l iquid 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 quarterl y stack testing, you may develop a unit

- specific approach utilizing232

fuel moisture co ntent 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**  **f**

**requency c**  **riteria .**  **Comment 38:** Commenter 17821 states that the red uced 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 relativel y short

- term periods. In the real operating world, states the commenter, a unit will simply not continue to operate in worst

- case co nditions, 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 s tates “ 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 ov er 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 frequenc y. 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 quarterl y 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 n o reason for this restriction. According to the commenters, the EPA has not p rovided 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 ty pical detection limit would meet these criteria. In addition, the quarterl y periodic performance testing is an option for sources choosing to not install CEMS or PM CPMS
. **Comment 41:** Commenters 17881 and 19033 state that s ection 63.10006(q) is unclear. According to the commenters, i t seems the intent is to require that the more frequent testing frequencies must be met if a233

performance test shows emi ssions greater than 50 % of an allowable limit, yet the increased testing frequency is required until all performance tests over a consecutive 3

- ye ar period show compliance. **Response to Comment 41 :**  The reduced frequency option is only

available to sources that meet the 50 % criteria during the 3 ye ars 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 th e previous performance test. The commenter states that in order to qualify for this reduced testing frequency , 3 consecutive ye ars of testing must show that emissions are at or below 50 % of the applicable emission limit. In light of the very

stringent emis sion 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. Al so, 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 RI CE MACT utilizes this concept in that after compliance is demonstrated for two consecutive semi

- annual tests, the testing frequency can be reduced to annual ly
. 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 c ommenter s ( 19536 , 19537 , 19538 ) assert 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 highl y 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 yi elded from a test. For new sources, s tates 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 anal ys is (or lack thereof) there are no operational methods available to reduce that variability . Given th e 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:** We believe that frequency of testing be tied to source performance and be reduced based on demonstration of continued lower emissions, not on potential emissions variability
. The EPA believes the provisions of the LEE exemption provide adequate a level of assurance with compliance for better perform ing units . For non Hg HAP, the sources must show levels below the threshold for quarterl y performance tests over a 3

- ye ar period. In addition, any change to the process that would result in an increase in HAP emissions would necessitate another performance test. These234

sources will also be subject to other rules containing provisions for parameter monitoring as discussed in section 5A05. **Comment 44:** Commenter 17718 requests that the final rule include a clarification to the proposed language at section 63.10 006(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 successfull y 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**  **r elated to**  **“ h**  **ighest c**  **ontent ”**  **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 reasonabl y possible in part due to natural variability . According to the commenters, there is a very real possibili ty

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 th e 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 p rocuring 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 perform ance tests/fuel sampling and anal ys is simply due to fuel variability

alone (and not a change in fuel ty pe(s) or blends). **Comment 46:** Commenter 17718 states that the proposed regulatory language (40 CFR 63.10007(c)) provides that performance tests must be c onducted “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 “ty pe of fuel ” simply

means that if bituminous coal is ty picall y 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 4 5**  **- 48**  **:** Periodic performance test s 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. If235

the source is unsure which fuel would result in the highest HAP loading, they may perform multiple tests within th at test period or opt to use CEMS to ensure continuous compliance with the standard. **5 . Testing**  **d eadlines**  **. 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**  **r egarding**  **p erformance**  **t esting and**  **m aximum**  **o per**  **a ting**  **l oad**  **. 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 day s. According to the commenter s , 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 1 7881 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 b y 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 th at the EPA develop a compliance option that represents normal operation of a facility and eliminate testing in modes of operation that are rarel y or never utilized.236

**Comment 54:** Commenter 18444 states that the EPA should require that states set maximum allo wable 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 tes ted infrequentl y (such as particulate HAP ). The commenter notes that the proposed rule language on maintaining heat input within 10 percent of the heat 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 p ercent 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 burn ed, 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 s ection 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

appl y 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 b y the EPA in 40 CFR 63, subpart ZZZZ

– NESHAP for RI CE. 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 catal ys ts) only

applie s 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 appl ying 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 NO X emissions. Essentially , states the commenter, stack testing is conducted to establish a relationship between NO X lb/MMBtu emission rates and unit load; prior to conducting the stack testing , four parameters indicative of NO X emissions, along237

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 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 t o 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 conducte d, 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. A s an example, states the commenter, the commenter enjo ys high availability due to redundancy

of s ys tems. 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 f or 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 incredibl y arduous and costly
. **Response to Comments 50 -**  **60:** We agree with commenters on the need for the regulation to define more clearl y 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 SO 2 ) 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 performanc e testing in lieu of continuous monitoring. In such cases, the rule will specify that the unit be operated at maximum normal238

operating load conditions during each periodic ( e.g ., quarterl y) performance test period. As noted above, actual maximum normal operating load for a particular facility is unit dependent but we expect it will be generall y between 90 and 110 percent of design capacity. Maintaining this high load operating condition 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 . SO**  **2 CEMS**  **i ssues**  **. a**  **. Comments r**  **elated to LEE ( t**  **esting/ m**  **onitoring) .**  **Comment 61:** Commenter 17800 states that in proposed section 63.10021(a)(11)(iv) and (v), the EPA proposes to require source s using PM CEMS to report “performance test data, except opacity data” and “relative accuracy

test audit data” electronicall y using ERT starting January 1, 2012 (FR Vol.76 , No. 85, p. 25,117) and section also requires the reporting of “performance test dat a, 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 anal ys is and therefore LEEs have no monitoring s ys tems 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 egregiousl y costly because they

would require stack testing company to sample for 28

- 30 days using Method 30B. 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 strongl y suggests the EPA revisit this portion of the proposed rul e 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 day s 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 appl y to LEEs
. The commenter states that they should not.239

**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. **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 c ommenters (17808, 17870, 18025, 18031) support the LEE approach but recommend continuous compliance methods the commenters feel are less burdensome. Comm enters 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 ye ar. If a LEE unit exceeds LEE limits, commenters propose that it revert back to more frequent performance tests (e.g., quarterl y, 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 b y this commenter. If a unit qualifies as an LEE for Hg, then annual testing is the only ongoing requirement. However, if the uni t 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 s ys tem. Specific testing requirements will appl y i n the interim prior to the CEMS or sorbent trap monitoring s ys tem being certified. **Comment 67:** Several c ommenters (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 st andards. 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. C **omment 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.240

**Response to C omments 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, the source can switch to testing onc e per ye ar for that pollutant but must revert to quarterl y 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 quarterl y testing. **8 . LEE A** **pplicability 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 appl y 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 c oal 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 90 th percentile Hg would set an effective Hg emission limit that i s likely less than 10 lb/year. According to the commenter, this is an unnecessaril y 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 anal ys is 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 app licable limit or less than 22 lb /year. In contrast, states the commenter, in calculating the241

Hg MACT floor, the EPA asserts that even the best performing units can reasonabl y expect ye ar- overye ar stack test results to vary by a factor of 50 because of statistical variability, operational variability , measuring s ys tem variability and variability

in fuel. The commenter states it is convinced that year- overye ar 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. Sh ould 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 perform ance test repeated annually , that documents emissions are less than 10% of the standard or less than 2 9 lb/ye ar. If results from a single test are above that threshold, the source will have to use Hg CEMS or a sorbent trap monitoring s ys tem. 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 c onfidently

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 technicall y capable of demonstrating emissions at the LEE threshold. In addition, the mass alternative pro vides 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 a genc y 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 c ommenters (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 anal ys es so long as the fuel supplier does not change. A ccording 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 hi ghly unlikel y to show emissions that would exceed the LEE threshold.242

**Response to Comment 77 :**  The final rule has been amended to remove the fuel sampling and analysis requirement of the LEE option. Inlieu of fuel sampling, annual LEE performance testing w ill be required. **Comment 78:** Several c ommenters (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 currentl y re quired under the proposed rule. The commenters believes that the requirement to use the 90 th 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 quarterl y basis (i.e., by averaging the Hg content level s measured during the 3 months comprising the quarter). Step 4: Apply

the control efficiency

determined during the stack test to the quarterl y average Hg fuel content. If the projected annual emission rate (calculated b y multiplying the control efficiency determined during the performance test b y 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 perpetuall y precluded from re

establishing 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 the243

testing options listed in Table 5 (performance testing, Hg CEMs , sorbent trap monitoring s ys tem, 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 s ys tem or LEE tes ting options. **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

- ye ar compliance deadline for affected units have the option of complying with the LEE requirements. **Response to Comment 80 :**  LE E 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 routinel y below 50% of the standard for the applicable pollutant. **Comment 81:** Commenters 17627 and 17718 believe that the EPA should reconsider the frequency and ty pes 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:** B ecause of the evidence of widespread contamination with a risk of significant adverse health and environmental effects associated with Hg emissions and because Hg has a high degree of persistence, EPA believes that it is appropriate to set a more precautionary threshold for allowing a s ource conduct periodic emissions testing in lieu of monitoring continuously for compliance with the Hg emissions limit. As mentioned elsewhere in this document and rule preamble, mercury is a powerful neurotoxin that persists in the environment indefinitel y and its emissions warrant special attention. **Comment 83:** Several c ommenters (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 sho uld maintain its LEE status; i f 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 Iused is that a source is unlikely to opt for LEE status after th e CPMS is installed.244

**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 ty

pe, 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 bas ed on the new fuel type/blend. According to the commenter, this would require sources that burn multiple fuel ty pes or blends to establish a fuel

- input operating limit during the initial compliance demonstration. The commenter recommends that consistent wi th the non

- LE E requirements, the EPA should remove the arbitrary monthl y sampling requirement and allow sources to conduct fuel sampling only when there is a change in the fuel ty

pe and that for single

- fuel units, the EPA should specify that these units are not required to compl y 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. Inlieu of fuel sampling, annual LEE performance testing wi ll be required. **Comment 85:** Several c ommenter s ( 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 pl ants 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 b y 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 wi ll 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 “ Lo w 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 a gency 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 IC R and adjusted using the UPL calculation show s 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 significantl y 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 anal ys is. Most of the commenter ’ s Illinois facilities installed ACI controls in years 2008 and 2009, and have reduced Hg emissions below 22 lb/y r. The commenter states that such plants conduct semiannual performance s tack 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 sources245

from monitoring or allowing those sources to use less rigorous and lower cost monitoring technology, rather than requiring continuous monitoring. The comm enter 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 SO 2 and NO X emissions. **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 onl y occur annually and non

- Hg emissions testing need onl y occur once every 3 ye ars. 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 mo nthl y 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 l imit (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 anal ys is only when there is a fuel change plus repeat the performance test every 5
- ye ars. **Respons e to Comment 88**  **:** LE E status is unique to each regulated HAP
. A source may achieve LEE status for one HAP while not for another. **9 . LEE**  **f uel**  **s ampling**  **i ssues**  **. 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 anal ys is 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 co mpliance 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

anal ytical result s. **Comment 90:** Commenter 17928 states that under the LEE an oil analysis required to compl y with the input

- based standards requires very low detection limits not ty picall y available in national labs. According to the commenter, there are a limited number o f laboratories that do these tests to the limits of detection needed; these anal ys es are too costl y to have performed on the regular basis proposed in the rule; and the oil

- fired units ty picall y have low capacity factors, another factor that argues against regular oil testing.246

**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/y r 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 onl y the 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 SO 2 in consideration of a potential HCl LEE unit, would be adjusted as appropriate for the pollutant emissions that are monitored b y the CEMS . According to the commenter, this would serve to keep HAP emissions consistent, and again, fuel anal ys is 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 adequatel y address the operating characteristics of fuel

- fle xible 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 typ es 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, an d all the while there may not be any

economical substitute for the unusable fuel, thus causing extreme localized economic and employ ment losses. **Response to Comments 8 9**  **- 93:**  The final rule has removed the requirements for operational limits and fuel sampl ing and anal ys is for LEE units. Compliance with LEE status will be achieved through performance tests. In creased 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. See responses to comments elsewhere in this document relative to particulate Hg measurements. **10. Belt s ampling**  **. Comment 94:**  Commenters 17730 and 17775 state that section 63.10008 includes very specific requirements for collecting composite fuel s amples. 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, ” collectio n 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, and247

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 approximate ly 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
. **11 . Sorbent**  **t rap**  **. 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 c ommenters (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

- LE E units and 10 day s 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 routinel y 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 n otably , 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 , Exhib it D, Quality Assurance and Operating Procedures for Sorbent Trap Monitoring S ys tems.) 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 SO 3 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 recov ery and vapor phase breakthrough specifications)). According to the commenter, those QA/QC criteria are, b y 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 p erformance 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 f or up to 14 operating days consistent with Appendix A, 5.2.1.248

**Response to Comments 97 -**  **98 :**  The final rule has been amended to allow 14 day s 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 oil

derived unit that is found not to be an LEE is required to install a sorbent trap monitoring s ys tem to demonstrate continued compliance. **Response to Comment 99 :**  The source woul d be required to install sorbent trap monitoring s ys tem or Hg CEMS
. **12 . Oil**  **- Fired**  **t esting**  **. 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 sub category 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 comp liance. 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 quarterl y and to subject limited use ( capacity factor less than 8% in a 24 month block average ) sources to work practice standards in lieu of numeric emission limits
. Inaddition, the fuel sampling and anal ys is requirements have been removed. The onl y fuel

- related provision is an option for liquid oil

- fired units to demonstrate compliance with the acid gas standards b y documenting that fuel moisture cont ent remains no greater than 1.0% . This demonstration is based on monitoring results or fuel supplier certifications. **13 . Measurement**  **i ssues**  **. 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 vendor249

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

suppl y. **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. **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 anal ytical detection limits and emissions standards that are full y 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 by pass capability . Specificall y, states the commenter, the EPA should clarify whether initial testing of the b yp ass 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 b ypass stack emissions seems overly burdensome. According to the commenter, creating emissions (and incurring costs) by switching a unit into by

pass 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 by

pass 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 by pass stack is used as monitor downtime. **14 . Fuel**  **s am** **pling i**  **ssues .**  **Comment 106:** Commenter 17716 suggests that the fuel sampling, anal ys is 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, analy sis, and calculation of expected emission rates proposed in section 63.10021 should apply

to liquid oil

- fired sources. **Comment 107:** Commenter 17402 states that 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 ty pe. According to the commenter, data in the docket indicate that over the long term, facility

c ompliance is fairl y 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 cou pling the less frequent stack testing with more frequent fuel sampling.250

**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 ty

pe of fuel, sampling should only be required monthl y 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 b y 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 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 mo derate the alternative procedures in proposed section 63.10008. The commenter states that all fuel anal ys is 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 overl y prescriptive; the primary objective should be to obtain fuel samples that are representative of the fuel that is being combusted. According to the commenter, be cause there is so much diversity

in how fuel is received, stored, and processed at individual facilities, as well as what is actuall y 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 day s 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 ty pes anticipated to be combusted and whether the source or fuel supplier will conduct the anal ys is (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 anal ys is, it may not be possible for subsequent anal ys is in response to ch anges in fuel ty pe 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 anal ysis 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 10 6**  **- 109**  **:** The final rul e 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 (quarterl y) performance testing, CEMS, or a combination of annual emission testing and PM CPMS
. **15 . Fu**  **el l** **im its**  **. Comment 110:**  Commenter 17705 encourages the EPA to limit the requirement to establish maximum fuel inputs to sources that are uncontrolled and solely rel ying on fuel anal ys is to demonstrate compliance with a numeric standard. The commenter state s that the characteristics of fuel, in particular coal fuel, can vary

between shipments, so it is problematic to establish any ty pe of maximum value based on a one

- time, short

- term performance test, and further, for units that are controlled, rel ying on a fuel input limit does not adequatel y account for emissions reductions achieved b y 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 param etric monitoring for the control devices (coupled with period performance testing) than unnecessarily constrain fuel supplies through non

representative “maximum ” fuel inputs.251

**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 (quarterl y) performance testing, CEMS, or a combination of annual emission testing and P M CPMS
. **16 . CEMS**  **o nly**  **. 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 moni toring is required if a source uses a CEMS to demonstrate direct compliance with an emission limit (including the SO 2 surrogate limit for HCl). **17 .**  **Section 63. 10007(a) Site Specific Test Plan**  **. Comment 112:**  Commenter 17718 states that the EPA should prov ide 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 (especiall y 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/gd

042.pdf **18 . CPMS**  **c omments**  **. 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 fut ure 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 m onitoring s ys tem potentiall y subject to PS 17. **Comment 114:** Commenter 17775 states that the rule proposes various installation operation and maintenance requirements for “ flow monitoring s ystems, ” “pressure monitoring s ys tems, ” and “total secondary power m onitoring s ys tems. ” According to the commenter, several of these proposed requirements are unnecessary or unclear: first, with respect to flow monitoring s ys tems, depending on252

the fluid being measured, many s ys tems do not use flow meters due to reliability issues, corrosion, or composition. Instead, these processes frequentl y 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 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 s wirling 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 properl y locate the flow sensor and to us e 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 specificall y allow for procedures that include process trending and comparisons that can indicate the flow monitor is performing properl y (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 traceabl y certified each ye ar. **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 s ys tems in section 63.10010(h)(2)(ii)(B), the requirement will be diffi cult 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 toleran ce of 1.27 centimeters of water, or a minimum tolerance of 1 percent of the pressure monitoring s ys tem 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 boil er operating day to ensure pressure measurements are not253

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 ba ghouse 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 periodicall y clean them; the purges can be varied to ensure that key

pressure measurements are very reliable. For pressure sensors that are exposed to liquids (e.g., scrubber slurry), states the commenter, redundant taps and a water cleaning s ys tem is frequentl y 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, the se types of problem rarel y 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**  **m ethods**  **. 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 Anal ys is of Coal and Coke by Macro Thermogravimetric Analy sis, ” or (2) ASTM D5142 “ Standard Test Methods for Proximate Anal ys is 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 Anal ys is from As

Determined to Different Basis. ” The commenter states that both ASTM D3302 and AS TM D3180 are referenced in ASTM D3173, and in addition, the following methods are currentl y used b y EGUs for Hg, metals, and chlorine in coal and should be evaluated for inclusion without an equivalency anal ys is:

 EPA Method 7473

- “ Mercury in Solids and So lutions 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 Trac e Elements in Coal, Coke, & Combustion Residues from Coal Utilization Processes by Inductivel y Coupled Plasma Atomic Emission, Inductivel y 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 remain s no greater than 1.0%. This demonstration is based on monitoring results or fuel supplier certifications without reference to any specific methods for such anal ys es. As for the fuel metals contat sampling and anal ys is, the rule no longer requires such mea surement eliminating the need to specify these methods.254

**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 tes t 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 b y documenting 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 onl y 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 SO 2 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 SO 2 s tandard or use HCl CEMS, the frequency of required testing has been changed to quarterl y. **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 stat es 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 the255

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 recomm ends that this facility

- specific limit remain constant for a longer period of time, such as annually , to provide a measure of regulatory

certainty
. **Response to Comment 124:** The final rule does not use a total PM standard as a surrogate for non

- Hg HAP metal s, 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 onl y 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 clarificati on of section 63.10005 that allows exemptions from the PM testing and testing for specific metals, but onl y 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 I CR
. **Response to Comment 126 :**  In response to c omments, 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 sufficientl y accurate, reliable, or durable to yi eld significantl y 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 non

Hg metals, it is the primary standard expressed in the regulation

– compliance with specific metals limits would be regarded as an alternative compliance opti on 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 b y 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 interva l. The commenter believes that for sources that choose to use CEMS to demonstrate ongoing compliance with the standards, the performance testing256

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, SO 2 , 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. A ccording to the commenter, an annu al PM stack test is 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 quarterl y 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 likel y 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 p reviously 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 w orking properl y, 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 i ntent 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 ye ar 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 SO 2 CE Ms is determined using the average hourl y SO 2 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 SO 2 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 SO 2 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 , st ates the commenter, section 63.10006(a) and (b) state, that PM and non - Hg metal HAP , and SO 2 and HCl emissions testing, respectivel y, is required at least every 5 ye ars.257

**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 anal ys is 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 th at the Hg concentration in a monthly sample must be less than the 90 th percentile concentration based on the Hg content measured during demonstration of initial compliance; equation 13 refers to the 90 th percentile of Hg concentration as calculated according to Equation 8, but the referenced Equation 8 calculates the average fuel Hg content, not the 90 th percentile. The commenter states that the EPA needs to clarify these equations so it is clear how they intend the 90 th percentile Hg concentration to be calculated. **Response to Comment 133 :**  The fuel sampling and anal ys is 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 em issions 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 r evisions 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
.258

**5B 01**  **- Recordkeeping/Reporting: Data reporting requirements**  **Commenters** : 17402, 17655, 17677, 17681, 17772, 17821, 17881, 17902, 18023 **1 . Reporting**  **r equirements for**  **d eviations**  **. Comment 1:**  Commenter 17402 opposes the EPA ’ s proposed definition of “ deviation ” an d 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 respectfull y submits that operating parameter exceedances , such as this ESP power limitation or CEMS downtime (failed calibration error test, po wer outages, data acquisition and handling problems, etc.), are compliance indicators and, therefore, inappropriatel y 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 wh en 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 th e 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 , c ommenter 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 day s 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 the259

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 deviatio n in cludes 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 ty

pical of reporting. In addition, for malfunctions , additional notification requirements apply. The EPA is revising the affirmative defense related malfunction 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 b y telephone or facsimile (FAX) transmission as soon as possible, but no later than two business day s 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.” **2 . Reporting**  **r equirements for**  **m alfunctions**  **. 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 malf unction 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 EPA is revising the affirmative defense related malfunction 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 b y 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 day s whether the malfunction caused or contributed to an exceedance, no later than two business day s 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 day s after the end of the averaging period, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction.” 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 anal ys is shall also specify , using best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.”260

**3 . Quarterly**  **r eporting of**  **h ourly**  **d ata**  **. Comment 7:**  Commenter 18023 believes the quarterly submittal of electronic hourly data is inappropriate for an emission limit

- oriented rule, is highl y burdensome on the emission source operator, and should be removed from the proposed rule requirements. Commenter states that section 7.2.5, Quarterl y 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 hourl y reporting, the EPA consulted with DAHS vendors and was told that the cost of collecting hourl y data would be minimal . However, c ommenter believes the agency failed to consult with users to ascertain the time requirements and costs for reviewing hourl y data, as opposed to records compressed to daily, weekly, or even monthly averages. Commenter submits that there is no ne ed for hourl y data, as there are no hourl y 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 saving s 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 unneces sary and undul y 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 avai lable. ” 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 SO 2 and NO X 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 f acility has installed MACT level controls and is operating that equipment appropriatel y 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 quarterl y. 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.261

Commenter 17772 states that this proposal is consistent with past EPA MACT requirements imposed on other industries. According to the commenter, for example, the MAC T 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 th e utility sector should be treated similarl y - 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 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 sy stems to accommodate hourly

reporting of Hg CEMS and sorbent trap data w ould 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, CO 2 , or O 2 , and moisture monitors needed to convert Hg concentration to the units of the standard, because, as previousl y 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 emission s 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 quarterl y el ectronic reporting of hourly SO 2 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 negle cts 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 monthl y 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 h as 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 anal ys is 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 l iquid**  **o il**  **- f**  **ired u**  **nits .** 262

**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 d ay 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 F R 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 b y 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. **Response to Comme nt 10:**  With the changes in the final rule that eliminate the fuel anal ys is requirements, this comment is largel y 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 ex emption. 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 th e source must keep records of the fuel moisture of each fuel shipment. **5 . Semi**  **- a**  **nnual c**  **om pliance**  **d ates**  **. 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 day s 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 quarterl y reporting to ECMPS of CEMS data. **6 . Annual**  **d ocumentation**  **. 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 documentatio n 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 complian ce 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 d eviation reporting requirements that are ty

pical of most NESHAP. These summary reports are in addition to the detailed performance test results reported electronicall y and will be used by the permitting authority

for effective compliance oversight
.263

**7 . Other**  **d ata**  **r eporting**  **r equirements**  **. 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 ty pe and heat input fraction that matters in determining compliance. Th e 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 ty pes of fuel which are burned and the maximum percentage or fraction of each fuel type (on a he at input basis). **Comment 15:** Commenter 17881 states that the waste determination information should only be required if a new fuel typ e is introduced following the initial compliance demonstration report. **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 b y 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.264

**5B02 -**  **Recordkeeping/Reporting: Records that must be retained Commenters**  : 17681, 17775, 17881 **1 . Objection to**  **r etaining**  **r ecords**  **o n**  **- s**  **ite .**  **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 cop y, the facility can produce a cop y within a reasonable time. **2 . Objection to**  **r equirement to**  **r etain**  **r ecords for**  **five y ears**  **. 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 ye ars. (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 se ction 1320.5(d)(2)(iv) (requiring a showing of substantial need or statutory mandate to require retention of records for more than 3 ye ars). The commenter states that the EPA ’ s statement in the supporting statement for the February 2011 proposed IC R291 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 a gency 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 pro visions of this part shall maintain files of all information (including all reports and notifications) required b y this part recorded in a form suitable and readily available for expeditious inspection and review. The files shall be retained for at least 5 ye ars following the date of each occurrence, measurement, maintenance, corrective action, report, or record. At a minimum, the most recent 2 ye ars of data shall be retained on site. The remaining 3 ye ars of data may be retained off site. Such files may be maintained on microfilm, on a computer, on computer flopp y disks, on magnetic tape disks, or on microfiche. ” In addition, the 5

- ye ar 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

- ye ar 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 merel y confirms that the existing retention requirements appl y. **3 . Objection to**  **r equirement to**  **m aintain**  **mercury ma ss**  **e mission**  **r ecords**  **. 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 secti on 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 rate s, 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.265

**Re sponse to Comment 3**  : The EPA has retained the language as is, given the formulas that are used for determining lb/GWh
.266

**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 r**  **eporting .**  **a . Support for**  **ECMPS r**  **eporting .**  **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 b y 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 currentl y used successfull y to report Acid Rain Program emissions from utility units. **Comment 4:** Several c ommenters (1 7740, 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 informatio n 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 c ommenters (17715, 17877, 19114) state that ECMPS is currently being used successfull y b y industry

and the infrastructure is already in place, thereb y 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 c ommenter 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 r**  **eporting, but w**  **ith s**  **upplemental r**  **ulemaking and p**  **ublic c**  **omment .**  **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 b y 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 wa s 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 to267

cover information to be reported for SO 2 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 req uirements under the now

vacated 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 submi t 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 SO 2 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 b y OMB. According to the commenters, the EPA electronic reporting formats specified to date by the Administrator have been sufficientl y 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 c ommenter 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 r**  **eporting .**  **Comment 12:** Multiple c ommenters (17716, 17725, 17795, 17820, 17821, 17886, 18014, 18498) state that reporting hourl y CEMS data electronically should not be required. The commenters state that the EPA proposes to require quarterl y reporting of hourly emissions data as well as results of all required certifications and QA tests through the CAMD ECMPS software and that s ummaries of the emissions test results and semiannual deviation reports would also be required for SO 2 CEMS , PM CEMS , and HCl CEMS . The commenters believe there is no need for this requirement; the hardcop y deviation reports and data assessment reports are adequate and consistent with the requirements of other MACT and N SPS compliance rules. **Comment 13:** Multiple c ommenters (17716, 17725, 17775, 17795, 17820, 18014, 18498) state the EPA has not justified the burden of requiring the ECMPS reporting. Several c ommenters (17716, 17725, 17775, 17820, 18014, 18498) state that th e 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 eas y
– that sources would “ simply integrate Hg emissions data and QA test268

re sults 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 “ s imilar, 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 w ell as the EPA, especiall y 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 costl y exercise that is both unnecessary and unjustified. Commenter 19679 asks for clarification on whether the Hg CEMS data to be inte grated 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, specific ally 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. **C omment 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 hourl y Hg emissions data. The commenter disagrees with the EPA ’ s assumptions regarding hourl y 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 kin ds 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 hourl y Hg emissions data, or of the QA and certification data for Hg monitoring s ys tems. 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 wo uld 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 IC R for the proposed requirements for quarterly reporting of hourly Hg emissions data.269

C ommenter 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 costl y. Commenter 17775 states that in addition to the compliance report, deviation report, performance tests and monitoring s ys tem performance evaluations, the EPA proposes to require quarterl y reporting of hourly Hg data (e.g., emissions, certification and QA, and monitoring pl an 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 quarterl y el ectronic reporting of much of that information “ in a format specified b y 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 the se 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

averag e 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 disagr ees with the EPA ’ s proposal for data reporting in Appendix A. The commenter observes that the EPA has not required hourl y 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 EP A 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 quarterl y reports to the Administrator “ in a format specified b y the Administrator. ” The commenter notes that the commenter has challenged similar provisions for use in other programs judiciall y. 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**  **r eporting**  **f**

**ormats .** 270

**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 s ys tems must be connected to other plant data monitoring sy stems and integrated into a single report. The quantity of data for E GUs can be staggering. The commenter encourages the EPA to employ like data collection and transfer s ystems for multiple programs so that this expensive system can be used for each program, especiall y since much of the data is the same. The commenter state s that the utility industry has worked with the C AMD for the last 17 ye ars to devise a comprehensive schema that is flexible and is relatively

eas y 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 Sy stems, and Sorbent Trap Monitoring Systems similar to what is currentl y being collected for COMS
. 2. Monitoring Plan Data for Auxiliary Boilers present at facilities currentl y 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 S ys tems: a. Initial Certification Cycle/Response Time, 7

- Day Drift, 3

-point Linearity Check, and RATA test results b. NI ST Traceability

Test Results c. Annual RATA testing results d. Weekly

S ys tem Integrity

Check re sults 5. Certification Results for Sorbent Trap Monitoring S ys tems: 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 b y the EPA and state auditors and inspectors. **Response to Comments 1**  **- 17:**  We recognize that emissions reporting for continuously measured pollutants (SO 2 , Hg, etc.) and for periodical ly 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 the271

additional data demands. We also recognize the need for substantial modifications to the ECMPS to accommodate the data needs for periodicall y measured pollutants. Although major modifications of the ECMPS would be required for periodic compliance tests b y 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 s ys tems mature, information provided through the ERT will be used to populate these data systems. We are currently upgrading the AIRS Facility S ys tem and expect to replace manuall y 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 wil l be as extensive as some of the data reported for the 2010 I CR 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 sele cted 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 c ompliance 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 b y this final rule. We do plan a separate and independent re gulatory 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

f or compliance purposes but also for a variety of other uses. **3 . Other**  **CEMS r**  **eporting c**  **omments .**  **Comment 18:** Commenter 18014 notes that the proposed EGU MACT Rule does not include provisions to use the p art 75 “ conditionally valid data procedures. ” According to the commenter, this would require the operator to invalidate the p art 75 conditionally valid data (for SO 2 , CO 2 , O 2 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 p art 75 to be used for EGU MACT compliance (with the exception of bias adjusted and missing data).272

**Response to Comment 18:** The final rule provides for certain p art 75 proced ures for the CEMS and sorbent trap monitoring systems used to compl y with this rule, including the use of the conditionally valid data procedures. **Comment 19:** Commenter 18449 questions why either CO 2 , O 2 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 accuratel y calculate the mass emission rate of any pollutant and that adding confounding factors such as O 2 , CO 2 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 b eing produced is all that is required to calculate the EPA ’ s proposed emissions in lb/TBtu or lb/GWh . According to the commenter, a CO 2 anal yzer 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 clearl y 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 rul e retains these requirements, consistent with the general approach to monitoring for this sector under p art 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.273

**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 r**  **eporting of e**  **missions t**  **est d**  **ata .**  **a . Support for**  **u sing a**  **m odified**  **v ersion of**  **ECMPS .**  **Comment 1:** Several c ommenters (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 u sing 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 b y the industry in submitting IC R data using the ERT software, c ommenters 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 s ys tem was developed to support a trading s ys tem 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 SO 2 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 sy stem 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**  **u sing a**  **modified v ersion of**  **ECMPS .**  **Comment 3:** Commenter 17767 states that the ECMPS option would be overly burdensome as their experience with it has sho wn it to be increasingl y obsessed with minor data formatting issues that often prevent the submission of data (though it might have been acceptabl y formatted and submitt ed 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 previousl y caught in the past. The EPA created the ECMPS process to replace its previous less efficient and less precise data verification s ys tems and processes. The result of this re

- engineering is that there are significantly fewer formatting issue s that prevent submissions, and a fraction of submissions that contain critical errors at the close of each reporting period. This has added significantly274

to the EPA ’ s ability

to validate adherence to regulatory requirements, as well as, checking for the t echnical 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 EC MPS process as compared to the old record typ e column format and ETS/MDC processes that preceded ECMPS. However, the EPA recognizes that emissions reporting for continuously measured pollutants (SO 2 , Hg, etc.) from CEMS is structurally

and procedurally

dif ferent from what is needed to electronicall y collect reference method test data for periodicall y 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 mini mize the structural changes to ECMPS needed while harmonizing the data collection and reporting for CEMS sy stems. Because more substantial modifications would be required of the ECMPS to accommodate the MACT data requirements for detailed reference method test data and other periodicall y measured pollutants, the EPA has decided to further develop the ERT to receive these data. **2 .**  **ERT r**  **eporting of e**  **missions test d**  **ata .**  **a . Support for**  **ERT r**  **eporting .**  **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. A ccording 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 s ys tem to generate reports for the EPA and local regulators. **b . Opposition to**  **ERT r**  **eporting .**  **Comment 5:** Several c ommenters (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 b efore 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, as sess 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 currentl y 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,**  **s usceptibility to**  **v iruses, and**  **c orruption of**  **d ata**  **.**275

**Comment 6:** Commenter 17730 notes that the EPA is proposing to use the ERT as the platform for sources to electronicall y 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 anal ys is. Commenter has banned the use of the Microsoft Access database s ys tem on its inter nal 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 infec tions. 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 c ost of repairing a database that is eventually corrupted b y 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. Itis 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 correctl y 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 IC R 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 als o enhance data quality by storing information needed to understand sample results, such as results of analy sis of method and field blanks and laboratory

quality control samples. **Response to Comments**  **7 -**  **9:** The EPA recognizes that the ERT provided 2 years a go for use with the utility I CR 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 successfull y 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 t he number and detail of information required for the IC R 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**  **d etection**  **l imit**  **f lags**  **.**276

**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 anal ytical 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 ty pical non

- detect with a (<) sy mbol. The commenter states that the ERT requires the use of bracketed s ymbols 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 b y 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 laborato ries 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**  **r equired**  **e mission**  **t est**  **m ethods are not**  **s upported 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 hardwar e 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 anal ys is 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**  **b urdensome**  **. Comment 13:**  Commenters 17730 and 17775 state that use of the ERT is burdens ome (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, E RT 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 electronicall y 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 c ommenters (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 c ommenters (17718, 17621, 17816, 17881) note that manually

inputting data significantly increases the potential fo r errors in data277

reporting. Commenters 17718 and 17816 suggest that the EPA should make the tool more user friendl y. 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 suf ficiently 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 Admini strator “ 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 simil arly , 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 easil y reviewable. **Response to Comments 1 3**  **- 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 f ield 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 wi th 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 electronicall y populated into the ERT. The EPA disagrees that the ERT requires the reporting of vast amounts of data that is not currentl y 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 the278

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 h**  **as p**  **rovided n**  **o e**  **xplanation of h**  **ow WebFIRE**  **w ill**  **w ork**  **. 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 source s 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 deadl ine. 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 b y 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 c ommenter 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. Acc ording 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 W ebFIRE 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 u se 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 s ystems mature, information provided in the ERT will be used to populate these data systems. The EPA is currentl y upgrading the AIRS Facility S ys tem 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 d ata**  **. Comment 20:**  Commenter 17718 asked that the EPA clarify whether onl y CEMS RATA performed under this proposed rule are to be submitted electronically using the ERT and whether onl y SO 2 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 NO X 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
.279

**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 dail y, whereas RATAs likel y are performed onl y once a ye ar and considers the proposed exclus ion 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 LE Es do not conduct RATAs . PM CEMS are subject to different tests (RCAs and RRAs ). According to the commenter, sin ce LEEs comply by initially demonstrating applicability with emission tests and thereafter by fuel anal ys is, LEEs have no monitoring s ys tems 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 copie s of the test reports will be provided to the Administrator (and/or the delegated authority). The commenter does not agree with submitting RATA P M data into the WebFIRE database. The commenter states that for those monitoring s ys tems 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. **R esponse to Comments 20**  **- 22:**  We agree that it is appropriate and supportive of future regulatory reviews that the ag ency

collect data from CEMS RATA testing. The final rule requires that sources submit the test reports resulting from CEMS RATAs via the CDX to WebFIRE. **vii . Use of the**  **ERT should r**  **equire r**  **ulemaking and o**  **pportunity for c**  **omment .**  **Comment 23:** Several c ommenters (17730, 17725, 17775) believe it is inappropriate for the EPA to require submission of reports through this rulemaking before the EPA has more completel y explained its plans, completed any necessary rulemakings, and made operational its website. Comment er 17730 states that the EPA should not be promulgating requirements intended to support a larger program, piecemeal, before that program has been full y 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 b y the proposed January 1, 2012 deadline. **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 the28 0

commenter, i f 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 c ommenters (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 2 3**  **- 25:**  The EPA di sagrees 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 individual s to provide comment. The EPA also disagrees that the sy stem 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 regulate d 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 readil y available for not only compliance purposes but for a wide variety of other u ses. 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 a gency 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 sampl ing and to generate a standardized electronic output. **viii . Hard**  **c opies of**  **r eports are**  **n eeded for**  **agency r eview**  **. Comment 26:**  Commenter 17719 notes that stack test data reported to state agencies must be considered along with additional, specific informati on 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 adequatel y accounted for and reported in one reporting tool, allowing the asso ciated test data to be wholl y considered, the commenter relies heavil y 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 sta tes 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. **i x**  **. Hard c**  **opies of r**  **eports should not be r**  **equired .** 281

**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 previousl y 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 desire d. 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 file s. 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 availa

ble 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 s ys tem. The EPA believes that it is much more efficient to allow electronic population of data s ys tems 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 a ddition 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**  **- m**  **edia E**  **lectronic R** **eporting R** **ule .**  **Comment 28:** Commenters 17730 and 17775 stat e 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 sign ature, 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 e lectronic 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 C omment 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 submitt ed 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. **xi . Paperwork Reduction Act**  **.**282

**Comment 29:** Commenters 17730 and 17775 state that to comply with the Paperwork Reduction Act and its implementing regulations, the EPA must specificall y 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 appropriatel y 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 opportuni ty

to adequatel y 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.283

**5B05 -**  **Recordkeeping/Reporting: Other Commenters**  : 17 197, 17681, 17691, 17725, 17775, 17820, 17881 **1 . Electronic**  **r eporting**  **. 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
- ye ar 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 b y 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**  **t est**  **n otification**  **t ime**  **. Comment 3:**  Commenter 17681 asks that the EPA choose 15 days or 21 day s 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 performan ce 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)), p roposed 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 beg in, 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 correcte d 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**  **r eporting**  **r equirements**  **. 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 section284

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 “ anal ys is 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 perf ormance test results(40 CFR 63.2)(applicable under proposed Table 10); And that “ Excess emissions and continuous monitoring s ys tem performance reports ” are submitted semi

- annually , and must contain the information in section 63.10(c)(5) through (13), secti on 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 t est 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 ty pes 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 s ys tems , and (3) excess emissions and monitoring s ys tem deviation reports. The commenter states that proposed section 63.100031(h)(3) also requires a hard cop y 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, pri or 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 a gency 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 s tate 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 cop y of any report. The a gency

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 p art 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.285

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 Commen t 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 mu st include “ [i] dentification of whether you plan to demonstrate compliance with each applicable emission limit through performance testing and fuel anal ys is; 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 anal ys is; performance testing with operational limits (e.g., C EMS 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 option s. **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.286

**6 .**  **SSM r**  **eporting .**  **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 loc al 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 courtes y em ail may be sent as an unofficial notification.287

**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, 1 7627, 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, 17 840, 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, 185 41, 18575, 18933, 19032, 19114, 19121, 19122, 19212, 19213, 19506, 19653, 8443, 9738, 19536 , 19537 , 19538, 18023 **1 . General**  **c omments**  **. 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 clearl y 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 effective date of this rule or at start - up, whichever is later . Existing sources must be in compliance 3 years after the effective date of this rule.
. Three ye ars is the maximum compliance time authorized under the statute. See CAA section 112(i)(3)(A). If sources are unable to compl y within 3 years, the owner or operator may seek a 1 ye ar 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 s tated 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. Commenter 18034 states that EPA makes several vague statements about steps to ensure a reliable and reasonabl y-priced suppl y of electric ity , particularly regarding localized issues, but does not provide any288

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 reasonabl y 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 consum ers in those areas are not adversel y 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 p lan 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 th eir actions on the electrical power s ys tem and building an adequate safety margin into their rulemaking efforts to ensure that the electrical power s ys tem of the country is protected. Commenter 18447 states that EPA states in the proposal preamble that “th e Federal government will work with companies to ensure a reliable and reasonably

-priced suppl y of electricity. ” The commenter asks “ How does the Federal government propose to fulfill this promise? ” The commenter points out that maintaining generation capa bility and output from their facility is very important not only

for satisfying the electrical demand (load) of the City of Ames and I owa State University , but also for providing voltage support and electrical stability to the interconnected electric syste m 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 constructio n 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 Comme nts 2**  **and 3:**  Some commenters asked that EPA, b y 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 effective date of this rule , whichever is later. Existing sources may be provided up to 3 years after the rule’s effective date to comply with the final rule; if an existing source is unable to comply within those 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 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)). Permitting authorities should be familiar with the operation of the 1

- ye ar 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). 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 ye ars .289

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 . One area where the EPA has some measure of flexibility is with respect to the exercise of its enforcement authorities. Please see the preamble to the rul e for an in depth discussion of both the 1

- ye ar extension and authorities beyond the fourth year. **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

- ye ar 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 automaticall y qualify the particular unit for the extension. Several c ommenters (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 ye ar 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 EGU s in the proposed rule and we are not issuing amendments to those provisions in the final rule. 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 ye ar 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 commenter s (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 authorize s the President to provide 2

- year renewable extension for sources to comply

with the final standards if he determines that the technology to compl y with the rule is not available and the extension is in the national security interest of the U.S. **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 , s ys tem operators, and state regulators of expected effects of the EGU MACT and other EPA regulations. The290

commenters believe that such a process would provide an opportunity for meaningful assessment and response to reliability issues. Commenter 18034 re commends 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 s ys tem to ascertain the impact of the new rules on Texas ’ and the nation ’ s electrical power s ys tem. 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 compl y with the final rule. However, the Agency does encourage facility owners to n otify the permitting agencies, the transmissions operators, and state regulatory agencies as earl y as possible of their intention to retrofit or close. Earl y notification will help to ensure that permitting is orderl y and timely for plants that are retrofi tting. Itwould 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
. **Comment 8:** C ommenter 17648 suggest s a process based on early notification of retirements. **Comment 9:** Commenter 18441 asserts that the 3

- ye ar 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. Th e commenter provides the following three examples to support their statements:

 The need for the Susquehanna

- Roseland line was first identified by PJM and approved b y 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 Eddys tone Unit 2 requires 18 separate transmission sy stem 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 actuall y shut down until May, 2012.
 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 ter minal equipment, are not expected to be in service until more than five years after such notice in May , 2012. The commenter states that the anal ys is 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 ye ars foll owing publication in the federal register, 40 CFR §63.9984, may result in the shutdown of certain291

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 earl y retirement o f EGUs . These commenters argue that the EPA should have assessed reliability at much more local level rather than rel ying 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 up on coal

- fired capacity are likel y to face profound price, suppl y, and reliability concerns and that in the event of extraordinary events, only

the additional peak

- load capacity supplied by coal

- fired facilities are likel y to provide the resilience necessary to address potential weather

- related blackouts or even cy ber

- security threats to critical infrastructure. Commenter 17731 believes that reduced grid reliability will be exacerbated b y heavier reliance on non - final (i.e., interruptible) transmission and g as 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 prob lems related to compliance. The commenter not e s 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 suppl y. 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:** S everal comm enters (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 b y the EPA. These commenters identify several areas in which they believe the EPA ’ s anal ys is of reliability impacts is incomplete or inaccurate. 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 s ys tem outages than is considered acceptable in the ele ctric industry . According to the commenter, ERCOT292

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 s ys tem outage event. The commenter states that the study takes into account components of s ys tem 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 practi ce, 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 anywh ere in ERCOT can be transmitted any where in ERCOT ) and states that this is not correct. The commenter notes th at electrical power cannot be transmitted in an unlimited manner from any where to any

where 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 reliabil ity

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 currentl y 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 wil l 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 capa city 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 E RCOT System , issued on May 11, 2011, the 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 anal ys is erroneousl y 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 b y who lesale markets that signal the financial profitability of existing and new entry

resources. The commenter states that in contrast, the IP M employed b y the EPA to model reliability

impacts does not reflect the manner in which decisions are made in the whole sale market. According to the commenter, the objective of the IP M is to minimize the system wide, region

- wide, or nation

- wide cost of achieving resource adequacy and maintaining its293

representation of transmission reliability subject to the environmental co nstraints imposed on generating units b y the proposed rule. The commenter states that in sharp contrast to market dy namics, in the IP M modeling framework employed by the EPA, the retirement and new entry decisions are centralized; the decisions, are not ba sed 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 significantl y from the actual market

- based retirement and new entry decisions. 10. Commenter 18441 notes that the IP M 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 generall y 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 likel y missing possible generation retirements that may be driven b y the interaction of the EGU MACT with these potentially lower cost capacity resources. The commenter is concerned that the EPA ’ s anal ysis understates the volume of s ys tem security and local reliability

issues faced by RTOs and other transmission operators. 11. Commenter 18447 states that the IP M 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 o r retirement of some generation would take away

potential re

- dispatch solutions and therefore likel y 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 anal ys is is overly simplistic and incorrectly assumes that demand response, energy efficiency , and rapid and wide

- spread deplo ym ent of renewable energy resources will sufficiently replace lost coal

- fired generation capacity both from a resource adequacy and bulk power s ys tem 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 underestimate d 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 i ts 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 s ys tem, including load shedding and black

- outs. The commenter notes several potential operating reliability impacts of the Utility MACT rulemaking:294

 Contingency

Reserves: requires resources sufficient to address sy stem disturbances; 50 % must be “ spinning reserves ” ( i.e., reserve capacity at units alre ady 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 b y responding within 4

- 6 seconds; all regulating reserve must b e “ spinning ” ;  Frequency

Control: requires sufficient resources capable of automaticall y and instantaneously responding to changes in frequency caused b y constant tracking and matching of power demand and power suppl y 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 s ystem; 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 1 4**  **:** Commenter 17731 questions the EPA ’ s view that utilities can easil y 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 -**  **1 4**  **:** The EPA agrees with these commenters that real threats to reliability from these rules are unlike ly but agrees as well that a process involving early notification can promote confidence in reliability

and as well as promote the kind of planning b y 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. 3 The EPA believes that the fle xibility of permitting authorities to allow a fourth year for compliance should be available in a broad range of situations (as discussed in the preamble ), and that this flexibility addresses many

of the concerns that have been raised. Furthermore as indic ated below, in the event that an isolated, localized concern were to emerge that could not be addressed solely through the 1

- ye ar extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while maintaining relia bility
. 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 b y the CAA can be met. Many companies have begun to do the detailed analys is 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 adequatel y plan for, and markets are responsive to, future requirements such as this final rule. The EPA agrees with these commenters that if companies that intend to retire EGUs formally notify their RTO (or comparable planning coordinator in the case of non

- RTO regions ), state regulatory

3 As stated above, EPA has provided the maximum compliance time authorized under CAA section 112(i)(3)(A).295

agencies, and regional reliability entities as soon as possible that they will retire , it would help to alleviate any local reliability concerns. . As we said before, in most places a closing plant will not be a cause for concern. To the extent there is concern, however, earl y 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/operat ors 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 strongl y encourag es earl y notification, and believes that responsible owner/operators should and will do the earl y planning for compliance and provide earl y notification of their compliance plans, especiall y where such plans include retiring one or more units. On the suppl y 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 quickl y. 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. 4 The 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 ty pes of resources can also be developed very quickl y. 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 si de 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 sh ows that, in many cases, transmission upgrades to address reliability

issues from plant closures can be implemented in less than 3 years. For instance, when Exelon notified PJM of its intention to retire four units, 7 it was determined that transmission upgrades necessary to allow retirement of two units could be made within 6 months of notification, transmission

4 Paul M Sotkiewicz, PJM Interconnection, Presentation at the Bipartisan Policy Commission Workshop Series on Environmental Regulation and Electric Sy stem Reliability , Workshop 3: L ocal, 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 National Electric Energy Data System (NEEDS 4.10) (EPA, December 2010) 6 BPC slides cited above

– slide 5 7 http://www.exeloncorp.com/Newsroom/pages/pr_20091202_Generation.aspx?k=eddy stone296

upgrades for the third unit would require slightl y over 1 year and transmission upgrades to allow the fourth unit to retire could be made in approx imately 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, despit e 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 cur tailment) 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 anal ys is 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 L ong 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 relia bility 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 b y EPA regulations. Th e 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 l ocal 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 mo deled demand based on the AEO, which includes an estimated level of demand response
. The reliability contribution from renewable resources is a relevant issue onl y for wind resources
. The reliability capacity contribution from wind resources in the anal ys i s of the rule was based on estimates from the National Renewable Energy L aboratory

(NREL) and was incorporated in the resource adequacy assessment (See IP M documentation of wind resource and TSD on Resource Adequacy .) Local reliability issues can be addres sed during implementation of MATS.

8 Cromby Units 1 and 2 and Eddy stone Units 1 and 2

– Deactivation Study , Updated September 7, 2010

- http://policyintegrity.org/documents/20100907

- cromby

- and

- eddystone - retirement

- study

- posting

update.pdf297

**Comment 1 5**  **:** Commenter 17725 asks that the compliance date align with the Power Year used b y RTOs
. **Response to Comment 1 5**  **:** The compliance date for existing sources subject to this rule is 3 years from this rule’s effective date . That is the maximum amount of time permissible under CAA section 112(i)(3)(B) which the EPA felt appropriate given the significant work that some plants will need to undertake to come into compliance. **Comment 1 6**  **:** Commenter 17821 asks that the EPA develop guidance on applicability of section 112(i)(6) in the final rulemaking. **Response to Comment 1 6**  **:** 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 1 7**  **:** 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 o f operations. **Response to Comment 1 7**  **:** The EPA has consistently said that earl y 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 ind ustry , with proper planning, we believe that the compliance schedule established b y 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 p lace (such as integrated resource planning, and in some cases, forward auctions for future generating capacity) that ensure that companies adequatel y plan for, and markets are responsive to, future requirements such as this final rule. **Commenter 1 8**  **:** 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 generall y take longer to plan, site, build and interconnect than the p roposed r ule ’ s 3
- to 4
- ye ar complianc e 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 1 8**  **:** The EPA appreciates this comment and agrees that the state regulators have an important role to play

in assuring that the transiti on to a cleaner electric generating fleet that this rule will bring about occurs as smoothly as possible so that reliable power is maintained. **Comment 1 9**  **:** Commenter 17701 advocates flexibility in the implementation of this and other rules to avoid compromi sing electric system reliability while minimizing cost impacts to consumers. According

9 As stated above, EPA has provided the maximum compl iance time authorized under CAA section 112(i)(3)(A).298

to the commenter, flexibility will enable the EPA to accommodate the highly localized and regional nature of electricity services and avoid reliability issues. **Comment 2**  **0 :**  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 fo r 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 orderl y, cost - effective manner. **Comment 2 1**  **:** S everal 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 s ys tem. These commenters believe the EPA should incorporate greater flexibility into the EGU MACT to ensure adverse impacts on the reliability of the electricity suppl y are avoided. **Response to Comments 1 9**  **- 21**  **:** There are several flexibilities in final rule that EPA wills help to avoid rel iability 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 3 0 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 2 2**  **:** Commenter 17701 encourage s the EPA to work with s tate and f ederal 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 orderl y 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 achievin g 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 orderl y, cost - effective manner. **Commenter 2 3**  **:** Commenter s 18441 and 18448 request that the EPA state in the preamble to the final rule that the permitting authority should e xplicitly

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. ” C ommenter 18441 believes that Reliability Critical Units that have timel y announced their deactivation should be eligible for a 1

- ye ar 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 unit owner believes this is the least

- cost compliance option, and is effectivel y no different from a generating unit choosing to install retrofits to meet the emissions rate standards that299

cannot get its retrofits in service b y the January 1, 2015 , compliance deadline. The comment er 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 2 2**  **- 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 2 4**  **:** 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 2 4**  : 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 ye ars. The EPA also believes that making it clear that permitting authorities have the authority to grant a 1
- ye ar 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 i s 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. 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 analy ses that have been submitted to th e EPA showing that the rule does not cause a problem for electricity reliability, are “highl y suspect” in that they are “ largel y from economic competitors with a vested economic interest in decreasing the economic viability of coal

- fired generation and the reb y increasing the clearing price of energy for consumers

– that dispute adverse reliability claims from the proposed rule. ” This commenter points instead to another anal ys is from the Federal Energy Regulatory

estimating a large amount of coal

- fired capa city ‘ likel y ’ 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 2 5**  **:** The EPA makes no judgments about the mo tives 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 b eyond what EPA actually proposed and final led. As such it has very little bearing on this rulemaking. Furthermore the FERC Chairman stated clearly that the study the commenter is referring to was a “back

- of

- the envelope first assessment of the amount and location of potential generator retirements . He further said that informal assessment of that kind cannot be relied upon to determine specific effects on s ys tem reliability . Therefore, it is inadequate to use as a basis for decision making.”300

None
- the

- less as stated elsewhere in this document, the CAA provides flexibility to address any reliability problems should any

arise. **2 . Current**  **c om** **pliance period should be s**  **horter .**  **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 2 7**  **:** 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 F R 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 s ys tems are consistent with th e use of ACl in other industry

sectors since the mid

- 1990 ’ s to meet MACT mandates. See 62 F R 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 p roposal explicitly

acknowledges that all Hg control options take significantl y 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 ye ar 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

- ye ar compliance schedule for any coal

- fired EGU
.301

On the other hand, commenter 17675 requests a 5
- ye ar 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 2 6**  **and 27**  : Several commenters suggested that 3 years was too long for a compliance period given the delays in p romulgating 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

- ye ar 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**  **c om** **pliance d**  **ates are s**  **ufficient .**  **Comment 2 8**  **:** Multiple commenters ( 19536 , 19537 , 19538 , 17110, 17402, 17648, 17808, 17854, 17870, 17973, 18025, 18027, 18421, 18425, 18438, 18439, 18450, 18487, 185 01, 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 A ir Pollutants ” where URS Corporation concludes not only that technology

is readil y 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 ef forts 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 similarl y 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 b y the rule. Several c ommenters (18487 , 19536 , 19537 , 19538) agree that the 3

- ye ar period will not adversel y affect electricity s ys tem 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.302

Commenters 17789 and 18450 agree that the compliance time is reasonable and further state s 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

- CI O has stated that there is no evidence to suggest that the availabi lity of skilled manpower will constrain pollution c ontrol technology

development. According to the commenter, in fact, given the high levels of unemplo ym ent in the construction sector, these jobs are much needed. Several c ommenters (17844, 18439, 18450) be lieve 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 th e 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 s ys tem reliability
. According to th e commenters, i f 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 case by

- case basis, extensions of time to complete the installation of pollution control sy stems. The commenters assert that in addition, recent electricity forward capacity market auctions in the PJM and I SO
-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 I SO
-New England. According to the commenters, these reserve margins are well in excess of the federal reliability standards set b y 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 EI C wi ll retire by

2015; and (2) Electric s ys tem 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 electri city suppl y. 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 when303

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

- ye ar extension if the facility is unable to install appropriate controls will protect electricity s ystem reliability . According to the commenter, applying the extensi on 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 2 9**  **:** Commenter 17648 asked that EPA establish uniform criteria for the section 112(i)(3)(B) case - by

- case one - ye ar extension and allow plants that receive the extension to dispatch only to meet relia bility 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

su ppl y. 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 Corporati on (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 b y 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

-- - 34b 180846a19
. **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 anal ys es support th e EPA ’ s retirement projections, and criticisms of the EPA ’ s projections are overstated. C ommenters note that EEI ’ s report resulted in inflated unplanned coal retirements because their modeling scenarios incorrectly assumed that the Waxman
- Markey climate ch ange bill passed Congress, that the CWA section 316 cooling tower regulations would mandate a one

size

- 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 )304

“ 2010 Special Reliability Assessment: Resource Adequacy Impac ts of Potential U.S . Environmental Regulations ” may

also overestimate the impact of new regulations. **Comment 3 2**  **:** 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 b y 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 polluti on control equipment required b y this regulation. **Comment 3 3**  **:** S everal 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 h ave known about the various new regulations affecting power plants for several ye ars 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. C ommenter 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 util ity

sector. **Comment 3 4**  **:** 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 a s those held b y PJM and I SO
-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 3 6**  **:** S everal 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. C ommenter 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. C ommenter 17648 also notes that RTOs ty picall y have advanced warning of proposed unit retirements and that each RTO has procedures to assure that threats to reliability

are identified earl y enough to be avoided. **Comment 3 7**  : 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 also305

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 3 8**  **:** 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 ye ar . The commenter agrees that this is a reasonable scenario for facilitie s 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 high

emitting unit for an additional year, specificall y 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

- ye ar 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 3 9**  **:** 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 b y the autho rities 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 harmonizatio n 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 no t 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 way s 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 relia bility 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 ty pe of cross

- functional anal ys is should include the most speci fic localized or unit level reliability anal ys is possible in order to pick up key ancillary services important to grid stability
. **Response to Comment 2 8**  **- 3**  **9 :**  The EPA has set out in the preamble to this rule, the situations that merit the one

- ye ar extension under CAA section 112(i)(3)(B). While authority to grant the 1

- ye ar extension is given to the state permitting authorities, EPA expects that that discussion in the preamble will help guide the states on this matter. While the ultimate discretion to provide a 1

- year extension lies with the permitting authority, EPA believes that when appropriate it will be broadl y available to facilities. Please see the preamble for a fuller discussion of the 1

- ye ar extension.306

**4 . Current**  **c om** **pliance p**  **eriod s**  **hould be l**  **onger .**  **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, 1776 1, 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, 1 7902, 17904, 17909, 17911, 17912, 17913, 17918, 17925, 17930, 17931, 18016, 18021, 18024, 18026, 18027, 18031, 18037, 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 complianc e. 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, 1 7791, 18024, 18026, 18422, 19506) ask that the EPA consider a flexible, gradual, or staggered compliance schedule for this rulemaking. Commenter 17911 requests a 2
- ye ar 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 appreciate s the EPA ’ s recognition of the need to spread complex outages over multiple outage periods. A ccording to the commenter, a s 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.307

Commenters 18441 and 18448 state that timely notice of deactivation to the regional trans mission 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

- ye ar 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 aff

ected 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 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, 20 16. 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 specificall y 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 Stat e 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 L ead Smelting

- 1 year (17716, 17731) Multiple commenters (8443, 17402, 17627, 17767, 17821, 17868, 18021, 18037, 18502) ask that the EPA consider phys ical 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 say s that this usually mitigates price fluctuations related to the cost of generation of any single resource. However, the commenter says that308

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 me et compliance timelines. The commenter gives the following examples: 1
. EGU MACT : As proposed, the commenter ’ s coal

- fired generation will be covered b y the proposed EGU MACT ; 2
. RI CE 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 b y the CSAPR (formerl y known as the “ Clean Air Transport Rule ” ); 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, potentiall y 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**  : Inthis regulation the EPA provided the maximum 3

- ye ar compliance time authorized under the statute. See section 112(i)(3)(A). Furthermore, the EPA’s actions in other CAA section 112 rulem aking 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 t o 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

- ye ar 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). However as discussed elsewhere in this document and much more full y in the preamble, the permitting authorities do have authority to grant a 1
- ye ar extension under a range of circumstances. Be yond that the CAA provides mechanisms for sources to come into compliance while maintaining electric reliability
. 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 analy sis to assess the feasibility ( e.g., ability

of309

companies to install the required controls within the compliance time

- frame) and potential impact of the proposed rule on reliability . For that anal ys is entitled “An Assess ment 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 newl y retrofitted and in service b y 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, moderatel y paced effort of the power sector and supporting industry , including some earl y 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 b y J anuary

2015, most projects would have to start earl y and the sector would have to engage in a more aggressive deploy ment 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

- ye ar extension. Claims T hat More Time is Needed for Small Entities T o Comply As stated above, the EPA’s authority to provide more than three years to comply with the standards is constrained b y 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

- ye ar 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 compli ance provisions of the statute do not provide an exception for small entities
. Inadequate Labor Pool, Low Skill Level &Insufficient Equipment Suppliers With current unemploy

ment 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 b y i nstituting 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 eas y 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. Avai lable space is a problem at many remaining facilities. Space constraints are a challenge that must be addressed earl y in the design stage of a compliance strategy . There are a number of ways to economize the available space but ultimately each plant is dif

ferent 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 multi

unit cases the installation time should be only slightly greater than for a single unit, and still feasible for compliance b y 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 rent al, dedicated310

staging area, efficient skilled craft utilization, and reduced administrative outlay s. 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 absorber s. 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 The compliance deadline allows sufficient time for completing landfills for FGD solids disposal. For example, DP&Lwill 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 necessaril y need to comp lete 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 newl y permitted landfill under constructio n, 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 o f $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 W

ill Cause Electricity Rates to Rise The EPA recognizes that this rule will cause electric ity 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 ye ars. On average, this is a 2.9 percent increase and is well below electricity prices seen historically and as recentl y as four or 5 ye ars 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 devel opment for the past few ye ars. 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 o f 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.311

Smaller Plants W

ill 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 therefo re 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 sy stems will allow the overall effort to be more manageable than otherwise, and should require relativel y fewer supply chain resources. Smaller Companies W

ill 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 engineering ser

vices to comply

with this regulation. This comment presumes that there is a shortage of equipment, labor and materials to appl y to compliance with this regulation. As stated elsewhere we are in an economy that is characterized by high unemployment and chro nic 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 compl y. **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, an d 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 De crees: (17648, 17808, 17870, 18448) i. Temporary

waiver mechanisms: (17055)312

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 app roach would allow promulgation by the date mandated b y 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) 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 co nsent 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 arrang ements 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, f or 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 f acilities subject to a consent arrangement with the same 1

- ye ar 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 compl y 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 by 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 T oxics 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, an d 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 onl y in this313

way can the EPA and state permitting agencies conserve the benef its 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 provi sions 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 th e standards within the 3

- ye ar timeframe. The EPA believes that although most units will be able to fully compl y within 3 years, the fourth year that permitting authorities are allowed to grant for installation of controls is an important flexibility that w ill address situations where an extra year is necessary. That fourth year should be broadly available
. . Furthermore, in the event that an isolated localized reliability concern was to emerge that could not be addressed solely though the 1

- ye ar extension un der CAA section 112(i)(3), the CAA from provides some flexibility to assure reliability is maintained while facilities come into compliance. **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) re quest a “blanket 1

- ye ar 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 basi s. **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 ye ar 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 t o 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). S ome industry commenter s have specificall y stated that they will be able to comply with the rule in the 3 year period and we believe that there are approxim ately 69 EGUs that appear to be currentl y compl ying 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 currentl y compl ying 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
. **Comme nt 4**  **3 :**  Multiple commenters (16824, 17003, 17137, 17730, 18441) ask that compliance be delayed until additional studies or anal ys es are conducted. Commenter 16824 asks that the EPA complete a cost

- benefit anal ys is (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. ”314

Commenters 17003 and 17730 ask that the EPA undertake a formal assessment of the feasibility for regulated sources to contract for equipment and man power 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. 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 adversel y impacting electric reliability. The commenter states that although the EPA ’ s anal ys is addresses overall system adequacy , the EPA has not anal yz ed s ys tem security under the rule. **Response to Comment 4 3**  : The MATS was developed by the EPA after years of studies and data anal ys is that examined the nature and quantity of HAP emissions from power plants, the heal th 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 job s. 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 readil y 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 moderatel y. 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 4 4**  **:** Commenter 17682 worries that the rule as proposed will severel y harm the ability of the United States to produce reasonabl y 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 onl y if it reflects the results of a credible cost

benefit anal ys is and a full assessment of the impacts of using potentially conflicting and relativel y untested MACT technologies to achieve compliance with the range of pollutant standards C ommenters 17003 and 17297 quote the EPA compliance cost estimates of a $3

- 4 in crease 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 4 4**  **:** 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 ye ars ago. It is not reasonable to take as a “ given ” that this rule will diminish international competitiveness. In fact the annual cost o f the rule is less than 0.001 percent of GDP. It is unlikel y to have much impact on the competitiveness of the U.S. economy.315

The benefits of the rule on the other hand, according to the EPA ’ s cost benefit study which is based on peer reviewed scientific l iterature 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
. **Commen t 4**  **5 :**  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 equipment installation. Commenter 19114 provides a detailed discus sion 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 ye ars (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 ye ars for retrofit (17805) f. SCR: (1) 36 months (1837) (2) 3 1⁄2 years (17623, 18428)316

(3) 43 months (17655) (4) 42 months (17736) g. Scrubber: (1) > 36 months (19114) (2) 40

- 60 months (17623) (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 year s ( 18023 ) i. Changes in fuel supply

to natural gas: 4 1⁄2 years ( 18023 ) j. Changes to transmission grid: (1) >3 ye ars ( 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 4 5**  **:** Numerous commenters submitted their own evaluation of the length of time required to install controls, swi tch 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 referenc ed 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 o f 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 control s industry developed into a mature industry

in response to the Acid Rain Program, the NO X 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 con siderable efficiency gains through integrating standardized equipment designs,317

systems approach, and modular construction techniques as well as the formation of business alliances1 to reduce frictional time lags. A ty pical 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 des ign

build 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) and award work requiring significant capital commitment (detailed design, procurement, construction, commissioning/testing). Pre
- award work elements are typicall y executed sequentially since each preceding stage ’ s results inform the following stage; however, award work elements can be executed with “ Lean C onstruction ” 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 b y commenters fail to account for the adoption of proven faster execution methods evidenced b y numerous units that have demonstrated FGD retrofit pro ject completion in less than 30 months. In particular, commenters who cite examples of lengthy or delayed retrofit schedules from projects conducted during the highl y uncertain period of the CAIR remand (when it was prudent to proceed cautiousl y) cannot re asonabl y expect such experiences to appl y 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 sy stems. Springerville Unit 3, for example, is a 400 MW coal

- fired unit that became operational in July 2006, some 33 months after the turnkey engineering

construction contractor was given a notice to proceed with engineering.5Springerville was clearl y on an accelerated schedule, as its original planned schedule was about 38 months. The main point here is that ty pical schedules for large complex power projects can be significantl y 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 sy stem, EPA believes that even the most complex retrofit APC project can be significantly accelerated as well. The recentl y surveyed wet FGD project schedules are not all representative of the shorter project schedules that EPA expec ts 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 week s, 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 p rojects 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 wet318

FGD s ys tems in a short period of time. Extend ed 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 s ys tems. The relatively much simpler dry

FGD, f abric filter, and other even simpler DSI and ACIs ys tems 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. **5 . One**  **- y**  **ear e**  **xtension .**  **Comment 4 6**  **:** The EPA request ed comment on a 1

- ye ar 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 significantl y reduces opportunities for facilities to invest in clean replacement power and consider retirement as a compliance strategy . Th e commenter states that this approach has multiple adv antages. Several c ommenters (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

- ye ar 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

- ye ar 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

- ye ar window. Several c ommenter s ( 19536 , 19537 , 19538 ) believe 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 commenter s state that section 112 uses “ emission control ” broadl y to r efer to pollution reductions of any319

sort(see, e.g., 42 U.S.C . §7412(d)(3), (d)(5), (d)(6), & h(1) (all using “ control ” to refer to pollution

reduction and referring to “ emission control ” achieved b y “best controlled similar source ” )), that in keeping with that general sy nony my , 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 commenter s state that elsewhere in the statute, as well, the term “ control ” is defined broadly enough to include the cessation of po lluting operations. See , e.g., 42 U.S.C . §7479 (defining “best achievable control technology” ). According to the commenter s , closure of a high

-polluting unit is a measure that reduces pollution, and is therefore a “ control ” under the CAA. The commenter s st ate that the EPA has, accordingl y, 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 shut down 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 b y 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 ye ars. The commenter states that the EPA has, elsewhere in its proposed rulemaking, considered reliabili ty to determine the pace at which controls can practicabl y 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 rel ated to compliance and reliability , particularl y in the event unit shutdowns occur in load

- constrained areas)). Commenter 18426 states that the extension, with the factors and conditions for qualifying and appl yi ng 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, a s 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 rul e 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? I s 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?320

Commenter 19122 state s that the 1

- ye ar 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 monit oring/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 in dustry will have very

little problem in meeting the 3

- ye ar 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: 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
. Earl y planning action by regulated utilities; and 6
. Earl y planning action by RTOs. **Comment 4 7**  **:** Multiple commenters (16850, 17004, 17026, 17887, 18539) comment on retiring or repowering units. Co mmenters 17004 and 17026 request that the EPA allow power companies to operate their plants as efficientl y 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 he at recovery , can be deemed “ controls ” under the CAA. **6 . Extensions for**  **r etirement and**  **r eplacement**  **p ower**  **. Comment 4**  **8 :**  Several commenters ( 18023 , 17638, 17696, 17820, 17821) ask that the provision to allow a 1
- year extension apply to all retirements. Multiple c ommenters (17841, 18426, 18434, 18441, 18442 18448) ask that a 1

- year extension be provided for possible unit retirements, retrofits, or repowering
. S everal c ommenters (18434, 18441, 19114) note that this extension should apply to off

- site power gener ation in limited circumstances. C ommenters 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 replacem ent 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 full y retrofitted.321

Commenter 18450 opposes allowing a fourth ye ar for compliance when building replacement power unless the source can demonstrate an electric reliability issue. Commenter 18039 objects to granting 1

- ye ar 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

- ye ar compliance deadline, to operate such existing high

- emitting unit for an additional year, specificall y due to the 1

- ye ar extension. The commenter states that in addition, if designing, permitting and constructing replacement power continues beyond a 1

- ye ar extension, it should be stressed that the CAA does not allow MACT compliance extension beyond 1

- ye ar, whether or not a replacement unit has come on

- line. Commenter 18441 notes that the 1

- ye ar extension request, if granted, may create in centives 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 b y the regional transmission organization in its subsequent deactivation study to be Reliability

Critical Units. According to the commenter, in this case, generator owners can effectivel y attempt to extend the life of th eir units for an additional ye ar or more with no intention of installing retrofits b y simply delaying their deactivation request so they can effectivel y side

- step compliance with the final rule through a potential misuse of the extension process contemplat ed 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 deactivatio n 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 4 6**  **- 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 flexibi lity that will address situations where an extra year is necessary. That fourth year should be broadl y available where it is necessary . Please refer to the preamble where there is a detailed discussion of the fourth year. The EPA is making it clear that pe rmitting authorities have the authority to grant a 1
- ye ar compliance extension where appropriate
. The EPA continues to believe 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
- ye ar compliance extension where necessary , in range of situations described in the preamble , addresses many of the other concer

ns that commenters have raised. **7 . Issues and**  **c osts**  **that n**  **eed to be c**  **onsidered in d**  **etermining compliance d**  **ate .**  **Comment 4 9**  **:** 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 ,322

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

-prop osals 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, especiall y 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 4 9**  **- 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 reasonabl y installed wi thin that time. 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 als o 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

- fram e 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

- ye ar extension would provide an additi onal 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 ye ar 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 C AA 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.323

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 po llution 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 larg e 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 pric e 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 res ources. 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), respectivel y. 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 l ife of the compliance period. Documentation for IPM can be found in the docket for this rulemaking or at http://www.epa.gov/airmarkets/progsregs/epa

ipm/index.html or at http://www.ep a.gov/airmarkets/progsregs/epa

- ipm/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, 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 a naly zed and units have made their individual retrofit vs. retirement decisions. The commenter believes that the EPA understates the number and size of retirements. **Comment 5 3**  **:** 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

r etirement 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 j eopardize the reliability of the U.S. electricity

supply by reducing generating capacity through earl y 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 elderl y citizens, may be at risk during severe winter weather or hot summer temperatures. Some commenters offer comments about processes based on earl y notification that might be set up to assure that the compliance timeframe did not interfere with electricity reliability . Commentor 17648 suggests that the EPA be notified within 1 year of the effective date of this rule, of compliance plans324

including plans to retire units. Commenters 18441 and 18448 recommend that plants be required to notify RTOs and IS Os of their plants to retire units so that the RTO/I SO can assess the impact on reliability of the planned closure. In the event that a unit is deemed “reliability critical” the ISO/RTO can plan transmission upgrades and other actions to avoid a loss of grid stability . These commenters envision a “proforma consent decree” to provide additional time if needed. **Comment 5 4**  **:** C ommenter 18023 believes the loss of generation capacity caused by

earl y 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 5 5**  **:** Numerous commenters (16705, 17055, 17254, 17400, 17403, 17608, 17627, 17761, 17765, 17804, 17813, 17857, 17901, 17911, 17813, 17901, 17904, 17911, 1 7919, 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, 1 7911, 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 Electri c Institute, prepared b y IC F 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 Sys tem , 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. ” ).
 Ira Shavel & Barclay

Gibbs, Charles River Associ ates, “A Reliability Assessment of EPA ’ s Proposed Transport Rule and Forthcoming Utility MACT ” (Dec. 16, 2010)(estimate 39 GW will be lost through earl y 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 th e Vice of EPA Regulation; W ho W ins 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 b y 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 prematurel y b y 2016).
 PIRA (states that over 160 GW of coal units do not currentl y 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. ” ).325

 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, principall y 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 5 6**  **:** Commenters 17919 and 18033 refer to statements made b y FERC that acknowledge FERC ’ s preliminary assessment on the impact o f EPA rules on coal

- fired generating capacity “ showed 40 GW of coal

- fired generating capacity ‘ likel y ’ 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 earl y collaboration with key stakeholders to prevent the potential for skyro cketing 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 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 suppl y 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 DSIassumption 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 shortl y 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 ab out the reality326

of these “ collaborations ” to deal with this important issue. The commenter states that in any event, and unsurprisingl y, the foregoing demonstrates that FERC

– responsible for delivering reliable electricity to the country

– is not as confi dent in the EPA ’ s assessment of the situation as the EPA portray s 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]av ing 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 complete ly 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 generatin g units could be impacted b y 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 Commission er Moeller ’ s response, “ [a]ccording to OER staff, EPA ’ s reliability anal ys is has been limited, ” and that staff have, “pointed out to EPA that a reliability anal ys is 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 underl ying 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 anal ys is 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 b y 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 anal ys is of the EPA ’ s rules that could impact reliability of electricity

– and disclose that analysis for public com ment

– and then hold a technical conference for public input; and (2) have the 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 especiall y 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 woul d 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 “ lev el the playing field, ” the agency has done an inadequate job of informing the public as to the consequences of such a policy 

### and that t he 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.327

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 co mmenter 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 directl y 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 anal yz ing 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 no t 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 thereb y 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 effectivel y prevent the agency

from being responsive t o public comments. **Comment 5 7**  **:** C ommenter 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, 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 thoroughl y examine the impact of process upsets on reliability

of the electric supply
. **Comment 5 8**  **:** Several commenters (17813, 17911, 1 7930) are concerned that the EPA has underestimated the impact of rising demand on electric s ys tem 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 rese rve 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 b y a stalled economy. If industry were to return to pre

- 2008 levels, they argue the market availability and market demand would be more closel y aligned, and even the EPA ’ s estimated 9 GW retirement may have an impact.328

**Comment 5 9**  **:** S everal commenters (17627, 18037, 18441) note that the EGU MACT has already had an impact on coal

- fir ed 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 88 43 worries that the “ enormous ” investments required to comply will lead to reliability issues by closing down any

where from 30

- 50% of coal

- fired power plants. Commenter 17055 worries that the EPA has not considered the impact of the RI CE regulations that c ould potential result in the loss of the small generators upon which many municipalities rely. They note that elimination of those units could create local suppl y 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 I SO
-NE auctions have already made commitments to supply power through May

31, 2015. They

further note that the last date to submit a delist b id for I SO
-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 earl y EGU retirements can be managed. Co mmenter 18441 believes the RTO /I SO notification procedures are not adequate to meet the magnitude of changes and potential retirements that could result from implementation of the proposed rule. C ommenter 17774 states that South Carolina does not have an RTO or I SO 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 southeaster n U.S
. Commenter 17919 believes that the industry cannot rely

on EPA emergency authorities because the EPA 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 5**  **2 -**  **62 :**  The EPA has considered the concerns raised by commenters and has concluded that given the flexibi lities provided in the final rule, the requirements of the final rule for existing sources can be met by most sources without adversel y impacting electric reliability. In particular, the EPA believes that the flexibility of permitting authorities to allow a fourth ye ar 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 c oncern were to emerge that could not be addressed solel y through the 1
- ye ar extension under CAA section 112(i)(3), the CAA provides flexibilities to bring sources into compliance while maintaining reliability
.329

The EPA considered the impact that potential retirements in response to this rule will have on re source adequacy . In considering these impacts, the EPA considered both the analy sis it has conducted as well as anal ys es conducted b y a number of other groups. The EPA’s anal ys is shows that the expected retirements of coal

- fueled 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 DSImay not be as prevalent as the agency has predict ed and because this could lead to more coal retirements, the agency

also performed a sensitivity analysis in which less DSIs ys tems and more scrubber s ys tems were installed. In that sensitivity , we see approximately 1 more GW of retirement. This small change would have onl y 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. e EPA’s assessment looked at the capacity reserve margins in each of 32 sub

- regions in the continental U.S. Demand fo recasts used were based on EIA projected demand growth. The analysis shows that with the addition of very little new capacity , average reserve margins are significantl y 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 nearl y 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

- sp ecific 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 EPA ’ s analysis. The DOE , in December 2011, published a report that looked at resource adequacy in the bulk power s ys tem when faced with a stress test which was a regulatory scenario far more stringent than EPA ’ s regulations. 10 For this stress test, in addition to CSAPR and MATS requirements, each uncontrolled electric generator is required to install both a wet FGD s ys tem and a fabric filter to reduce air toxics emissions. I f such installations are not economically ju stified, 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 ty pically cost less than installations of F GDs 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 anal ys is finds that less th an 1 GW of new natural gas capacity would be needed b y 2015 beyond the additions already projected to occur in the Reference Case. This anal ys is 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. In August 2011, PJM Interconnection

– the Regional Transmission Operator (RTO) responsible for planning and reliable operation of the bulk power sy stem serving all or portions of 13 states in the Mid

Atlantic and Midwestern regio ns - issued a report anal yz ing the impacts of the CSAPR and the proposed MATS rule. 11 Although PJM ’ s anal ys is assumes substantially more retirements than EPA projects, it nevertheless concludes that resource adequacy is not threatened in the PJM region. Thi s is particularly significant, given that the PJM region is one of the largest and most heavil y dependent on coal

- fueled

10 U.S. Department of Energy , December 2011, “Resource Adequacy Implications of Forthcoming EPA Air Quality

Regulations”. 11 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.”330

generation in the country. The PJM analysis notes, as 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. In June 2011, the Bipartisan Policy Center issued a report anal yz ing potential collective impacts of EPA’s pending power sector rules and concluding that “scenarios in which electric s ys tem reliability is broadly affected are unlikely

to occur.” 12 The EPA has reviewed industry and NERC studies suggesting, contrary to the EPA ’ s and these other groups ’ anal ys es, that EPA rules affecting the power sector (including this final rule, the CSAPR, EPA ’ s proposed rule addressing power plant cooling water intake s ys tems under section 316(b) of the Clean Water Act (CWA), and 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 the se anal yses 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 b y several of these studies is attributable to their inaccurate assumption that EPA ’ s 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 anal ys es were performed before the CWA section 316(b) rule or the MATS rule were even proposed; even analyses subsequent to the CWA section 316(b) proposal continue to inaccuratel y portray EPA ’ s proposed approach. Second, in reporting the number of retirements, many anal ys es 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. As a preliminary

matter, none of the se situations, either alone or in combination, will necessaril y lead to an electric reliability

problem. There is excess generating capacity in the U.S. today and in most cases an EGU that closes, either temporaril y until it comes into compliance or permanently , will not cause a reliability problem. As explained above, our modeling of the impact of this final rule at the regional level projects retirements of less than one percent of nationwide generating capacity and confirms that there will continue to be adequate capacity in all 32 subregions of the country as sources compl y with

12 Bipartisan Policy

Center, June 2011, “Environmental Regulation and Electric System Reliability”.331

the rule. 13 This analysis shows that significantl y less capacity will close in response to the final rule than might have under the proposal. Moreover, the regional modeling of retirements demonstrates that plants that close in response to this rule are spread out across the country rather than clustered in one area. Outside anal ys es have identified many of the same flaws in studies projecting large

- scale retirements as a result o f EPA’s power sector rules. For example, On August 8, 2011, the Congressional Research Service (CRS)
. 14 issued a report that report that concluded that studies that assert that EPA rules will cause reliability

problems, often make assumptions about the requirements of the rules that are inconsistent with, and dramatically more expensive than, the EPA ’ s actual proposals . CRS further noted that EPA’s rues will primarily affect units that are more than 40 years old, that have not yet installed state - of

- the

- art pollution controls, and that are inefficient. Many of these plants are being replaced by combined cycle natural gas plants, driven more my lower gas prices than by

EPA’s regulations. The June 2011 Bipartisan Policy Center report referenced above likewise highlighted many of these same shortcomings in the studies in question 15 as did M.J. Bradley and Analysis Group in a June 2011 report. 16 **Comment 6 3**  **:** 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, 190 32, 19114, 19121) note that there are likel y 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) specificall y reference th e NSR process. Multiple commenters (17730, 17736, 17758, 17808, 17820, 17821, 18024, 18037, 18428, 18447, 19114) specificall y 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 specificall y 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. Commenter 17813 is concerned about pre

-permit approval evidentiary hearings requi red in Texas, which ty pically 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 b y the Minnesota Pollution Control Agency.

13 See Technical Support Document on Resource Adequacy in this Docket. 14 James E. McCarthy

and Claudia Copeland, Congressional Research Service, August 8, 2011, “EPA’s Regulation of Coal

- Fired Power: Is a ‘Train Wreck’ Coming?”. 15 Bipartisan Policy

Center, June 2011 , “Environmental Regulation and Electric System Reliability”. 16 M.J. Bradley

& Associates and Anal ys is Group, June 2011, “Ensuring a Clean, Modern, Electric Generating Fleet while Maintaining Electric System Reliability .”332

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

commissi on 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 anal ys is done in 2005 that looked at SCR and FGD for C AIR compliance, but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR requirements would not significantl y 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 chemicall y 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 pollutio n 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 p ermitting 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 strate gy . 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 rec overy , authorization ty picall y averages seven months and is obtained usually within one year. 17 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 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
- ye ar compliance extension where necessary , in the range of situations described e lsewhere in this document , addresses many of the other concerns that commenters have raised.

17 “ 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.pdf333

Time frame for Compliance Is Too Short to Construct and Permit an FGD Land fill As we have said elsewhere in this document, th e compliance deadline allows sufficient time for completing landfills for FGD solids disposal. For example, DP&Lwill 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 necessaril y need to complete landfill construction ahead of commencing operation of the retrofit to achieve cost

- effective emission reductions under the Transport Rule programs. S uch 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 statio n 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 sh ould 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 necessary . I f all parties work diligentl y and proactively, state permitting will not prevent facilitie s from coming into compliance with this rule within the compliance period. If, however there is an unexpected delay

that could not be prevented b y the facility’s owner, the EPA expects the 1

- ye ar extension of the compliance time to be available. **Comment 6 4**  **:** 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 suppl y 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 compl y 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
- ye ar time period allowed b y 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. 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 onl y 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 standb y t o 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,334

brownouts or rolling blackouts. Commenter 17775 estimates that installation of new control equipment required b y the EGU MACT would take at least 6 years to complete. **Response to C**  **omment 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 compl iance 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 m ay need to be newly

retrofitted and in service by the compliance date(s). The EPA used its IPM model to anal yz e which APC technologies would likely be used, and in what quantities, to achieve compliance with the proposed Toxics Rule. The EPA’s assessment s hows that a reasonable, moderatel y paced effort of the power sector and supporting industry , including some earl y 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 b y J anuary

2015, most projects would have to start earl y and the sector would have to engage in a more aggressive deploy ment 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

- ye ar 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 relativel y quickl y. 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 disc retion to grant extensions to the compliance time

- line of up to 1 year. This time

- frame also allows extra time 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 c ontrols on another unit). In other words, the additional 1

- ye ar 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 compl y within 3 years, the 4 th ye ar 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 EP A expects that state permitting authorities will make the fourth ye ar available
. **Comment 6 5**  **:** 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 **Response to Comment 6 5**  : The EPA agrees that the unique considerations faced b y 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 h as 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 o n the data to be received, for non - continental oil

- fired EGUs. The EPA has now received these late data and, based on those data, we determined the emissions characteristics of the non

- continental units were different, and, therefore, the Agency is finaliz ing a non

- continental subcategory for liquid oil

- fired EGUs in Guam, Hawaii, Puerto Rico, and the U.S. Virgin I slands. The EPA is not aware of any liquid oil

- fired EGUs in any of the other335

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 emissio ns characteristics, warrant a separate subcategory

for these EGUs. The EPA believes that units in this subcategory will compl y through the use of cleaner oils or, for PM, through the installation of an ESP. **Comment 6 6**  **:** C ommenters 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 b y regulatory authorities. **Response to Comment 6 6**  **:** 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 b y the board of directors). In response to these monetary assertions, the EPA recognizes the adversity towards financial risks associated with installing controls equipment pri or 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, en gineering and construction management costs (as a percentage of total installed cost) range from 4.1 % to 7.3 % (basis: 500 MW unit). Considering industry ty picall y limits conceptual engineering not to exceed 10% of total engineered cost, b y extension, pre

award work accounts for less than 1 % of total installed price. [Conceptual engineering studies are defined as: establishing project scope, typ e 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 examp le, 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 Gentleman Station. 18 This represents 0.24% of installed cost. Since c onceptual 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

co mpliance, which appears to serve a sensible fiduciary purpose. Negotiating Contracts, Competitive Bid Evaluation

– More Time Required for Compliance

18 “ S&L to Develop Cost Estimates, Plans for FGD at Gerald G entleman ” ; Utility E
- Alert #1030, June 24, 2011; McIlvaine Company336

Contract negotiation through the competitive bid process is an agreement achieved between a buye r (utility) and seller (supplier). Ultimatel y, the buye r 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 ye ar, 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; namel y, 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 6 7**  **:** Multiple commenters ( 18023 , 17608, 17638, 177 16, 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 f

iduciary 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 s tate 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 non

recovery if they make capital commitments before a final rule is issued
. **Comment 6 8**  : Co mmenter 18421 recommends that the EPA, the DOE, and the FERC work closel y with regional utility

planning and operation centers, the National Association of Regulatory Utility Commissions, state PUCs , and utilities to ensure that the measure s available preserve the reli ability of the electric s ys tem. 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. **R esponse to Comments 6**  **7 and**  **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

- ye ar compliance timeframe. A number of commenters took exc eption 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 adequatel y plan for, and markets are responsive to, future requirements such as the rule. In addition, the EPA itself is reaching out to key

st akeholders including not only sources with direct compliance obligations, but also337

groups with responsibility to assure an affordable and reliable suppl y 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 understands that FERC and DOE will work with entities whose responsibility

is to ens ure 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 earl y 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

- ye ar compliance time

- frame as specified in CAA section 112, along with other compliance tools, ensures that the emission reductions and health benefits required b y the CAA can be achieved without any risk of adverse impacts on electricity s ys tem reliabili ty
. **Comment 6 9**  **:** Several commenters (17403, 17716, 17821, 17902) note that delay s are expected due to the number of involved stakeholders (state public utility commissions, RTOs , NERC , FERC , DOE, EPA). **Response to Comment 6 9**  **:** Some commenters thought that there would be delays in compliance with this rule attributed to the numerous stakeholders who would be involved . W ith proper planning, we believe that the compliance schedule established by the CAA can be met. As stated above, there are already tools in p lace (such as integrated resource planning, and in some cases, advanced auctions for capacity) that ensure that companies adequatel y 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 suppl y of electricity including state Public Utility Commissions (PUC), Regional Transmissi on 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 res ponsibility 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 s ys tem reliability **Comment 7 0**  **:** Several commenters (17402, 17752, 17758, 18428, 19114) note that the word “ installed, ” when attributed to vendors, refers onl y to the phys ical construction of the controls but that the reali ty 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 7 0**  **and 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 fue l supply changes.338

**Response to Comment 72**  **:** The EPA ’ s anal ys is does not fully support this contention. The use of natural gas to compl y with this regulation does increase modestly, b y about 3% in 2015. However natural gas generation in 2015 with this rule wi ll 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 7 3**  **:** Commenter 17815 notes that the short compliance timeline will jeopardize fuel diversity
. Commenter 16850 states that over the past 20 ye ars, 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 deplo y 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 activel y encouraging the development of renewable resources such as wind and solar. In order to provide Penns ylvania 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 rarel y dispatched. **Comment 7 4**  **:** S everal 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 clo se or be replaced b y 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. Commenter 174 03 coal

- fired retirements would have a significant impact on key midwestern and south Atlantic states. **Comment 7 5**  **:** C ommenter 17386 expresses concern that the proposed rule would decrease generation capacity by forcing earl y retirement of oil

- fired EGUs . This commenter believes that forcing earl y retirement of oil

- fired EGUs and the consequential decrease in generation capacity and sy stem reliability is contrary

to NERC ’ s objective to provide reliable service. **Comment 7 6**  **:** Several commenters (17701, 17791, 17 807) 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 opp ortunities to import power. The commenters note that fuel diversity is critical for electricity

reliability

in Florida, where suppl y problems may be particularly

acute during extreme339

weather events like the recent cold snaps and hurricanes, when supply of natural gas may

not be available for sustained periods of time. **Comme nt 7**  **7 :**  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 s ys tem 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 suppl y to repower resulting in necessary gas transmission upgrades that can be time consuming and costly . According to the commenter, the reality i s that the EPA ’ s own permitting rules present a time consuming obstacle to meeting the EPA ’ s deadline ye t 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 7 3**  **- 7**  **7 :**  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 analy sis 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 p lants 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 o f new capacity , transmission upgrades, and demand

- side strategies that can make over all compliance with this regulation much less expensive, and can be implemented relativel y 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. **Comment 7 8**  **:** 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 7 8**  **:** Sources can obtain an additional year to comply if necessary

for the installation of controls. Unavoidable delay s in obtaining permits necessary to install the controls would likely be sufficient to obtain the additional year to comply
. **Comment 7 9**  **:** 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 7 9**  **:** Sources that are existing sources on the compliance date for the final rule would have 3 ye ars to come into compliance. Generall y these are newer plants that have pollution controls and should be well positioned to comply with this regulation.340

**Comment 80**  **: C**  ommenter 17386 recommends that the EPA and generation owners collaborate to develop and meet timelines while monitoring equipment installation to avoid negative impacts of d elays that could occur. According to the commenter, such an approach would also ease concerns over grid security caused b y mass outages on generators to install the required equipment **Response to Comment 80**  : The EPA ’ s anal ys is does not confirm that MATS will result in any where near the extent of outages that this commenter projects, and several outside anal ys es have reached conclusions consistent with the EPA ’ s anal ys is. 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 8 1**  **:** Commenter 17930 stated that the EPA ’ s beyond

- the

- floor analysis [for Hg at facilities burning virgin low BTU coal] doe s not properl y 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 8 1**  **:** As stated elsewhere, the EPA b elieves that the data used to conduct the beyond

- the

- floor anal ys is are consistent with results achieved in U.S. DOE Hg control technology demonstration projects. The DOE ’ s National Energy Technology

L aboratory

(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/PRB

derived 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 favorabl y to the results of 70 to 90 percent achieved in the short

- term testing at the same in jection 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 normall y expected to exceed that measure d through an ESP. The EPA believes that its beyond

- the

- floor analysis is appropriate, including the costs anal yz ed. We do not anticipate any reliability problems due to lignite plants closing. Any shift away from lignite is made up for by other ty pes 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 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 8 3**  **:** S everal commenters (17627, 18034, 18037, 18907) are concerned that the reduced reliability resulting from the E GU MACT may result in an increase in emissions because industry will be forced to rel y 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 necess ary strategy to prevent or minimize the impact of reliability issues resulting from loss of capacity , however, then localized net increases in emissions would be341

expected. Rather than improving air quality , the commenters argue that this rule would directl y and adversel y impact citizens in the urban cores where emergency generation is ty

picall y 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 anal ys is. 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 merel y 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 up on. The commenter states that as the EPA was informed b y the State of Delaware in the RI CE 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 sourc es ” emit air toxics and are an increasingl y 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 b y cl eaner, 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 I SO
- RTO DR programs, particularl y 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, specificall y to prevent an increase in emissions. These generators are less efficient to operate than other sources and thus are l ess desirable economicall y as well as environmentally. The EPA does not expect that the Mercury

and Air Toxics Standards rule will substantially increase the use of these generators. **Comment 8 4**  **:** 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 variab le and often does not blow during times of peak energy use. **Respon se to Comment 8**  **4 :**  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 thi s 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 L aboratory

(NREL) on a complete update of the wind resource342

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 hourl y generation patterns for a representative day in winter and summ er. 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, an d. Table 4

- 22 of the IPM documentation on EPA ’ s website
. See IPM documentation. **Comment 8 5**  **:** Several commenters (17800, 17807, 17911) believe that the work practice standards will impact the reliability

of electric suppl y. These commenters argue that most E GUs 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). A ccording 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 8 5**  **:** 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**  **p ublic**  **p ower**  **u tilities**  **. Comment 8**  **6 :**  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 ca pacity wholl y owned b y 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 (ty pically 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 promul gated, 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 the343

larger, more qualified consulting firms. Additionally , several respondent s 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 generall y must receive approval from political bodi es, 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 c ould result in extended delays, including what one respondent called “hostile interventions. ” **Response to Comment 8 6**  **:** The EPA recognizes that 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 privatel y 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 8**  **7 :**  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 complianc e schedule established upon promulgation of the standards to appl y to an entire category or subcategory of sources. **Response to Comment 8 7**  **:** The EPA does not agree with the commenter that the CAA section 112(i)(3) paragraphs are inconsistent. CAA section 11 2(i)(3)(A) authorizes the EPA to provide up to 3 ye ars 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
- ye ar exten sion of the compliance period esta blished in the final rule if such time is necessary for the installation of controls.344

**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, 185 39, 19114, 19120, 19121, 19214, 9738, 19536/19537/19538, 18023 **1 . Opposition to**  **emission a veraging**  **compliance o ption**  **. 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 appro val is problematic as written. The commenter states that b ecause 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 f

acility is not exceeding the cap in the compliance equations in section 63.10009. According to the commenter, i f 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 du plicative 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 (NO CS), 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 plan s. **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 ex isting 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 unit

specific compliance. Ac cording to the commenter, averaging of units might facilitate state

- of

- the

- art highl y 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 b een recentl y installed, in effect giving credit for the installation of those controls.345

**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 owner s 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 increase d 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 c ommenter s ( 19536 , 19537 , 19538 ) states that the EPA should not perm it units to average emissions. According to the commenter s , 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 prohibi ted by section 112. The commenter s 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 c ommenter s point out that the agency ’ s discretion to construe the word “ source ” under the CAA is constrained b y the congressional policies underl yi ng section 112. Chevron, U.S.A . v. Natural Resources Def

. Council , 467 U.S . 837, 866 (1984). The commenter s 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 ba lance pollution

- reduction with economic considerations. See 42 USC section 7412(d). The commente s r assert that the agency has set most standards at the statutory minimum. According to the commenter s , section 112 does not allow the agency to permit addition al 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 (quarterl y) can provide a flexible, c ost - effective compliance approach
.346

**2 . Support**  **e missions**  **a veraging**  **c om** **pliance o**  **ption .**  **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 a gency 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 req uirement 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 compl y 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 b y 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 subj ect 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. **Re sponse 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.347

**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 emiss ions 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 emissio ns averaging. **3 . Request**  **expanded f**

**lexibility for emissions a** **veraging .**  **Comment 13:** Multiple c ommenters (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 th at facility

- wide limit. **Comment 14:** Numerous c ommenters (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 faci lity 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 easil y be accomplished by requiring the units to develop an emissions averaging plan, similar to the plan required for NO X emissions aver aging 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 17 928 further states that oil

based 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 commenter s ’ suggestions, and the rule continues to allow emissions averaging of a rate, not mass, from existing units within the same348

subcategory . EGUs in the same subcategory located at one or more contiguous properties, belonging to a single major industrial grouping, which are und er 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 co ntiguous 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 sc enarios 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 s ynthetic organic chemical manufacturing appropriate ly applied to electricity generation). Infact, 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. Co mmenter 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 consi dered 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:349

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 SOGMIemission points within a major source. Many major sources containing such points will also contain other points not covered b y 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 le g ally defensible. Similarly, allowing averaging between new and existing sources at the same facility would also likely lead to one source fai ling 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 include d 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 a gency 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 fi nal 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 owner s or operator s may not be able to avail themselves of the emissions averaging options (e.g. becaus e 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 1**  **7 :**  Several c ommenters (17623, 17627, 17689, 17736, 18037) state that limiting emissions averaging to onl y 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 emission s. 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 wil l 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 arbitrarin ess. 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 E PA 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 s ingle unit resulting in an exceedance of an applicable emission limit.350

**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 a ppropriate 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 2 0**  **:** 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 b y allowing an averaging plan that based on CEMS us age, 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 anal ys es . **Comment 2 1**  **:** Commenter 17705 stated that the availability of the alternate SO 2 stan dard 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 1 9**  **- 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 rul e no longer requires fuel anal ys es for pollutants. **Comment 2 2**  **:** 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 appli cable to “new or existing sources ” (emphasis added).351

**Response to Comment 22:** The agency acknowledges the commenters ’ support for emissions averaging and for the a genc y ’ 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 2 3**  **:** Commenters (17402, 17655) support weighting b y 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 2 4**  **:** 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 appl y 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 appli cable emissions limit. The rule does not include a discount factor. **Comment 2 5**  **:** 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 e xisting sources flexibility to achieve compliance at diverse points with varying degrees of add

- on control already in place in the most cost

- effective and technicall y reasonable fashion. This flexibility

is not needed for new affected sources because they can be designed and constructed with compliance in mind. **Comment 2 6**  **:** Commenter 17798 recommends initial emission averaging by utility ownership and state staged to facility averaging 2 ye ars 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.352

**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 day s after the unit’s first compliance date in the rule. **Comment 2 7**  **:** 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 ass ociated with emissions averaging from reduced emissions testing frequency. **Comment 2 8**  **:** Commenter 9738 states that the inclusion of an alternative compliance provision within the proposed rule that would allow owners and operators of existing affected sourc es 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 fiscall y for the new standards. The commenter states that second, if an owner or operator chose to selectivel y implement such technology, less work would need to be perfor med, as onl y 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 2 8**  **:** The agency appreciates the commenter ’ s support of emissions averaging within a subcategory
. **4 . Clarifications and**  **modifications to e missions**  **a veraging**  **. 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 som ewhat contradictory

and could be interpreted as requiring compliance in the first month of collecting data . Several c ommenters (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 3 0**  **:** Several c ommenters (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 states353

that if however compliance with an averaging plan were based on the average of 12 consecutive months, a f acility 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 comp liance 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 3 1**  **:** Several c ommenters (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 performanc e 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 no t clearl y 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 3 2**  **:** 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) appe ar to have a contradiction in dates (30 days vs. 60 day s), 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 ( on 180 days after [I NSERT DATE 3 YEARS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERALREGI STER] , or the date on which emissions testing done to support yo ur emissions averaging plan is complete (if the Administrator does not require submission and approval of your emissions averagin g plan), or the date that you begin emissions averaging, whichever is earlier). **Comment 3 3**  **:** Commenters 17648 and 17881 request clarification of emissions averaging provisions, w ith 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 arguabl y may allow sources with units in different subcategories emitting through the same stack to average em issions to demonstrate compliance, without clarifying that all of the other relevant averaging provisions, such as the emissions cap, appl y. **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 onl y 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.354

**Comment 3 4**  **:** Several c ommenters (17705, 17718, 17737) state the EPA should clarify in sections 63.10009(e)(1) (initial compliance, includes SO 2 ) and 63.10009(f)(1) (continuing c ompliance, no mention of SO 2 ) that the SO 2 surrogate limit as an alternative standard for acid gases can be used under the emissions averaging compliance option. **Response to Comment 34:** The agency agrees with the commenters ’ suggestions, and the rule has b een revised to include SO 2 as eligible for emissions averaging. **Comment 3 5**  **:** Commenters 17623 and 17775 suggest the EPA include more flexibility in the submission timing of the emissions averaging plan, and notes that submittal 180 day s prior to compliance is a lengthy l ead 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 ’ re quest, and the rule has been revised so that an emissions averaging plan must be developed b y 3 ye ars 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 3 6**  **:** Several c ommenters (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 contractuall y commit to an emissions averaging program similar to the original NO X compliance program under the Acid Rain Program. **C omment 3**  **7 :**  Several c ommenters (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 on e 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 pro vision 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, and the rule now allows a 90
- boiler operating day rolling average period for mercury emissions from EGUs in the EGUs designed for coal ≥ 8,300 Btu/lb subcategory that are included in an emissions averaging group, along with the existing 30
- boiler operating day rolling average perio ds for other pollutants in other subcategories
. 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 pe riods of startup or shutdown, s o the request to lengthen the averaging time to account for such periods is moot
.355

**Comment 3 8**  **:** Several c ommenters (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., PM, HCl or Hg) are being used to determine compliance with the limits, values from those monitors co uld 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 devi ces in proposed 40 CFR 63.10022. **Comment 39**  **:** Commenter 17718 states that if SO 2 data via CEMS is being gathered for comparison with the acid gas alternate SO 2 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 SO 2 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 (or 90) 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 4 0**  **:** 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 h eat 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 fl exibility , and the rule has not been changed. **Comment 4 1**  **:** 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 th at 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 4 2**  **:** 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 co ntrol 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 a gency 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 n eeds 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 w ould be required to provide.356

**Comment 43 :**  Commenter 17718 states that the EPA should clarify why the presence of an ESP would require monthl y fuel content determinations. **Response to Comment 43:** The comment is moot, as the rule no longer requires fuel analysis for pollutants. **Comment 4 4**  **:** 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 4 5**  **:** 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 4 6**  **:** Commenter 17730 states that the emissions averaging plan i s 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 4 7**  **:** 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
. Moreover, as discussed in the preamble, the rule now allows EGUs designed for coal ≥ 8,300 Btu/lb subcategory that are included in an emissions averaging group for Hg emissions a 90

- boiler operating day rolling average period. Should an EGU owner or operator disagree, he or she should choose another compliance demonstration method. **Comment 4 8**  **:** Commenter 17775 opposes the requirement for the source to document the ty pe, design, and operating specifications of the control devices installed on the effective date of the rule if performance test results are not available.357

**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 is in place 60 days after the publication of the final rule. Acco rding 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 a s emissions test results, to be available within 3 years after promulgation. **Comment 5 0**  **:** 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 CE MS 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 5 1**  **:** 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 th e 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 configuratio n 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 f actors in deciding whether or not to use emissions averaging as a means of demonstrating compliance. **Comment 5 2**  **:** Commenter 17881 states that the EGUs located at a single stationary source may

not always have identical owners and/or operators contrary to se ction 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 eliminat e any

possible confusion in the future.358

**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 5 3**  **:** 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 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 Co mment 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 5 4**  **:** 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, specificall y, 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 theoreticall y 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 o r 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 5 5**  **:** Commenter 17881 states that the term “heat capacity” is improper in context of section 63.10009(f)(1) and (2), as heat capacity generall y 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 currentl y 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 monthl y 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 5 6**  **:** Commenter 17881 states that in sectio n 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, it359

may be appropriate to include additional equations which u se 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. **Comment 5 7**  **:** 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 averag ing 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 5 8**  **:** Co mmenter 17881 states that section 63.10009(h) does not include SO 2 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 SO 2 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 6 0**  **:** 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 b y onl y EGUs eli gible 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.360

**Comment 6 1**  **:** Commenter 17881 requests that the heat input/steam output record s as required by section 63.10032(e) should be kept on a monthly instead of dail y 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. **Comment 6 2**  **:** Commenter 17913 states that the emissions averaging demonstration should only be based on an averaging period consi stent 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 peri od. 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. **Respons e to Comment 62:**  The agency agrees with the commenter’s suggestion to clarify how compliance is demonstrated. As rule contains a quarterl y compliance assessment based on results of quarterl y emissions tests for EGUs that use emissions testing and of 30 (or 90, as discussed elsewhere) boiler operating day

rolling averages for EGUs that use CEMS (or sorbent trap monitoring for Hg emissions), the rule has been revised to stress compliance with the 30 (or 90, as discussed elsewhere) boiler operating day

rolling averages for those EGUs that rel y on CEMS (or sorbent trap monitoring systems for Hg emissions) . Note that this means the quarterly emissions testing value is used during the quarter to assess compliance with emissions limits . Should an EGU owner or operator find such an approach problematic, he or she should choose another compliance demonstration option. **Comment 6 3**  **:** 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 l arge 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 be fore 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 all ows 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**  **d iscount**  **f actor**  **. Comment 6**  **4 :**  Numerous c ommenters (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, imposi tion of a discount factor effectivel y 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 ty pes of units engaged in averaging. The commenters states that361

the EGUs covered b y this rule are fairl y homogeneous, and the current proposal does not allow averaging between units of different subcategories. Commenter 17904 states that a discount factor will simply ac t as a deterrent to emissions averaging. **Comment 6 5**  **:** 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 b y 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 ty pes 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 so urces 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 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 so urces. **Comment 6 6**  **:** 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 F R 19430. The commenter states that more recentl y, the EPA relied upon its reasoning in the HON Rule to appl y the 10 percent discount in the emissions averaging provisions for IC I Boilers (see 76 F R 1561 9; 75 F R 32035), and that its decisions in the HON and IC I 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 6 7**  **:** 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 6 8**  **:** Commenter 17 768 states that appl ying 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 publ ic. **Comment 69**  **:** Commenter 17928 states that averaging provides valuable flexibility but is already constrained b y 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 6 4**  **- 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 onl y in the fuel used to362

produce electricity. The agency believes that difference is accounted for in this rule by prohibiting units from differing su

bcategories

– 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, particularl y for l ittle 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 d**  **iscount f**  **actor .**  **Comment 7 0**  **:** 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 controlled aggregatel y to a degree no less stringent than they would need to be controlled if they were controlled individu ally
. In failing to incorporate a discount factor, Commenter 17648 states the EPA may unfairl y 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, sing le 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 99 th UPL for facilities that average would be closer to the actual average of the top 12 % than the 99 th 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 control s 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 7 1**  **:** Commenter 1764 8 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 IC I Boiler NESHAP undercuts the EPA ’ s rationale for not proposing a discount factor in the Toxics Rule. Inthe IC I Boiler NESHAP, commenter 17648 states that the subcategorization reduced variation among sources within the subcategory , and that NESHAP nonetheless retained a discount factor. 76 F R 15 612. Commenter 17648 s tates 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, b y 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 7 2**  **:** 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.363

**Comment 7 3**  **:** 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 7 4**  **:** Commenter 17718 states that imposition of a discount factor effectivel y 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 7 5**  **:** Several c omment er s ( 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 anal ys is 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 effectivel y allowing compliance to be measured based upon a far larger number of test runs, and operating hours

– over which there will be far less variability and thereb y 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, esta blish 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 allo ws units to combine their emissions for purposes of compliance, it should re

calculate the variability associated with multiple

- unit emissions, and establish a corresponding “ discount” in the standards for multiple units. **Response to Comments 70 -**  **75:** The ag ency 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 ag ency 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 anal ys es was developed to take factors such as those mentioned by the commenter into account. **7 . Facility**  **a veraging**  **p rovisions**  **s hould**  **be m**  **odified to allow for a**  **lternative mass l** **im its**  **. Comment 7**  **6 :**  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 unlikel y 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 e ach 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 7 7**  **:** Comment er 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 rat e, the emission rate364

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 c ommenter presented Example 1 below of a hy pothetical 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 b y 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 bas is. According to the commenter, the facility is therefore penalized for emitting less. 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 actuall y 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 currentl y 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 hourl y heat input of the unit over the course of a ye ar (included in document). The commenter states that both o f the proposed changes to the facility averaging provisions listed above fit squarel y within the generall y applied limits on the “ scope and nature ” of past rulemakings where facility averaging is allowed. The commenter asserts that if the EPA is serious ab out 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 f actor, 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 it365

would be inappropriate to introduce a new emissions limit based on mass only wi thout 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.366

**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 , 1953 7 , 19538, 18023 **1 . Coal**  **s witching**  **. Comment 1:**  Several c ommenters (16705, 17400, 17697, 18038, 18575) point out that the proposed rules assume that all coal ty pes 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 suppl y 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 b y 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 suppl y 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 significantl y 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 b y some facilities. Low sulfur sub

- bituminous is now widely available and is burned across the contiguous U.S. states to comply with SO 2 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**  **f**

**uel switching to n**  **atural g**  **as .**  **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.367

**Comment 6:** Commenter 17881 states that exclusive use of natural gas at Consumers Energy ’ s Karn ’ s Oil/Gas Fired Units

– 3 & 4 (currentl y 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 o f 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 onl y 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 MA CT, 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 properl y 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 every where 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 b y some facilities. However, the EPA maintains that control technology

options are available to retrofit existing facil ities to allow them to meet the existing source emission limits without having to switch fuels. **3 . Concerns**  **with a bility to**  **m eet**  **l iquid**  **f uel**  **- f**  **ired l** **imits .**  **Comment 9:** Commenter 17912 disagrees with the EPA ’ s suggestion that oil

- fired units have the complian ce option of using low

- HAP oil, citing that the EPA fails to identify any where in the ICR fuel data any oil sufficientl y l ow 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:368

a. The concentrations of metals and chlorine in coal can be measured, but are generall y below anal yt ical detection limits for residual oil. The commenter states that during IC R testing, quantif iable levels of chlorine were detected in the fuel used b y just two of the eight EGUs tested and nickel was the onl y 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 poss ible (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 e lsewhere in this document, EPA has reassessed its anal ys is 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**  **c onversion of**  **l iquid**  **- f**  **ired 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 conversel y, the storage of DFO does not require heated s ys tems. b. According to the commenter, combustio n 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 phys ical characteristics, the combustion process equipment is designed and installed t o reflect the characteristics of the fuel being combusted. The commenter states that boiler burners and burner tips used to combust RFO cannot b e 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 conversel y, combustion of DFO does not require an atomization system.
c. According to the commenter, an EGU using RFO will not have the same out put (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.369

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 sy stem, including replacement of burners and burner tips and modifications to the burner management sy stem. The commenter states that prior to performing the phys ical changes, a boiler combustion study must be performed to ensure the burners are properl y 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 l ower 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 s ys tems 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 signifi cant 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 relativel y 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/install ed 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 29,0 00 barrels of DFO is over $500,000, based on the 5

- ye ar average price presented (Commenter included Table 2.3.2, Five

Year Average Fuel Prices at New York Harbor, Docket No . The EPA

- HQ
- OAR
- 2009
- 0234). k. The commenter states that beyond the capital expendi tures 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 generall y high on the supply

curve due to their relativel y high heat rates, they are primaril y dispatched for reliability at a low level in preparation for spikes in demand (when their out put 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 c osts during times of sy stem duress.370

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 DFO
fired 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 indic ate 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 b y residual oil

- fired EGUs without the n eed for oil switching, although such switching is alway s an option to an EGU that does not want to install PM controls. **5 . Opposition to**  **u se of**  **p roposed**  **r ule/** **l imits to**  **necessitate f uel**  **s witching**  **. 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, b oilers are designed for specific ty pes of fuel, as well as ranks within a fuel type, and there are limits due to the heat values and amount of coal being burn ed that restrict lignite power

-plants from increasing non

- lignite coal consumption. The commenters state that the se 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 fu el 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 typ es and construct this infrastructure is incomplete and provides the following points as flaws in the EPA cost analy sis:371

a. According to the commenter, the EPA ’ s cost estimate does not include all requisite infrastructure costs (e.g., dust collection, conve yors, 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 adequatel y 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 th e EPA fails to include the cost of installing fabric filters in the price anal ys is. The commenter states that the EPA ’ s cost anal ys is 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 anal ys is determines the marginal capital costs attributable to the BTF option requiring installation of ACIs ys tems 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 c osts onl y counted once. **Response to Comments 1 2**  **- 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. C ontrol 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 . Reques**  **t for e**  **xpansion of p**  **rovisions for e**  **xclusion from r**  **equirements .**  **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 ye ars 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 immediatel y following promulgation of the final rule, or 15 percent during any one of those ye ars, 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. Comm enter 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 f ired” unit (76 FR 25020) seems to require that the372

owner phys icall y 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 cap able 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 ga s 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 ce ases 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 appl y for a permit revision to c omply 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

- ye ar requirement of 10 percent heat input. **Comment 17:** Commenter 17756 recommends that the EPA revise the definition to change the “ look

back” 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

- ye ar average for the ye ars 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:** C ommenter 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 actuall y burns 90 percent natural gas during a calendar ye ar 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

- ye ar 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 b y the compliance deadline and373

continue to operate that way thereafter should also not be subject to the oil

- fired EGU MACT requirements. **Response to Comments 1 5**  **- 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**  **- y**  **ear e**  **xtension for c**  **om pliance**  **. Comment 22:**  Commenter 17852 concurs that a 1

- ye ar extension can be appropriate when a utility is undertaking a technicall y 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 ye ar to comply . Commenter adds that there are many things that utilities can do to achieve compliance within the 3

- ye ar time

- frame, and cites the following:
a. Various sources have suggested that controls can be installed within the 3

- ye ar 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 ty pe are provided in the preamble to the final rule. **8 . Blending**  **f**

**uels .**  **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 ci tes 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 oi l 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 th at 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 ye ars or any one of those calendar ye ars, 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 arguabl y fall into the solid oil

- derived fuel subcategory
.374

b. The c ommenter 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 exclusivel y, in any combination together, or in any combination with other fuels in any amount. ” Commenter 17774 urges the EPA to clarify which standards appl y to units burning coal and petcoke and suggests that the EPA require affected sources to comply with the standard applicab le to the majority of fuel burned (e.g. , greater than 50 percent). **Comment 24:** Several c ommenter s ( 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. ” Commenter s state that EGUs designed to fire solid fossil fuels burn a mi xture of coal ty pes as well as other solid fuels including solid oil

- derived fuels (petcoke), biomass, and other solid fuels. Commenter s suggest that any subcategorization must be based on design differences which materiall y affect the availability of cleaner fuels, or other methods of reducing pollution. Commenter s 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 primaril y fossil

- fueled. Commenter s concur with the EPA ’ s proposed rule definiti ons 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 comb ination w ith other fuels in any amount (76 FR 25122, Proposed section 63.10042 definitions). The commenter s state that “ Fossil fuel

- fired, ” in turn, is defined as, “to the extent that an EGU that is capable of burning primaril y coal or other solid fossil fuels to g enerate 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. ” Commenter s add that this is particularly

important for biomass, as burning green wood pro duces more of various regulated HAP than does burning coal (Commenter s cite Figure 1 in Docket No . The EPA

- HQ
- OAR
- 2009
- 0234). Commenter s 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 qui ckly to provide clean energy

and an immediate pollution reduction. In addition to significant HAP reductions, the commenter states that emissions reductions in NO X and SO 2 can be realized from fuel switching (coal to natural gas) in the power generation se ctor. Commenter recognizes that the EPA may not consider it realistic to require all coal plants to shift to natural gas b y 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 IPM375

runs commissioned by

commenter and review of the EPA ’ s IPM results. Commenter cites that the EPA shows in the IP M results that no new pulverized coal capa city 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, suppl y, 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 cos ts cause a unit ’ s total incremental cost of electricity

(COE) to be significantl y 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 Docum ent [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/epa

ipm/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 address es the natural gas suppl y issue, and cites several references to the contrary (Docket ID No . The EPA

- HQ
OAR
- 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, especiall y during peak demand (e.g., the heating s eason). 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 suppl y t o 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 ye ars. i. According to the commenter, the EPA ’ s anal ys is of costs of constr ucting new laterals to distribute gas to existing coal

- fired units demonstrates that some coal

- fired power plants have relativel y inexpensive access to natural gas mainlines, while other coal

- fired power plants will have a more difficult time accessing nat ural gas mainlines, but the anal ys is 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 acces s 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 recentl y 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.376

iii. The commenter states that according to the U.S. EIA, “the U.S. natural gas pipeline network is a highl y integrated transmission and distribution grid that can transport natural gas to and from nearl y 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 ye ars. vii. The commenter states that according to a recent report issued b y the MIT Energy Initiative on the Future of Natural Gas ( “ MI T 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 ye ars; between 2005 and 2008, pipe line capacity additions totaled over 80 billion cubic feet per day (Bcfd), exceeding those from the previous four

- ye ar period b y 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 anal ys is 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 comparativel y low cost; and (c) increased utilization of existing NGCC power plants provides a relativel y low

- cost short

- term opportunity to reduce U.S. carbon dioxide emissio ns by up to 20 percent in the electric power sector and significantl y reduce sulfur dioxide, nitrous oxide, particulates, and mercury with minimal additional capital investment in generation and no new technology requirements. viii. The commenter states th at 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 sta tes 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 ye ar and reached record levels in November. ” ix. The commenter states that generall y speaking, estimates of the available domestic supply of natural gas have expanded significantl y over just the past five ye ars. According to the commenter, in a 2009 Report addressing the supply of technicall y recoverable natural gas in the United States at377

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 recentl y estimated that annual production of natural gas will increase b y 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 d eposits 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 prod uction is likely

to increase significantl y. According to the commenter, as summarized in a recent report issued b y 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), an d 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 (I CF Figure 1 included in Docket EPA

- HQ
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- 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 suppl y 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 maximi ze 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 lev els 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 som e areas; whereas, commenter pos its that it establishes with the above references that natural gas is widel y 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 compared378

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 say s 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 inherentl y lower emitting p rocesses, 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 dramaticall y expanded U.S. natural gas reserves and infrastructure have reduced gas price volatility (citing several references in the Docket EPA
- HQ
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- 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 ty pes 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. In creasing 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
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- 2009
- 0234) to support this point:
a. Commenter 17852 states that, in comparing costs for fuel switching to natural gas, the EPA onl y focuses on one typ e 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 c oal 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 anal ys is also ignores the possibility of co

- firing natural ga s 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 anal ys is ($5.74/MMBtu), increasing the379

use of av ailable 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 state s 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) onl y 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 oil

fired subcate gory, 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 p ower 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 ga s 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 onl y 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 dramaticall y increasing natural gas prices (Figure 1, 2010 to 2011 Annual Energy Outlook of the EIA included in Docket EPA

HQ
- O AR
- 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 EP A 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 onl y a 33% capacity factor. If onl y 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
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- 2009
- 0234).380

h. Commenter 17852 cites that the MIT report also found that there is sufficient surplus NGCC capacity to displace roughl y one - third of U.S. coal generation. The commenter states that according to MIT, substitution of this NGCC capacity would reduce CO 2 emissions from the power sec tor b y 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 s ys tem. ” 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 p lants 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, especiall y during peak demand (e.g., the heating season). ” Commenter points out that the development of shale gas has vastly increased onsh ore gas production, gas storage capacity has increased over the last few ye ars, 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 ty pes 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 po ints:
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 dramaticall y improved over the last 5 ye ars, and the lead time to respond to increased demand has been significantl y 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 natur al 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 availa ble 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 relativel y 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 ye ar from381

2000 to 2006, and in the years from 2006 to 2010, U.S. shale gas production grew b y 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 increas ed demand from the EGU sector into the future. f. Commenter states that the EPA ’ s anal ys is on fuel switching is flawed because it mistakenl y presumes retired generation must be replaced b y building a gas

- fired unit in the same footprint. According to the c ommenter, 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 demonstrat e that concerns over natural gas availability

and abundance are unfounded. The commenter states that according to the July US EIA Natural Gas Monthly report, “nearl y 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 rat es of natural gas continue to grow. Commenter 17853 states that an immediate HAP benefit to the environment can be realized b y 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 accuratel y 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, SO 2 , NO X , CO 2 , 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 directl y towards a corresponding decrease in coal

- fired generation. **Response to Comm ents 2**  **5 -**  **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 fo r 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 emission s 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 generall y stable, and that the availability of natural gas is expanding. One commenter even notes that one study

specifically

considere d such issues in the context of the proposed EGU NESHAP. Even assuming all the studies are accuratel y characterized, the results do not in any way support a determination that conversion of all coal

- and oil

- fired EGUs to natural gas is cost effective or that the382

supply and transmission capabilities are sufficient to support such a conversion. The commenters maintain that the supply

is currentl y sufficient and that the transmission capabilities are expanding, but no commenter indicates that the current sit uation (or the situation within three ye ars) would allow a wholesale conversion to natural gas. The highest estimate provided b y commenters is that one third of the coal

- fired generating capacity could be replaced. Even being able to replace one third of the coal generating capacity

with natural gas **,** this clearl y falls short of the amount of fuel switching that would be necessary

to set a beyond the floor standard at levels that would require all existing coal units to switch 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 a ppear 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 not 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. **10 . Concurrence and**  **c aution**  **for d**  **elegation of s**  **tate p**  **rograms .**  **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 ultimat ely 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 closel y 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 th e 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. **11 . Concerns from**  **n on**  **- continental EGU s**  **ources .**  **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 n atural gas resource in Hawaii. The commenter states that a s 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 of383

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 primaril y b y blending and some sulfur removal. However, they do not and cannot economically

control for metal content. The commenter states that a s 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 prop osed 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 ty pe boilers is currentl y being researched and is not a commerciall y 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, S iemens, 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 currentl y 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

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2009
- 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 is land (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 b y the erratic HCI measurements made during the IC R testing (HCIemissions varied b y 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 ter m plan involves participation in expansion of a local LNG facility operated b y EcoEiectrica and activel y pursuing installation of a NG pipeline. The commenter states that engineering evaluations and permitting for the pipeline is underway , but completion h as not been established yet. **Response to Comments 29 -**  **30:** As noted elsewhere in this document, the EPA is establishing a non

continental liquid oil

- fired subcategory in the final rule.384

**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**  **t esting**  **. 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 conduc ted 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 b e revised to clarify that an affected source may

elect to perform and/or rel y 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 sh ould 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 E PA 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 perfo rmance 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 t esting should be no more frequent than every 6 months. **Response to Comment 3:** The final rule does not contain the proposed fuel sampling and analy sis compliance demonstration approaches. See the final preamble and discussion under Comment Code 5A. The final rule uses either CEMS, where applicable, quarterl y performance testing, reduced testing under385

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 requir ement 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 m ethodology**  **. Comment 5:**  Commenter 17621 provided discussion of testing methods recommended for IC R 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 anal ys is for the specific source and anal ytical 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 anal ytical method. The commenter states that based on EPRI ’ s reviews of many ICR Part III test reports, almost all samples were anal yz ed 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 sufficientl y above the background sorbent mercury level. The commenter states that test runs with loadings below 10 nanograms generall y failed method quality criteria for one or more of the three samples. Commenter 17621 states that EPRIhas classified the adequacy of Method 30B to measure at the proposed MACT limit for new coal EGUs as uncertain b ased 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 accuratel y 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 predominantl y filterable PM, the above methods will b e able to measure accuratel y 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 accuratel y b y gravimetric anal ys is and whether the overall method accuracy , considering sampling variability , will be adequate at that emission rate is unknown. Commenter adds that field studies conducted b y EPRI and others have identified problems with the accuracy of Method 5 at low emission levels. According to the commenter, results386

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 th e 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 p robe and filter also affects the amount of filterable PM collected, with the lower temperature collecting more filterable PM. The commenter states that the IC R Part III data include tests conducted at two different temperatures (250 °F and 320 °F) and with both ty pes 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 emi ssions are predominantl y 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 accuratel y b y gravimetric anal ys is, 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 condition s (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 O TM
- 28 determined that modifications from the original Method 202 had reduced the positive bias due to aqueous

- phase conversion of gaseous SO 2 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 effectivel y. 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. Acco rding 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 anal ys es need to be above the minimum detection limit to provide reliabl y 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 influence s. 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 matter387

measurements when the quantity of material coll ected 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 ro utinely 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 propose d. 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

- ho ur 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, u se of a PM filterable surrogate would also allow a direct compliance determination via the u se 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 concurrentl y quantify filterable PM and the non

- Hg metals which we are regulating. The final rule uses a PM CP MS 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 filterabl e 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 currentl y 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 separatel y for compliance with different federal particulate limits based on these temperature differences, adding to the testing workload.388

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 CEM S 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 H g 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 SO 3 on the filter and the collection in the impinger provides for more consistency in obtaining constant weights. Since little or no SO 3 is retained on the filter, the highl y hydroscopic SO 3 does not cause weighing difficulties by absorbing water from the air . Also, by moving the SO 3 to the impinger, the SO 3 can be neutralized and thereb y 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. **C omment 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 b y M ethod 5, be conducted at a filter temperature of 25 0 °F. Commenter adds that filterable PM measured b y M ethod 5 at 250 °F is expected to provide different (and higher) results than filterable PM measured b y M ethod 5 at 320 °F, because of the condensation of sulfuric acid at 250 °F. According to the comment er, consequently , a mechanism is needed to allow EGUs required to perform Method 5 tests at 250 °F to concurrentl y demonstrate compliance with the proposed PM limit based on a Method 5 filter temperature of 320 °F. Commenter 19033 suggests the following me chanism 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 th e 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, Comm enter 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 o f 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**389

**the Method 5 tests are required to be conducted at 250°F, the operating lim**  **it 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 c ommenters (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 temperatu re. 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 s tates that sources with SO 2 or SO 3 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 3 0B 4 hour test runs that met all QA criteria with a catch under 10 nano grams . 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 u nreliable or**  **i nadequate**  **. Comm**  **ent 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 trul y standard collection hardware, conditions for the separation of the water and sample gas, temperature for collection and anal ytical 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 i f 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.390

**Response to Co mment 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 wi ll cause even CEMS that are operating properl y 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 potentiall y inconsistent enforcement practices. The commenter states that non

- Hg HAP metals compliance provisio ns 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 Ta ble 4 of the proposed rule, as well as section 63.10005(d)(4), indicate use of the SO 2 surrogate is predicated on the EGU both being equipped with wet or dry FGD and using an SO 2 CEMS for the compliance determination but that section 63.10006(h) applies to those solid oil

- fired and coal

- fired EGUs without SO 2 CEMS but with wet or dry FGD controls. The commenter states that such EGUs are required to conduct SO 2 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 SO 2 testing at least every other month. The commenter states that this paragraph is confusing, as SO 2 is being treated as a regulated pollutant even though its use as a surrogate would appear to be barred in the absence of an SO 2 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 SO 2 CEMS, as such CEMS are generall y 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 r ule such that only

the HCl testing would be required under such circumstances. **5 . Test**  **r equirements**  **. 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 would391

require testing every

other month, which is unjustified and costl y. This commenter also states it is unclear how compliance is determined under the multiple testing scenario. **Comment 16:** Commenter 17796 supports t esting for filterable particulates as well as condensable PM. **Comment 17:** C ommenters 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 SO 2 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 co mply 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 EGU s 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 pro vided 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 s urrogate (i.e., SO 2 ) and the associated HAP (i.e., HCl) even though the surrogate cannot be relied upon for compliance for solid oil

- fired and coal

fired EGUs without a SO 2 CEMS and without wet or dry FGD controls. Commenter 18498 states that the requireme nt 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 onl y 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

o ne 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 th e 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 onl y app lies to392

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 IC R if they

feel it is necessary

to collect additional data on the relationship between PM and non - Hg HAP metals emissions. **Response to Comment 1**  **5 -**  **17:** We agree that a reduction in the frequency and typ es 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 respon se 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 quarterl y, 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: C**  ommenters 18014 and 18498 state that the minimum sampling time of four hours required b y 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 provid e 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 en couraged to perform an assessment of the ability of an alternative sampling duration, sampling rate and anal ytical 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 compl ying 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 is sue 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 l imits should be applied based on the majority of fuel actually

combusted annuall y on a heat input basis.393

**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 annu al 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 th ese include chloromethane formed b y action of sunlight on marine biomass and chlorine from sea foam, possibly

influenced by

wind direction. **Response to Comment 2 1**  **:** 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 anal ys is or provides certification from a fuel supplier and that analysis or certification shows fuel moisture content does not exceed 1 percent
.394

**5C05 -**  **Compliance: Treatment of Common Stacks Commenters**  : 15678, 17733, 17739, 17775, 17781, 17796 **1 . Unit** **- by** **- u**  **nit c**  **ontrol .**  **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 especiall y 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 strongl y supports appl ying 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 b y having all IB units at a source appl y 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**  **c om** **bin ed**  **s tack**  **d ata**  **. 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 th e 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 sep arately , 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 c ommenters ( 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 thi s incorrect approach inconsistently. While it may be acceptable for395

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 a pplying 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 sparsel y populated. C ommenter 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. C ommenter also states that counting as two a single stack may dampen variability unlike the EPA ’ s claim in the Boiler MACT . C ommenter states that the practice of treating plants that have multiple boilers exhausting through a single stack as if they were separate sources is fairl y s ys temic and results in a widespread population of the database with fictional values. Commenter 12991 disagrees with the use b y 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 best

performing 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 valu e 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 1396

& 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 Comment s**  **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 us ed 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 analy sis, 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 MAC T anal ys is. The I CR required owners or operators to provide the a gency with information from individual EGUs, and those owners or operators certified the results submitted to the agency as being true, accurate, and complete. The a gency

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 maint ains its use of submitted data for rulemaking purposes remains valid. **3 . Common**  **stack p rovisions**  **. Comment 5**  **:** Several commenters (15678, 17733, 17796) support the approach of appl ying the most stringent standard to each EGU when they share the same stack an d/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. **Respons e to Comment 5**  **:** We agree with the commenters and have included such requirements in the final rule. **Comment 6 :**  Commenter 17775 state s 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 emissi on 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) b y providing a 12

- month rolling average compliance period and should provide the same for common stack units that use averaging to comply
.397

**Resp onse 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 t esting in the ductwork prior to the common stack so as to measure emissions from the individual EGUs. **Comment 7 :**  Commenter 17781 state s as currently written, paragraphs (h), (i) and (j) do not seem to address the likel y situation where each of the EGUs ass ociated 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 o f multiple and different testing frequencies appl ying 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.398

**5C06 -**  **Compliance: Startup, Shutdown, an d 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, 179 02, 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 a pplicab**  **ility d**  **uring SSM .**  **a . Support or**  **o ppose SSM**  **a pproach**  **. 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 a

pplicable 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 readil y 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 tes t 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 devi ce
– are effectivel y 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:399

 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 ec onomically 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, 17 736, 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, 1773 6, 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)  In cluding 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 sho uld 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. Ruck elshaus (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. Inthe 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 s hutdown, 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 shutdo wn 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 emission400

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. **Res ponse 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 handle d 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**  **e xperience**  **. 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. Accordingl y, 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 cir cumstances.” **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**  **a ble to**  **a chieve the standard**  **. Comment 9:**  Multiple c ommenters (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 ev en 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 b e 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 h ave fewer emissions.401

 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.  Comment ers (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 significantl y higher emissions and also a smaller number of operating hours.  Commenter 17767 s tates that if a unit that experiences a difficult, lengthy s tartup, 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 o f 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 n ot**  **s ufficient**  **. Comment 10:**  Commenter 17904 believes the EPA has taken a positive step in establishing a 30

- day average. Commenter 19121 generall y 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 exp erienced b y 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 c ommenters (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 varyingload 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 a ssumption.  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 wi ll be problematic for the averaging period. **Comment 13:** Commenter 17740 states that EPA ’ s statement that EGUs “ do not normally startup and shutdown frequentl y” effectivel y, and incorrectl y, assumes that all units are operated as base load units. As the Sev enth 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,402

and unpredictabl y, 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 newl y constructed. Thus, an older EGU with highl y 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**  **p lant**  **o perations/** **o utages/**  **d escribe SSM**  **p eriods**  **. 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 co nsider 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 startup s 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 b yp ass times allowed in their Title V permit in 2010. Commenter 17795 states that their units startup and shutdown frequentl y, 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 SO 2 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.403

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 maint enance, 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. Co mmenter 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, 1 7923) 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**  **u nits**  **. Comment 15:**  Several c ommenters (17725, 17820, 18014, 18498) state that even with relatively long averaging periods (30

- day rolling averages), the emiss ions from nonrepresentative periods could significantl y affect averages, especially for peaking units or other units that come online and offline frequentl y. 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 wor k 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 b e 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 peri ods. Commenter 17623 states the EPA ’ s anal ys is 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 ty picall y startup and shutdown frequently, how ever, that is changing and cite a new nodal s ys tem in Texas that may

increase the frequency

of startup/shutdown events. Commenter 17795 states that recent404

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 (1775 8, 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 emi ssions due to renewable facility operation. Commenters (17758, 16849) state the EPA should not penalize environmentally friendl y 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 simp le 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. **R esponse to Comments 1**  **5 -**  **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 p lan/**  **s uggested**  **startup/shutdown a**  **pproaches .**  **Comment 19:** Commenter 17316 recommends that facilities establish a maximum allowed duration for startup/shutdown periods in the Monitoring Plan. C ommenters (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**  **c lear**  **h ow SSM**  **i ncluded/** **n o**  **b asis for**  **s tandard**  **. 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)405

 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 anal yz ed 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 appl y 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, 17820,1 7870, 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 coll ected 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 l imited 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 1 9114 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 appropriatel y 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 th at 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 anal ys is of this406

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 malfuncti ons is discussed in the preambles to the proposed rule and this final action. **ii . The EPA**  **n ot**  **d emonstrated that**  **l im** **its are a**  **chievable .**  **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 emissio n standard is lower than the rate “ achieved in practice ” by the best performing units. Commenter 17761 states that the EPA inappropriatel y 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 b y 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 th at a single standard can be met at all times, including startup/shutdown periods. Commenter 17737 states that EPA provides no data or anal ys is to demonstrate that coal

- fired EGUs will be able to meet the standard including SS periods. Commenter 17851 state s 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 anal ys is. **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 anal ys is 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 b y use of a 30 day averaging period is not supported b y 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 unpre dictable startup emissions. I f the EPA cannot demonstrate, then407

commenters (17724, 17876, 19032) state that startup/shutdown periods should be excluded from 30

- day averages. **Response to Comments 2 1**  **- 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 o utage**  **. 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 p recipitated 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 seasonall y, 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 C omments 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 section 4D02 of this document
. **iv . Burner**  **inspection r equirement**  **. Comment 25:**  Several c ommenter s ( 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. Commenter s 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 sam e 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 anal yz e data for emission standards during SS(M). Comment er 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 anal yz e excess emissi on reports to determine the frequency of startups/shutdowns and include that analy sis in the standards.408

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 appl ying adjustments to the limits to allow for difference s 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**  **c omponent**  **. Comment 27:**  Several c ommenters (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 emis sions 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 comp onent could be drasticall y 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 th e proposed rule and this final action. **j . SSM**  **r esults in**  **i ncreased**  **e missions/**  **d istinct**  **o perating**  **m odes**  **. Comment 28:**  Commenters 17730 and 17740 state SS(M) periods are distinctly different modes of operations fro m 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 1787 8 states that SSM periods result in increased emissions rates. Several c ommenters (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 c ommenters (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.409

Commenter 18023 states that startup is a distinct operating period and it should be considered independentl y. Commenter 18023 provides Hg CEMS data showing two distinct emission profiles for periods of startup (when SCR is offlin e due to low temperature) and for periods of steady- state with full control (when both SCR and FGD APCD sy stems 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, whi ch 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 compl y 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 CO 2 diluent of 5 percent), which is 16 times higher. Commenter 17795 provides average SO 2 emis sions 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. **Resp onse 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 a gency also believes EGU owners or operators strive to minimize periods of malfunction and should a malfunction period occur, its duration will be brief, as410

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 du**  **ring s**  **tartup/ s**  **hutdown .**  **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 CEM S 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 onl y 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 significantl y 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 dyn amic plant operations. Commenter 17677 questions the enforceable value of these data, and states the EPA needs to consider the ability for CEMS to accuratel y monitor emissions in startup/shutdown periods. Commenter 17772 states the PM CEMS data from startups/s hutdowns are not reliable and highl y 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 c ommenters (17725, 18014, 18498) state that particle size distribution or unburned levels during startup affect PM CEMS measurement accuracy , particularl y those using light scattering or optically

- based technologies; commenter 17728 states that the particle size distribution may differ from those in the correlation. Several c ommenters (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 un acceptable, and interferences cause breakthrough.411

**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**  **a ssumptions/**  **j ustifications**  **. i**  **. Support or o**  **ppose EPA ’**  **s a**  **ssumptions .**  **Comment 3 0**  **:** Multiple c ommenters (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 ty

pically use cleaner fuels during startup) are unsupported and do not reflect actual EGU operating practices). Several c ommenters (17728, 17729, 17756, 17775) state the EPA ’ s rationale does not account for the variety of ways EGUs startup and shutdown (ty pes 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 frequentl y (18447); base load units do have startups and shutdowns (17772); EGUs do not startup frequentl y (17851); solid fuel

- fired EGUs startup infrequently (17815); the duration of startup/shutdown is reasonabl y predictable (17316, 17386); the duration of startup can vary significantly

(17756); the emissions during startup are variable (17316, 17 386), due to transient combustion conditions (17386), affected b y length of time unit has been shutdown (17316, 17386), and affected b y ambient conditions at lite

- off (17386); the number of startups in a given period can vary (17756); frequency

and duratio n of startup/shutdown varies by unit and fuel blend (17758, 17807); base load units generall y operate for long periods without an outage (17737); and historically , planned outages for maintenance and repair were fairl y predictable and routine (17720, 17758 ). **Response to Comment 3 0**  **:** 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 pre ambles to the proposed rule and this final action. **ii . Cleaner**  **f**

**uels .**  **Comment 3 1**  **:** Commenter 17740 states that units burn a wide array of fuels and the EPA cannot assume without additional justification that EGUs rel y 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 significantl y during startup/shutdown than other periods). Commenter 17737 takes little comfort in the EPA ’ s assertion that emission exceedances will412

not occur due to use of clean fu els during startup. Commenters 17737 and 17772 state that they use oil during startup with APCD by pass (FF, ESP) to avoid oil residue fouling, and Commenter 17737 states that by pass occurs until flue gas entering the FF is 160 oF. Commenter 17756 states that they use oil for some units and use NG for oth ers 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 ty pically 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 swi tch fuels. Commenter 17702 states that manufacturer protocols for control equipment require additional delays for equipment startup when oil is used. **Response to Comment 3 1**  **:** For periods of startup and shutdown, the EPA is finalizing work practice standard s instead of numeric emission limits. See the preamble for discussion. **iii . Combustion**  **i nefficient**  **. Comment 3**  **2 :**  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 (PI Cs) (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**  **n ot**  **o perated**  **. Comment 3**  **3 :**  Numerous c ommenters (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 practic es 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 compl y 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, and413

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 b yp assed under certain operating conditions. Commenter 19114 states that APCDs need to achieve stable operating temperatures or other conditions. Ingeneral, 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 long

term 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 stat es 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 s ys tem to operate during SSM, if technicall y 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 s tates that the EPA does not understand how to operate a boiler and the procedures that are necessary to operate safel y during startup/shutdown. Commenter 18447 states that during shutdown or malfunction, the fuel to the boiler is shutdown and the ESP is po wered 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 theoreticall y be reduced by ramping up the fuel rate, but plants closel y 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 by pass is necessary

to avoid melting fiberglass tubes. Commenter 17740 provides an example facility , a single unit plant that ha s upgraded with installation of new control equipment (SCR, FGD, and PJFF) that is considered BDT, modification of plant heat rejection s ys tem, 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 SO 2 and NO X 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 significantl y jeopardize compliance for SO 2 and NO X . **Response to Comment 33 :**  For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emiss ion limits. These work practices take into account operation of414

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**  **n ot**  **e fficient**  **. Comment 3**  **4 :**  Numerous c ommenters (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 c ommenters (17758, 17772, 17774, 17807, 17821) state that emissions may be greater during startup/shutdown periods because APCDs do not operate efficientl y until st eady

- state is achieved. Commenter 17856 states SO 2 emissions are higher from the scrubber and NO X 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 compl y w ith 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 s ys tems require 24 to 36 hours for startup to develop the proper scr ubber liquor chemistry , and to achieve the SO 2 emission reduction. Commenter 17736 states that ESPs yield lower removal efficiencies during startup due to low temperatures; Several c ommenters (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 3 4**  **:** 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**  **c larifications**  **. i**  **. Definition for SSM .**  **Comment 3 5**  **:** Several c ommenter s ( 19536 , 19537 , 19538 ) state that the EPA does not define startup, shutdown, or malfunction.415

**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 malfunc tion contained in general provisions (40 CFR Part 63.2) applies. **ii .**  **Period for e**  **missions a** **veraging .**  **Comment 3 6**  **:** Commenters 17808 and 17870 state that averaging emissions over 30 boiler operating days is onl y relevant for CEMS but is not relevant for units conducting monthly or quarterl y 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 3 6**  **:** The commenters are correct that the 30 (or 90, as discussed elsewhere) boiler operating

- 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 malfuncti ons is discussed in the preambles to the proposed rule and this final action. **iii . Definition of**  **b oiler**  **operating d ay/**  **s ubpart Da**  **. Comment 3**  **7 :**  Several c ommenters (17756, 17775, 17820) state the “boiler operating day” definition is not flexible to account fo r 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 i f less than 18 hours should be excluded from the 30

- day average. Several c ommenters (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 ex cluding startup/shutdown periods from emission limits would follow precedent in numerous rulemakings. **Response to Comment 3 7**  **:** For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits so this comm ent is moot. These work practice standards take into account operation of APCDs. See the preamble for discussion. **iv . Other**  **. Comment 3**  **8 :**  Commenter 17675 states there should be allowances for alternative compliance limits or alternative monitoring for star tup/shutdown periods, especiall y for acid gas and SO 2 , when APCD are416

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. Commenter 17761 sugg ests, 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 de fined 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 3 8**  **:** 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**  **s tartup/**  **s hutdown**  **. 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 CO 2 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 appropriatel y 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 s ubsequent 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 sugges ts 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 accuratel y 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**  **s tandards/** **work p ractice**  **s tandards for SSM**  **. a**  **. Support s**  **eparate s**  **tandards .**  **Comment 4 0**  **:** Several c ommenters (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 c ommenters (17730, 17737, 17930) state the EPA must establish separate emission standards for417

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 manufacturer ’ s/site best work practices. Commenter 19122 recommends higher alternative PM limits or a work practice standard. Numerous c ommenters (16849, 17383, 17402, 17627, 17638, 17677, 176 89, 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 c ommenters (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 c ommenters (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 emission s 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 perio ds 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 col lecting SSM period data would involve significantl y altering measurement techniques and may require manual monitoring. **Response to Comment 4 0**  **:** 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 malfunctio n events. **b . Sierra Club Decision**  **. Comment 4**  **1 :**  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 c ommenters (17383, 17689, 17712, 17724, 17813, 17876, 17885) agree that court decisions indicate that HAP regulation must account for startup/shutdown events. Several c ommenters (17732, 17775, 17904, 17930) state that section 112 only requires that some section 112 compliant standard apply at all times. Several c ommenters (17732, 17775, 17930) state that section 112 does not require that one standard apply to all periods. Commenter 17772 states that the court case418

clarified that providing c ontinuous emission reduction did not mean that a single standard for all periods 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. Comm enter 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 b y not only providing no exc lusions, 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 al low 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 4 1**  **:** 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 m alfunction 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**  **s ection 112(h)**  **. Comment 4**  **2 :**  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 c ommenters (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 “n ot feasible to prescribe or enforce ” which includes any situation in which the Administrator determines that the application of a measurement methodology to a particular419

class of sources is not practicable due to technological and economic limitations. Commenters (17716, 17720, 18023) state the EPA must provide a separate work practice standard for SSM because it is not technicall y feasible to complete stack testing (and monitoring, 17720) during these periods. Multiple c ommenters (17402, 17716, 17725, 1773 6, 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 technicall y feasible to complete stack testing or monitor during startup and shutdown. Multiple c ommenters (1740 2, 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 s tates that the EPA has recognized previously that ICI boilers and EGUs are virtuall y 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 ICIboilers with respect to emission testing. Commenter 18037 states it is no t 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 accuratel y determine emissions during startup/shutdown. Commenter 18023 has evaluated stack testing times and relay s that total PM testing would require 8 to 10 hours and metal HAP and acid gas testing would require minimum of 16 hours. Several c ommenters (17725, 17820, 18014, 18498) st ate it is uncertain whether representative measurements could be obtained during startup/shutdown due to dy namic 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 star tup would require 6 to 8 hours to complete a single test, but the conditions would have changed so significantl y 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 s tartup. **Response to Comment 4 2**  **:** 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**  **t esting and**  **m easurement**  **i ssues**  **. Comment 4**  **3 :**  Commenter 18034 opposes any requirements to require stack testing during startup/shutdown. Commenter 18034 states that requiring stack testing during potentiall y dangerous plant operations that could place testing personnel at risk is inappropriate.420

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 properl y 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 accuratel y 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 Commen t 4**  **3 :**  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 co mmenters 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 non

compliance) 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 r**  **equirements .**  **Comment 4 4**  **:** 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 c ommenters (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 63.7 530(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. C ommenter 17772 suggests the work practice standard take into account the boiler configuration, boiler typ e, and safe operation of the unit. Several c ommenters (17725, 17774, 19032) state the work practice standard should account for421

boiler ty pe and control equipment. Commenter 17816 states that work practices should be specific to a unit ’ s boiler ty

pe, operational characteristics, and APCDs. Commenter 17774 states that sources should have to address malfunctions as soon as safel y practicable. Commenter 1777 4 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 plan s. 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 4 4**  **:** 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**  **p arameters for APCD**  **. Comment 4**  **5 :**  Sever al c ommenters (17 820, 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 AP CD 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 frequentl y used loads, and then maintain those levels during other periods, including startup and shutdown. Several c ommenters (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 perio ds of startup/shutdown in the parameter operating limit. **Response to Comment 4 5**  **:** 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 5A 05. 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 r ule and this final action. **3 . Other**  **a veraging**  **p eriods**  **. a**  **. General .** 422

**Comment 4 6**  **:** Commenter 17774 recommends a longer compliance period to provide flexibility and accommodate SSM events. Commenter 16849 suggests a longer averaging period, as an alternative t o 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 av erage. 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 emission s 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 a nd 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 excee d 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 b y 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 SS M events. Commenter 17761 notes that longer averaging periods for all emissions limits (such as an annual or semi

- annual average) to full y 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 in stead 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 that423

emissions that occur during p eriods 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 lev el 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 c oncern 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**  **l etter**  **. 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, b y averaging over a long period of time, e.g., ye arl y. **Response to Comment 4**  **7 :**  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 emissio n limits that are caused b y 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 merel y 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**  **c apping and**  **e lectrical**  **p roduction**  **. Comment 4**  **8 :**  Commenter 17648 agrees with the options for calculating input

- based emissions based upon a default diluent value or fuel specific CO 2 concentration, or calculating output

- based emissions using an electrical pro duction 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 m ethodology
. 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 178 21 states the EPA should define the default CO 2 value for various fuel types, just as it has for O 2 . Commenter 17821 urges the EPA to define a default CO 2 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 CO 2 diluent values, notes that the O 2 diluent value is not424

appropriate, and recommends use of the diluent cap values already defined in part 72 of 5 percent for CO 2 and 14 percent for O 2 for coal

- fired EGUs, which would harmonize the two r ules and provide adequate margin in the data. Commenter 17821 also supports a value of 5 percent CO 2 , 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 1790 4 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 c ommenter s ( 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, shutdo wn, 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 CO 2 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. Commenter s 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 actuall y 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 c ommenters (17740, 17758, 17776) state that the EPA does not address these concerns (that there are equipment integrity conc erns, 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 th at 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 c ommenters (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 4 8**  **- 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 SS M 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 timesthe process unit is operating and at the intervals specified in the rule, except for periods of monitoring s ys tem malfunctions, repairs associated with425

monitoring system malfunctio ns, required monitoring s ys tem 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 notwiths tanding the malfunction. **5. Reliability i ssues**  **. Comment 5**  **0 :**  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 by p ass controls for short periods are critical to operating a reliable electric s ys tem. 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 by pass, 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 by pass under even these special circumstances could result in transmission consequence s 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 5 0**  **:** 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 like lihood 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 implementati on of this final rule. We address APCD maintenance , by pass stacks, our approach to malfunctions, and reliability issues elsewhere in the final rule record. **6 . Malfunctions**  **. a**  **. Support or o**  **ppose m**  **alfunction a**  **pproach .**  **Comment 5 1**  **:** Several c ommenters (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 ty pical operating conditions and426

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 th at 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 compl y 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 malfuncti on events are unlikel y 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 malfunc tion. 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 m alfunction 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 c ommenters (17808, 17870, 18025) recommend the EPA or states maintain current enforcement discretio n 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 a427

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 5 1**  : 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**  **p ractice**  **s pecific to**  **m alfunctions/Sierra Club Decision**  **. Comment 5**  **2 :**  Commenters 17775 and 1802 3 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 safel y 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 re quires that some “ section 112

- compliant standard” appl y 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 technologicall y 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 appl y 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 appl y at other times. In fact, the commenter states that establishing section 112(h) s tandards for malfunctions would be more consistent with the Sierra Club ruling than applying clearl y 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 clearl y 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 reasonabl y control. The commenter states that the428

EPA should adhere to that intent and specify reasonable work practice or operational requirements for periods of malfunctions. **Response to Comment 5 2**  : 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, commenter s ’ 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 my riad different ty pes 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 5**  **3 :**  Commenter 17775 states that the EPA ’ s reporting requirements also raise some prac tical 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 b efore 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 eas y. 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 n otes 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 pe riod 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 5 3**  : 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.429

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 exp eriencing 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 day s after the initial occurrence of the malfunction or, i f 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**  **d efinitions**  **. Comment 5**  **4 :**  Commenter 17775 note s 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 suppos ed 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 th at the definition of “malfunction ” is sufficient for the Utility MACT rule. **Response to Comment 5 4**  **:** 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**  **d efense**  **. a**  **. Support or o**  **ppose AD a**  **pproach .**  **Comment 5 5**  **:** Multiple c ommenters (17623, 17715, 17740, 17807, 17904, 17909, 17912, 18025, 18428, 19114) support affirmative defense (AD) for malfunctions; commenter 17722 generall y supports the AD for excess emissions. Multiple c ommenters (17689, 17724, 1 7712, 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 prov ide detailed guidance on how the provisions will be applied and rel y on case - by

- case review. Commenter 17912 notes that the EPA properl y proposes flexibility

for malfunctions. Commenter 17912 supports the EPA finding that it is reasonable not to account fo r 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 red undant with items 1 through 6, are unnecessary , are not reasonabl y430

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 deviati on, improperl y 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 every

thing in their power to minimize emissions, unless the EPA proves certain fact s 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 highl y prescriptive and infer that the failure to meet any step is a willful violation. Commenter 1 8500 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 unreasonabl y 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 ha s improperl y 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 burden some. 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 vaguel y 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 impac t of the excess emissions. The commenter asks whether that means that if the EPA or some private litigate can imaginativel y identify some step not tried, then the affirmative defense is rejected? The commenter goes on to note that if so, no affirmative def ense would ever be successful

-- some untried alternative or additional action could always be found b y inventive counsel or expert witness. Similarly, commenter 17772 notes that proposed rule section431

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 actuall y emplo ye d 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 b y a showing that the operation and maintenance practices were consistent with good utility pr actice. 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 actuall y 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. C ommenter 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 req uire 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), paragrap h (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 provi sions 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 c ommenters (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 anal ys is 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 these432

technologies are available, the EPA should not provide an AD for malfunctions from emissions controls that are accident prone. Several c ommenter s ( 19536 , 19537 , 19538 ) state that the EPA ’ S AD for malfunctions is unlawful. Commenter s state that the CAA makes clear how the courts are to assess civil penalties, whether a case is brought b y 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 “ diligentl y prosecuting ” its own civil enforcement action, CAA § 304(b)(1)(B), 42 U.S.C. § 7604(b)(1)(B). The commenter s state that the EPA ’ s rule proposal, b y shifting this careful balance and contravening these mandates, violates the CAA. Commenter s state that the AD that the EPA proposes to allow in case of malfunctions goes directly against congressional intent in two ways. First, the commenter s 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 commenter s note that the EPA ac ts outside of its delegated authority to limit civil penalties available in citizen suits or its own enforcement actions. Second, the commenter s state that the proposal will impermissibly chill citizen participation, and the ability to win an effective, deterrent remedy , in CAA enforcement actions. Commenter s state that the AD is fatall y flawed because the EPA cannot decide when civil penalties will not be allowed. The commenter s 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 commenter s state that the EPA exceeds its authority . The commenter s 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 commenter s 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. Commenter s 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 commenter s 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 commenter s state that section 304(a), 42 U.S.C. § 7604(a), grants courts the sole authority “to appl y appropriate civil penalties ” in citizen suits. The commenter s 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 onl y be understood as an intentional decision by Congress that the EPA cannot contravene by rule. Commenter s 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 commenter s state that the affirmative de fense 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 commenter s note that433

enforcement of the CAA could suffer, for civil penalties provide a powerful deterrent to violators as Congress intended. C ommenter s state that the AD also runs counter to two clearl y expressed intentions of Co ngress: (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 C ongress ’ 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 commenter s 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, c ommenter s 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 commenter s 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 commenter s note that polluters are likel y 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 ty pe 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. Commenter s state that assuming arguendo that the EPA had authority to promulgate any

ty pe 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 malfuncti ons 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 ye ars. 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 e xceedance that occurs of which an operator is aware. Specificall y, 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 publicl y av ailable 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 scho ol 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.434

**Response to Comment 5 5**  **:** For malfunctions, the E PA is finalizing the proposed affirmative defense language for exceedances of the numerical emission limits that are caused by malfunctions with minor revisions as discussed below
. As the EPA explained in the preamble to the proposed rule, the EPA recogniz es 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 is including an affirmative defense in the final rule as we have in other recent section 112 and section 129 rules so as to balance the tension, inherent in many typ es of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under circumstances beyon d 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, the 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 some situations it is appropriate for the 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 n ecessary 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 calls into question the relevance of these cases today , they support the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simpl y provides fo r a defense to civil penalties for excess emissions that are proven to be beyond the control of the source. By

incorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ninth Circuit required this ty pe of formalized approach when regulating “upsets beyond the control of the permit holder.” Marathon Oil Co. v. EPA , 564 F.2d 1253, 1272

- 73 (9 th 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 b y 42 U.S.C. § 7602(k), and account for unplanned upsets and thus support the rea sonableness of the standard as a whole. Further, the EPA’s view is that the affirmative defense is consistent with CAA section s 113(e) and 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 onl y after it has been determined that a penalty is appropriate. The affirmative defense regulatory provision is not re levant to the amount of any penalty to be assessed under section 113(e) because i f 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), the EPA necessarily defines conduct that constitutes a violation. The EPA’s view is th at 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 reli ef is available. All other435

violations of the emission standard are subject to injunctive relief and penalties. The CAA does not require that all violations be treated equall y. 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 the EPA to establish such “enforceable emission limitations.” Thus, the citizen suit provision clearly contemplate s enforcement of the standards that are defined by the EPA. As a result, where the 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 pen alties) in narrow, specified circumstances, as the 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 malfun ction 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 b y 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 appropriatel y 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 ty pe of fact

- intensive disputes that the commenter complains of. In addition, several of the affirmative defense criteria are exactl y the ty pe 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, th e source must prove b y 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 generall y 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 was436

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. The EPA is not adopting commenters’ suggestion with respect to compensatory damages or limits on the frequency of use of the affirmative defense. Itis not clear that EPA has authority to re quire 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 injunc tive 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 onl y 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 defens e provisions require that parties choosing to assert the affirmative defense meet additional malfunction reporting requirements. Any such reports submitted to the EPA are publicl y available pursuant to CAA section 114. Further, the EPA disagrees with comments that criticize the affirmative defense criteria as being overly vague or undul y restrictive and complex. The EPA believes that courts are well equipped and often do evaluate and appl y the type of criteria set forth is the affirmativ e 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 M alfunctions, 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, 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 does not find persuasive commenters’ concerns with potential use of the root cause anal ysis against the source. The purpose of the root cause anal ys is is to determine, correct, and eliminate the primary causes of the malfunctio n and the excess emissions resulting from the malfunction event at issue. A sources ability to do so with the benefit of hindsight after a malfunction has occurred does not necessaril y mean that malfunction could have been predicted or prevented. The E PA also disagrees with comments that criticize the affirmative defense for shifting the burden of proof. 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 acti on. 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 the 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, the EPA does not agree that the affirmative defense should operate as the437

commenter suggests. The commenter improperl y s eeks to shift the burden of proof from the source to the EPA. It is the source, not the EPA, that has the information relevant to assess whether a particular event qualifies as a malfunction and meets the affirmative defense. **b . AD for**  **s tartup/**  **s hutdown**  **. Comment 5**  **6 :**  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 st ation) where opacity standards appl y 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 5 6**  **:** . 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
. Incontrast, 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, a pplicable 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**  **t imeline**  **. Comment 5**  **7 :**  Commenter 17912 states section 63.10001 requires notification a s soon as possible but no later than 2 business day s, 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 ev idence 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 sh ould 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 cite s an example where emissions are measured b y 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 th ere 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 5 7**  : 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 day s 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 that438

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 m ethod**  **. Comment 5**  **8 :**  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 b y 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 pro vides 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 elim inate 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 substantiall y 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 5 8**  **:** 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 b y telephone or facsimile (FAX) transmission of the exceedance
. However, the wri tten 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 approv al 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**  **r equire**  **Root C ause Analysis for**  **every m alfunction**  **. 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 anal ys is (RCA) for every malfunction for AD. Commenter 17923 states that the ambiguity of the recordke eping requirements limits confidence in a facility ’ s ability to demonstrate compliance.439

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 anal ys is 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 i n the future, and the facility 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 typ es of inductive analyses, and other indu ctive 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 anal ys is, 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 anal yz ing their violative emissions to reduce or avoid those emissions in the future, which is an environmental benefit
. A root cause anal ys is is only required if a source seeks to assert an affirmative defense
. However, such an anal ys is is beneficial in resolving or preventing violations and excess emissions whether the source seeks to assert the affirmative defense or not
. A root cause anal ys is is one example of what constitutes good air pollution control practices to minimize emissions. A root cause anal ys is is not required for every malfunction

- - onl y those malfunctions for which the so urce 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 anal ys is to achieve the de sired results and conclusions in the event of a malfunction . The EPA joins the commenter in seeking meaningful results which successfull y 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 anal ys is is required. In the context of part 63 section 112, the term “root cause analysis ” was used genericall y to imply an anal ys is 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 pen alties are an appropriate sanction for the violation, if one occurred
. The term “root cause anal ys is ” 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 anal ys is ” is not a defined term in the applicable subparts of Part 63. **8 . SSM**  **l imits**  **should be m ore**  **s tringent;**  **emissions are h igh during SS**  **e vents**  **.**440

**Comment 6 0**  **:** 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 recentl y 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 ye ar, and Title V monitoring reports for 2009 and 2010 for these same facilities show actual duration of SSM events frequentl y exceed 100 hr/y r, and more than 200 hr/y r at one facility
. Commenter 17755 states that a majority of PM and opacity

excess emissions occur during S SM 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/y

r per boiler could emit up to 1,436.4 ton/y

r per boiler if the SSM application is granted. Commenter 17975 highlights another facility

with current emissions limit of 1,033 ton/y r that could emit up to 2,284.4 ton/y r 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 as sume 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 ye ar, and four other facilities with over 40 hours of opacity exceedances per ye ar 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 COM S 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 EPRIdata 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 removed441

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 startu p suggest the emissions can sometimes be much higher than estimated in SSM applications. 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 ef

fectivel y 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 c ommon 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 thes e 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 durin g 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 by

passed at all, and could be by passed 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 negativel y impacts the ba gs. 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 d

uring 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 standa rds 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 commerciall y 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;442

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 conditi ons. 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 mai ntenance 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 stat es 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. 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 effectivel y 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 6 0:**  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 clearl y states that if you are conducting co ntinuous monitoring, “You must operate the monitoring s ys tem 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 b y 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

- ye ar review. **9 . Use of**  **m ulti**  **- m**  **etals CEMS and f**  **uel t**  **esting for startup f** 

**uels .**  **Comment 6 1**  **:** 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

- metal443

CEMS use allow s 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 6 1**  **:** 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**  **s tartup**  **. Comment 6**  **2 :**  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 6 2**  **:** For p eriods 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, c ommenters 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**  **d ata.**  **Comment 6 3**  **:** 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 b y the CAA and the courts in Cement Kiln Recycling Coalition. C ommenter states that , as a result, the EPA must establish work practice standards for these periods. **Comment 6 4**  **:** Commenter 17776 states that the proposed rule would inappropriatel y 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 durin g these periods can be accuratel y 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 6 5**  **:** Regarding startups and shutdo wns, commenter 17914 cites the following as problems with the EPA ’ s MACT floor anal ys is:

 No startup/shutdown data were considered.
 In correctl y characterized solid fuel

- fired EGUs as infrequentl y starting up and shutting down and using cleaner fuels during startup.
 In correctl y characterize startups and shutdowns as predictable and routine.444

 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 6 6**  **:** Commenter 18034 states that emissions during startup and shutdown were not ev aluated 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. **Response to Comments 6**  **3 -**  **6 6**  **:** 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 6**  **7:** In commenting that the EPA is not adequatel y 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 6**  **7:** 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 c lear 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 in feasibility 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 c ommenter states that even with the proposed 30 boiler operating day averages, emissions from these non

- representative periods could significantly affect the averages, especiall y for peaking units or other units that com on

- and off

- line frequently . Commenter agrees with the EPA that startup and shutdown period s 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 typicall y perform less than optimally during periods of startup and shutdown. In fact, some air445

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 especiall y 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). Several c ommenters ( 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 peri ods 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 w ould 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 emissi on 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 pres umption 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 increasingl y limited resources and are already overburdened with regulatory responsibilities. Since it would not be technicall y feasible to accuratel y 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 rang es required to have accurate data) , the statutory requirements for the EPA ’ s authority t o 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 my riad different ty

pes 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 has446

not provided support for its assertion that it would not be technicall y feasible to accuratel y 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 demons trate that the source complied with the standard. 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 7 0**  **:** 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 co uld 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 ty

pes of boilers and encourages the EPA to require c ompliance 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 analy sis of data concerning such emissions. Commenters 17790 and 17851 find the EPA ’ s logic about appl ying the proposed standards during startup and shutdown to be flawed because it does not account for the variety of way s in which the EGUs startup and shutdown and because it is not based on actual emi ssions 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 a447

certain way

during periods of startup and shutdown. The EPA ’ s decision ignores that it is well known that emissions control devices ty pically 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 7 0**  **:** 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 this response to comments document. The requirements do not include a startup, shutdown, and malfunction plan. See Table 3 to Subpart UUUUU of p art 63. Commenter’s suggestion that its state

approved plan is prefereable to EPA’s approach does not explain how an approach based on such a plan meets the requirements of section 112.448

**5C07 -**  **Compliance: Other Commenters**  : 16849, 1 6850, 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**  **l ow**  **e mitters**  **a lternative**  **c o**  **mpliance .**  **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 9 0 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 emissio ns 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 single

fuel units, changes in fuel ty pe, 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 ty pes 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 ty

pe changes. Commenter 17176 states single

- fuel LEE units should not have to compl y 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 (pe rformed every 5 ye ars) 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 sati sfaction 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 opp ortunity 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 highl y 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 anal ys es.449

**Response to Comment 1:** The final preamble describes the final rule provisions for LEE. Because the proposed fuel anal ys is 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 sy stem, with quarterl y Method 30B testing until the monitoring s ys tem is certified. Yo u can regain LEE status for that unit if every required performance test for a 3

- ye ar 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 emission s 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 r ule 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 ha s 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 m odernization 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 standard s, 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 appropri ate. As stated b y 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 syst em 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.450

**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**  **t esting**  **. Comment 3:**  Commenter 1 7808 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 di fficult 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 wil l 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) anal ytical results take a minimum of 2 weeks to be analyzed and reported b y laboratories, so a unit could potentially be out of compliance for 2 weeks before anal ytical results could be provided; (4) anal yz ing 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 compl y 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 CEM S or PM CPM S 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 s ys tems 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) al lows 180 day s 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 o f 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 s tart 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 s ys tem. 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 fl exibility for sources to specify

the start of the “performance test” for CEMS that have been previously certified (e.g., SO 2 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 this4 51

rule being promulgated). The commenter states that in addition, for PM CEMS, which do not conduct any thing called “ certification testing ” (the term “ certification” does no t appear any where in PS 11), there is no clear point at which to declare that the performance test has begun. Unlike SO 2 CEMS, PM CEMS must be correlated by conducting tests with a reference method and developing a “ correlation curve ” that meets PS 11 perf ormance 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 s ys tem 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 s ys tem 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 s ys tem. 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 IC R testing and established compliance testing and compliance assurance requirements consistent with that assessment. Commenter 17775 indicates the EPA has proposed continuou s monitoring, initial stack testing, or periodic fuel analysis that it presumably believes are consistent with that assessment; as long as an EGU is compl ying 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 th ose 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 1802 5 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 b y the EPA for similar units. The commenter states that Connecticut DEP remains confident that quarterl y 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.452

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 sched uling 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 demand s 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 fe els there must be a maximum time limit, it cannot be shorter than 36 months without significantl y 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 no r 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 CP MS in the proposed rule and this was an erratum. **4 . Frequent**  **t esting for**  **l iquid**  **o il**  **- f**  **ired u**  **nits .**  **Comment 8:** Commenter 17758 states that frequent performance stack testing (monthly or every other month) for oil

- fired EGUs is impractical, unnecessary , restri ctive, 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 frequentl y than annuall y. Commenter 17775 stat es 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 appl y to EGUs using fuel anal ysis 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 b y the ISO or for compliance with the proposed rule should be exempt fro m any “ limited use ” calculation. Commenter 17716 states that many liquid oil

- fired sources operate infrequently and onl y during peak demand periods, and frequent performance testing (monthly or every other month depending on whether add

- on controls are ins talled) 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 emissions453

of HCl, HF, and non

- Hg metals are most closel y 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, anal ys is, 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 quarterl y 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 limit s . 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)
. Italso 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**  **l imits**  **. Comment 9:**  Commenter 18023 suggests BLDS for fabric filters are not necessary , and if BLDS are required in the final rule they should onl y be used for purposes of triggering maintenance activities. Commenter 18023 explains the following for BLD S: (1) this operating limit is purely arbitrary , the EPA provides no information nor makes any claim that the op erating 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 sy stem 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 syst em, nor does it apply to applications in which monitoring s ys tem 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 adequatel y identified in the bi

- monthly performance test required b y 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 generall y 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 necessaril y 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 secondary454

power); (3) because performance does not correlate perfectl y 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 appl y for EGUs that operate additional wet control systems, the EPA should clarify what requirements they

are proposing for EGUs that operate onl y 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**  **f**

**lexible c**  **ompliance o**  **ptions .**  **Comment 11:** Commenter 16850 states that electric utilities should b e 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, particularl y notes that the EPA provided a flexib le 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 bes t 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. **C omment 13:**  Commenter 17772 states that the proposed rules purportedly leave in place the existing emission standards for SO 2 , NO X , 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 merel y modi fied, b y 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 suppl y - 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 complianc e, 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 unn ecessary

restrictions and requirements on them, without demonstration of substantial environmental or health benefits and that the EPA ’ s proposed compliance testing and monitoring programs are455

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 reliabl y demonstrate compliance, such as through re examination 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, especiall y for elements present in trace quantities for which no detailed operational hi story 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 ty pes 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 catal ytic 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 ye ars, could lead to unnecessary operation solel y to demonstrate compliance, which is undesirable from both an environmental and a financial perspective. **Response to Comments 1 1**  **- 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 reasonabl y allowed under the statute and court pr ecedent. 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 st andards, including operation of emissions control devices as appropriate, during periods of startup or shutdown and does not impede development and deploy ment of diverse energy

portfolios. Compliance options have been simplified, but still assure complianc e 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 8 percent the ability to meet a work prac tice standard, rather than conduct emissions testing, thus preventing the commenter ’ s concern about unnecessary

operation solely

to demonstrate compliance.456

**7 . Clarifications**  **n eeded for**  **c ompliance**  **d emonstration**  **. Comment 16:**  Commenter 17752 states that the c ompliance 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 appl y 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 appl y (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 s ys tems) to only appl y 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 “per formance 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 anal ys is, ” 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. Accordingl y, Commenter 17775 indicates the proposed rule on its face appear s 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 onl y 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 appl y to each compliance option. According to the commenter, the EPA must provide a clear rational e 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 s ys tems), and457

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, b y 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 moni toring s ys tems, ” 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 inadequatel y explained. According to the commenters, many of the EPA ’ s proposed provisions simply require compliance “ as applicable, ” but the EPA nowhere clearl y 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 clearl y 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, th ere 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 ty pe of information into existing Title V permits. **Response to Comm ent 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 DSItechnology

will qualify

for the option to use SO 2 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 limi ts 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 p reamble to the rule or more specificity in the458

regulatory

text concerning requirements for performance testing, continuous parameter monitoring systems, fuel sampling and anal ys is, control device operating parameters, monitoring and reporting. Several c omm enters (17868, 18424, 18963) question the EPA ’ s assumption that a large number of EGUs will use DSIto 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 SO 2 control system, and commenter 18963 notes that there have been no commerciall y demonstrate d applications of DSI for the control of HCl from coal refuse

- fired CFB units. Commenter 17868 questions the EPA ’ s assumption that the 3

- ye ar compliance schedule is achievable based on the use of DSI sy stems rather than FGD. Commenter 18424 also questions the EPA ’ s projection that a large number of EGUs will use DSIto 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 empl oying 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 SO 2 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 SO 2 surrogate, for the same reasons as stated in the proposed rule. If a source uses DSIand 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 a bove. 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 c leanup 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) directl y from the fuel stream of IGC C units. A ccording to the commenter, in this respect, IGCC is more akin to a natural gas

- fired combined cycle unit, since it burns a sy ngas, which is cleaner than the coal combusted in a pulverized coal unit. According to the commenter, the EPA should reflect that I GCCs 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. The commenter states that it makes n o 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 ty

pe of electric generating unit by proposing a separate subcategory for IGCC units, and the EPA needs to further acknowledge the process differences between IG CC 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.459

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 s yn gas - based heat input; and (2) differences between s yn gas - 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 c ombined 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 s yngas derived from either c oal 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 s yn gas, 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 s yn gas 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 onl y that the HAP emissions (or surrogate emissions) coming out of the stack must not exceed the standard
. If a sy ngas 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 provisio ns 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. I f 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 s tandard 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 b y 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 s ys tems. b. The EPA should allow states to request equivalency determinations based on state rules that cover the same pollutants, but with different co ntrol requirements and timing460

**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 limi t 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 perio ds. 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 appl y as federally enforceable standards. A Part 70 operating p ermit 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 t o 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 newly

designated oil unit to schedule and conduct initial performance tests to demonstrate compliance with the applicable standards. **Response to Comments 20 -**  **21:** While the rule n o 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**  **m eet**  **c om** **pliance d**  **eadline .**  **Comment 22:** Comment er 18023 indicates that the requirement in section 63.10005(g) to demonstrate initial compliance for existing sources no later than 180 day s after the compliance date is problematic for sources that may

be in an outage or temporarily not operating on the c ompliance 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 day s 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

- ye ar 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 stat es that the “ Tailoring Rule ” provisions can be triggered b y 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 anal ys es requirements during the permitting process. The commenter states that GHG BACT is a largel y 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 ex acerbated b y 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 co ntrols needed for an existing unit to meet the emission limits of the Utility HAP MACT Rule.461

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 , h e or she can request up to a 1
- ye ar exten sion 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 anal ys is done in 2005 that looked at SCR and FGD for CAIR comp liance, but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR requirements would not significantl y impact the construction of pollution controls that are installed to comply with this r

ule. 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 chemicall y 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 pol lution 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 likel y 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 ty pically averages seven months and is ob tained usually within one year. 19 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 timel y installed to m eet 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.

19 “ 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.pdf462

Commenter 17790 disagrees with the EPA ’ s assumption that DSIwith fabric filters will provide compliance

- level re ductions 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 D SI technology has not been widel y 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 DSItechnology will work without a scrubber, it is highly unlikel y any utility ’ s compliance strategy will rely onl y 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 ef fectiveness 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 neces sitates 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

- ye ar compliance deadline that the EPA optimistically a sserts companies will be able to meet. Commenter 17820 states that the EPA assumes that an adequate supply of dry sorbents is readil y available in the RIA, yet sorbent production would need to increase b y 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 pote ntial 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 mill ions 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 comment er, the sole regional supply of Trona from the Green River, W yoming area takes two to four weeks to deliver, Trona is shipped by

rail in sealed pressure discharge ( “ PD ” ) railcars that ty pically 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 the463

supply chain. The commenter states that the RIA is overly optimistic about the use of DSI and, in turn, understates the co st 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 sy stems 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 NO 2 . 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 H 2 SO 4 dew point corrosion, plug gage and/or blinding. DSI for fabri c 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 SO 3 from high sulfur coals on ACIfor 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 easil y 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 carb on, 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.464

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 s ys tems 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 likel y require a fabric filter to avoid NSR and PSD permits. The commenter states that while DSI may be installed in less than three ye ars, 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 pre sumption that sorbent injection or dry scrubbing will be installed over wet scrubbing sy stems 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 s ys tems and the installation time for wet scrubbers is significantly longer. **Response to Comment 23:** As mentioned in the response to comment 17, the a genc y finds that a number of additional EGUs will choose some form of acid gas control b y 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 co mbustion 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 th at 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

- ye ar extension from the Administrator. **9 . Request to**  **m odify**  **c ompliance**  **r equirements**  **. Comment 24:**  Co mmenter 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 NO X and CO production. The commenter s tates that in section 63.10021(a)(16)(iii) and (iv) the EPA is requiring the annual inspection of sy stems controlling the air

- to - fuel ratio and optimizations of CO and NO X consistent with manufacturer ’ s specifications. According to the commenter, while the EPA references air

- to - fuel ratio, typicall y boiler operators use excess O 2 to determine proper combustion; the general indicator of incomplete combustion is high CO levels or unburned carbon in the fl y ash, and operators use O 2 set points to insure combus tion has been optimized. Currently Commenter uses a neural network computer sy stem to optimize the boiler combustion and minimize NO X and CO production; this system continually tunes the boiler combustion465

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 f inal rule to recognize the value of automated boiler optimization tools such as neural

- net s ys tems. 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 rarel y, if ever, used to access the impact on NOx or CO; for instance, flame observation on cyclone and coal

- fired tangential boilers would not generall y be useful. Acco rding to the commenters, the cyclone itself is the burner and the flame is opaque;, in general, the furnace of a tangential boiler is essentiall y 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 currentl y 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 ty pe, 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 signifi cant 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 op erators. **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 SO 2 as a surrogate for acid gases (e.g., HCl) as an alternative to measuring HCl since SO 2 emissions are controlled upstream via acid gas scrubbing to reduce sulfur. Commenter collected SO 2 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 SO 2 data under the Acid Rain Program. According to the commenter, at a minimum, the EPA could set an SO 2 surrogate limit to be the same value as other coal

fired units, or the EPA could use data from the two existing IGCC sites. The commenter states that the EPA should not limit having SO 2 as a surrogate just to units with a FGD system when other proven and effective SO 2 emissions reduction technology exists and states that as an example, General Electric ’ s gasification technology , currentl y being installed at the Edwards port IGCC, uses water scrubbing of466

sy ngas at high temperatures which removes water soluble acid gas compounds such as HCl, HCN , HF, and Cl 2 . The commenter states that the emission controls for the Wabash River and Polk Station I GCC 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 SO 2 as a surrogate measurement of acid gases. **Response to Comment 27:** The EPA has acknowledged that IGCC EGUs qualify for the alternate SO 2 compliance alternative in the final rule and has based such limits on the tw o 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 s ys tem 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 O 2 leaving the boiler; enough coal is put in to combust and maintain pressure, and enough air is put in until a desired excess ox ygen is achieved leaving the boiler. The commenter states that coal properties vary greatl y (heating content and moisture), so coal feed rates at a desired load can vary greatl y, and consequentl y, the mass of air entering th e 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 re quired on a daily , weekl y, monthly , quarterl y and semi

- annual basis. According to the commenter, this does not include the external resources and costs associated with stack testing or fuel anal ys es. The commenter states that these MRR requirements are dup licative 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 significantl y reduce the issues raised b y the commenter. **Comment 30:** Commenter 17914 states that while many of the proposed provisions of the rule are technicall y 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 S ys tems(AQCS) performance optimization challenges and constraints. Commenter requests that the EPA reconsider several aspects of the rule, which as proposed would severel y 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 c laims. 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 reduction s of over 90467

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 analys is 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 red ucing 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 f acility 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 f or 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, us ing DSI technology

to meet the acid gas HAP emission limits actually makes it more difficult to compl y with the PM emission limits because the dry sorbent injected into the flue gas stream reacts with SO 2 , creating sodium sulfate, a particulate that must b e 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 c ommenter states that where a base is added to the pond, the water will necessaril y 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/NETLmercury control demonstration program, supports that consistent mercury removal levels > 90% are achievable when the corre ct sorbent is properl y 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

- by

pollutant approach have been addressed elsewhere in the response to comments document. **Comment 32:** Commenter 17702 states that the EPA ’ s proposed compliance req uirements 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 compl ying with the emission limits under normal operations.468

**Respon se 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**  **c larification on**  **o utput** **- b**  **ased l** **imitations .**  **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**  **s ustainable**  **e fficiency**  **. 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**  **w ork**  **p ract** **ice s**  **tandards .**  **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**  **m odify or**  **r emove**  **w ork**  **p ractice**  **s tandards**  **. Comme**  **nt 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 suc h activities are generally not done on an annual basis, but rather are less frequentl y performed during periods of extended maintenance shutdown/inspection. Commenters proposed that the 18

- month maximum outage interval should be extended to 24

- 30 months an d 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.469

Inspecting flame patterns is more useful for industrial boiler practices in which an obser ver peers through a glass at the burner and then makes changes to nearb y controls to optimize the flame. Commenter 17638 supports a CAM
- ty pe approach regarding the establishment of work practices, which provide for reasonable assurance of the unit operatio n in lieu of a “ one size fits all ” approach. Several c ommenters (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 sy stems, 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 m aking 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 s ys tem. 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 c ommenters (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 o utages 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 non

detectable 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 stan dard 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 emission s 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 efficientl y, 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 c ommenter s ( 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 s ys tems continuously monitor the combustion process to d etermine 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 are470

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 practi ce 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. **Resp onse to Comment 36:**  The EPA has reviewed the comments on the proposed frequency of tune

ups, 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 sy stem 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 recordkeep ing 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**  **s tates (**  **c om** **pliance d**  **ates) .**  **a. General s**  **upport .**  **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. Co mmenter 17758 further indicates that if states can demonstrate that overall emissions reductions are equivalent or greater than those that would be achieved b y 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 e quivalent to the EGU NESHAP. For Hg emissions and other accumulative impact pollutants, the c ommenter suggests equivalency can be measured by

comparing total emissions on a statewide or corporate utility basis. Commenter 17719 is concerned about existing s ources 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 yi eld 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
.471

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 Bil l 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 rule s, the state has successfull y 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 chan ges, 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 enforc e 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 reduction s in HAP emissions equivalent to or greater than the proposed rule. **b. Support for s**  **pecific s**  **tate/ l**  **ocal or EG** **U .**  **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 m ercury

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 entirel y b y 2020. Commenter urges the EPA to expand on this concept in the final rul e 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 earl y 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 install472

po llution controls to reduce interim emissions of NO X by about 50 percent through the installation of advanced combustion controls, and to reduce SO 2 emissions through a combination of lower

- sulfur fuel and the installation of a DSIs ys tem. 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 (SO 2 , NO X , PM), Hg, other HAP, and GHGs
. In addition, the Boardman 20 20 Plan establishes a path toward significant reductions in CO 2 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 conne ction with other elements needed for compliance assurance, would be considered b y 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 he at 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 earl y. 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 SO 2 , 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 allo w 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 essentially473

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 anal ys is 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 . Specificall y, the commenter request s 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), identic al emission limits for other pollutants ( e.g ., acid gases ), and marginall y 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 stan dards and elements necessary for compliance assurance, may be considered b y EPA as no less stringent, i.e., “ equivalent, ” to the proposed utility NESHAP rule. **c. Concerns o**  **ver d**  **elegation .**  **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 4 3**  **:** Commenter 16859 requests that the EPA concurrentl y publish implementation guidance for this rule to stat es 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.474

**Response to Comments 3 7**  **- 4**  **3 :**  Responses to these comments are provided in the preamble to the final rule. **15 . Need**  **o ption for**  **p ercent**  **r eduction or**  **i ncrease**  **c om** **pliance a** **veraging t** **ime .**  **Comment 4 4**  **:** 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 complianc e averaging time were to be on a 12

- month rolling basis. Commenter 17737 states that I CR 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

disc ourage 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 4 4**  **:** We have addressed comments related to a percent reduction format elsewhere in th e final rule record
. **16 . Cannot**  **m eet**  **m ercury**  **e mission**  **r ate on**  **c ontinuous**  **b asis**  **. Comment 4**  **5 :**  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 highl y 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, th e 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 catal ys t degradation, etc.) or outside the utility ’ s control (e.g., vari ability 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 vari ability . A s demonstrated b y contemporaneous data collected by EGU owners or operators and submitted to the Administrator , approximately 180 EGUs are currently475

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 ye ar 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 p**  **ortable m**  **onitoring e**  **quipment .**  **Comment 4 6**  **:** Commenter 17740 requests the EPA to permit sources to measure concentrations of CO and NO X in the effluent stream before and after adjustments with portable monitoring equipment. According to the commenter, industry practice is to use portable anal yz ers located at the boiler outlet duct to measure CO and NO X during combustion tuning operations. **Response to Comment 4 6**  **:** 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**  **c larifications**  **n eeded**  **. Comment 4**  **7 :**  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 range s are specified in terms of day s, months and years, and that it is unclear whether the EPA is referring to calendar or operating day s. Commenter recommends that the EPA adopt operating days or operating quarters. The commenter states that these terms are u sed 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 4 7**  **:** The agency reviewed the comm enters’ 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 dis cussion 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

- ye ar old rulemaking is insufficient. **Comment 4 9**  **:** Commenter 18477 s tates 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, installation476

of costl y control technology on these units to comply with the EGU MACT for the relativel y short time frame before retirement would also represent significant economic inefficiency . Commenter estimates that installation of emission control equipment for Hg, HCl, H F, and PM would cost at least $696 million, based on preliminary quotes provided b y 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 extremel y difficult for companies to develop a cost

effective compliance plan without control equipment vendor guarantees. Ven dor 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. Accordingl y, Commenter urges the EPA to exercise its discretion and establish work practice standards for non

continental 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

- t erm viability of these programs are ultimatel y dependent on customer participation. According to the commenter, demand response and energy efficiency

programs are ty picall y more suited to be replacements for peaking type generation resources than tradition al base load generation. **Response to Comment 4 8**  **- 50**  **:** The EPA disagrees that established precedent, can and should not be used as justification for actions within this rulemaking. 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
.477 **CHAPTER 6**  **: IMPACTS AND COST ANALYSIS**  **6A**

**– Impacts/Costs:**  **Em ission 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 th e 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 a ssessment since these benefits are a consequence of the rule, regardless of the rule ’ s intended purpose. This rule is expected to achieve substantial PM 2.5 health benefits resulting from primary PM and SO 2 emission reductions, and these co

- benefits have be en included in the regulatory impact assessment
. **Comment 2** : Commenter 17385 asks that the EPA perform additional energy efficiency sensitivity anal ys es incorporating additional policies. The commenter is pleased with the Integrated Planning Model (IPM) an al ys is of demand

- side energy efficiency

impacts on moderating electricity demand and reducing compliance costs. The IP M 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 ty pes that are leading to increased investment in end

use 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/y r/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
. ” Infact, there is no such goal described in all of CAA section 112 and today ’s rule complies with the requirements of section 112(d) to establish technological standards based on what has been achieved in practice b y the best performing sources in the category . If the commenter i s actually

commenting on whether the proposed regulation will adequatel y 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 n ecessary to further limit HAP emissions from EGUs 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 need s, of which 80% is coal

- fired. The commenter also478

states that 50% of this coal

- fired equipment was constructed under CAA NSPS and more than 60% has FGD or scrubbers to control SO 2 emissions. Also, more than 6,000 MW of the generating capacity has been retrofit with NO X controls, and SCR. Nearly all of the equipment has low NO X burner technology , making the aggregate cooperative coal

- fired generation newer and better controlled than the overall electric utility

sector. **Response to Comment 4:** Existing polluti on control technologies are available for EGUs to comply with MATS , including controls that reduce Hg, non
- Hg metal and and particulates, and acid gas HAP, including HCl. **Comment 5** : Commenter 17768 states that the rule is justified based on the co

- benefits that stem largel y 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 anal ys is for the regulation. **Response to Comment 5:** The EPA agrees that it is valuable to quantify the PM 2.5 health co

- benefits 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 PM 2.5 health benefits resulting from primary PM and SO 2 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 emissio ns 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 reasonabl y accurate estimates of benefits, the most important feature of the EPA ’ s approach is having an accurate projection from 2005 to 2016, so th at the emissions reductions and economic downturn referenced b y 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 red uctions in emissions that have occurred from 2005 to present. The data used at proposal were updated to reflect the comment process on the Cross

- State Air479

Pollution Rule (CSAPR), for which number eastern states provided detailed updates to the EPA ’ s emissi ons 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 20 16 baseline, and the inclusion of non

EGU plant closures, federally enforceable emissions reductions, and consent decrees that have happened since 2005. Finall y, 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.480

**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 Com ment 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

EP A anal ys is). EPA did not state that compliance options for criteria pollutants will not reduce HAP emissions as commenter suggest, only that there may

be compliance options (e.g. purchasing allowances in a trading program) which may not lead to HAP emissio n reductions
. We direct the commenter to Section III of the preamble to the final rule for a discussion of the hazards to public health and the environment attributable to EGUs. **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 SO 2 emissions and 62% in NO X emissions from Texas EGUs from 1995 to 2009 and the fact that nearl y 50% of the coal

- fired capacity in Texas has FGD systems. The commenter also points out that national concentrations of PM 2.5 and PM 10 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 b y other requirements of the CAA, and the EPA has done so in the technical anal ys es 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 in clude these emission reductions achieved through promulgated regulations, settlements, consent decrees, and closures in the baseline for future ye ar anal ys es . Because the CSAPR has significant impacts on emissions from U.S
. EGUs , the EPA specificall y accounted for CSAPR in the baseline. As such, the EPA has accounted for emissions reductions since 2000 in the anal ys es 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 recentl y 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 SO 2 and NO X emissions by 57% since 1980. Mercury has been cut b y 40%. This has occurred while electricity use has increased b y 85% and electricity from coal generating facilities 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 undermin es all this hard work. Not only does the proposed Utility MACT rule in its current form481

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 b y the commenter, but rather builds on them by requiring that coal

- fired power plants control highl y toxic HAP emissions to a level that is currentl y being achieved by the best performing EGUs . 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 illnesse s including asthma attacks and other respiratory s ymptoms in children. **Comment 4**  : Commenter 18037 believes the use of base ye ar 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. Finall y, 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 reasonabl y 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 b y 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 r ule 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 si nce 2005. Benefits of the rule are based on emissions reductions projected b y 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 benef its 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 the ir emissions to area source levels. The commenter believes that applying generall y achievable control technology (GACT) to these facilities recognizes the investment already made. **Response to Comment 5**  **:** The EPA has addressed comments relating to area sourc es elsewhere in the preamble to today ’s rule as well as other portions of this document.482

**Comment 6**  : Commenter 18434 states that the proposed rule ’ s output - based emissions limits appear to consider onl y 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 b y 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 th at 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 IG CC process is extremely effective for the removal of PM and that the f

abric 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 IP M modeling does not reflect the addition of a fabric filter to IG CC 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. **Com ment**  **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 SO 2 emissions, and ambient PM 2.5 , rather than HAP . The commenter also believes that the EPA exaggerates the PM 2.5 emissions, which are already addressed under other CAA programs. **Response to Comment 10**  : The EPA disagrees with this commenter that PM 2.5 health co

- benefits should be excluded in the estimation of benefits expected b y 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 achieve483

substantial PM 2.5 health benefits resulting from primary PM and SO 2 emission reductions, and these co

benefits are thus an important category to quantify. Consideration of ancillary benefits in benefit

- cost anal ys is is directed by OMB Circular A

- 4 (p. 26, available at: http://www.whitehouse.gov/omb/circulars_a004_a

- 4/):

“Your analysis should loo k 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 ty pically unrelated or secondary

to the statutory purpos e 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 b y 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 anal ys is 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 a ssociated 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 PM 2.5 health benefits, and direct health benefits of reducing SO 2 . I f we were able to fully monetize these benefits, the benefits would exceed the costs by an even greater amount than we currentl y estimate. The EPA disagrees that the quantified PM 2.5 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 b y a rule beyond control requirements for other rules . I f this rule was duplicative with o ther 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 emi ssions reductions achieved by MATS alone. Further, the PM 2.5 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 hyp othesize, but do not predict, the control strategies that states may choose to enact when implementing a NAAQS. The setting of a NAAQS doe s 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.484

However, some costs and benefits estimated in this RIA account for the same air quality improvements as estimated in the illustrative PM 2.5 NAAQS RIA. In implementing these rules, emission controls may lead to reductions in ambient PM 2.5 below the PM NAAQS in some area s. 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 compo nents of the total benefits estimate.485

**6C**

**– Impacts/Costs: Energy Impacts**  **Comments are addressed elsewhere in this document.**486

**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, PM 2.5 , or other pollutants. **Comment 2:** C ommenter 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 b y 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 transportatio n, including a consideration of rail competition. This is reflected in the results presented in the RIA . In recent ye ars, railroads have increased coal transportation rates in real terms wherever they have the opportunity. However, rail rates at plants cap tive to a single rail carrier are now close to the maximum levels prescribed b y 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 impact s 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 fro m the production, transport and use of natural gas. C ommenter 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, long

distance 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 apparentl y do not provide a reasonable basis to discourage fuel switching from coal to natural gas.487

**Response to Comment 3:** The primary basis for EPA’s rejection of fuel switching to natural gas was that the switch would not be co st effective, not because of the non

- air quality health and environmental impacts. We do note, however, that natural gas extraction through hydraulic fracking is a relativel y new process and, while it can be safel y undertaken, there remains some level of uncertainty about the level of expertise available to do so in all instances. **Comment 4** : Commenter 17833 expresses concern that the proposed rule may impair the reuse of coal combustion residuals (CCR) such as flue gas desulfurization gy psum (FGD gy

psum). 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 anal ys is is incomplete and cannot be properl y evaluated. The commenter explains that the use of FGD gy psum 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 gy psum into building material, and kept it out of landfills. In order to be used by most wallboard plants, FGD gy psum must be formed in a multistage process to precise specifications by the electric utilities. Converting operations to handle a different gy ps um material requires plant closure and expensive re

commissioning of the plant, as well as additional costs for transporting natural gy psum, which can approach the cost of the final product. The commenter discusses the 30 ye ars the FGD gy psum 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 Sy nthetic Gy

psum 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 Gy

psum, ” 16 Human & Ecological Risk Assessment 317
- 39 (2010); Scott Shock et al. , “ Evaluation of P otential for Mercury Volatilization from Natural and FGD Gy psum 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 Manag ement S ys tem: Identification and Listing of Special Wastes; Disposal of Coal Combustion Residuals from Electric Utilities, Comments Submitted by the Gy psum Association. ” The commenter states that the loss of FGD gy psum 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 gy psum wallboard. **Respo nse to Comment 4:**  The EPA does not expect a significant impact on the availability of FGD gy psum due to MATS. IPM analy sis shows a potential 6 GW reduction in wet FGD operations, not all of which produce gy

psum. This is a small fraction of the total 180 GW of wet FGD projected to operate in the base case , and should have an insignificant impact on the availability of FGD gy psum . **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 b y 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 adequatel y 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.488

**Response to Comment 5:** Waste streams associated with conventional emission controls for NO X , SO 2 , and PM are already well regulated, and the costs of compliance with those regulations were considered as part of the promulgation of th ose rules. MATS may increase the number of waste streams that will have to be properl y 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 disp osal 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 benefit/cost assessment of the MATS rul e 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 properl y evaluated as phys icall y 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 b y 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 CO 2 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 increas ed hourly emissions of CO 2 . The EPA is currentl y 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 b y the numeri c 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 highe st 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.489

**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 b y 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 feasible and, thus, the provisions of CAA section 112 (h) are not met.490

**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, 184 28, 18433, 18434, 18437, 18486, 18497, 18500, 18575, 19114, 19121, 19199, 19212, 19213, 19653, 18023 **1. Impacts**  **analys e**  **s are**  **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 e conomic and reliability

anal ys is 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 a sk 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 analy sis of all the rules and guidance on cost

effective multi

-pollutant responses. Commenter 17815 asks that the EPA especially consider impacts on regions such as Texas which rel y more heavil y 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 anal ys is of the combined impacts. **Response to Comment 1:** The final CSAPR was included in the baseline analy sis for MATS and other finalized air rules and regulations. As explained in the preamble to today ’s rule, the EPA considered impacts on regi onal bases as part of its overall analy ses, and these are discussed in the RIA and other technical supporting materials. The Agency

did not prepare a cumulative impact anal ys is 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 anal ys is. A cumulative impact anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low benefit regulation among other rules that may

have large net benefits. B y anal yz ing 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 **c** ommenters (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 beyond491

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 accuratel y 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 anal ys es . The methodology and assumptions m ade for the anal ys is of the rule were included in the RIA that accompanied the proposal. EPA modeling and projections are intended to be a reflection of possible compliance using specific tools, assumptions, and methodologies that the a gency 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 has conducted detailed impact anal ys is of the rule, which shows reasonable impacts to retail electricity prices. The analysis provides a rich characterization of regional issues, and reflects the difference s 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 employ ment anal ys is which shows some potential positive and negative employ

ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 3: C**  ommenter 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 accuratel y 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 analy sis. As such, the EPA relies upo n guidance from its independent scientific and economic review panels and employs peer reviewed processes and technical literature in completing its anal ys es . The methodology and assumptions made for the anal ys is of the rule were included in the RIA that accompanied the proposal. 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 has conducted detailed impact anal ys is 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. 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 employ ment anal ys is which shows some potential positive and negative employ

ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy.492

**2. Ge**  **neral 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 sy stem and customer base. Some of these commenters cite EO 12866 and/or 13563 specificall y 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 s ys tem reliability and minimizes cost impacts on consumers. Commenter 17 701 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 are permitted by the statute . The EPA does not endorse any specific pollution control technology . The MACT standard is a technology

- based standard that is established by considering the maximum emission reductions currentl y achieved b y the best performing EGUs in the category . Individual facilities are free to use whatever technolog ies, 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 among existing sources in the same subcategory to demonstrate compliance ; use of surrogates to determine compliance ; choice for existing sources to comply with input

- based or output

- based limits ; and guidance on appropriate us e of the 1
- ye ar 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 appropriatel y incorporated provisions in the proposed rule to provide regulated EGUs wi th 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/ furan **s** 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.493

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 **e**xplains 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 polluti on 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

- effec tive air pollution control technologies. **Comment 8**  **:** Commenter 17055 mentions that their initial assessment did not consider impacts the RI CE 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 significantl y 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 uni ts 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 anal yz ed 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 appropriatel y 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 issues 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 analy sis 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 economic494

impacts that utilities will need to consider when planning for compliance. The commenters present an estimation of compliance costs from this analy sis of $17.8 billion in annualized compli ance 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 an d 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 acc ordance with requirements outlined in the CAA. The EPA has conducted detailed economic impacts anal ys is 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 exc ellent track record of installing pollution controls without greatly impacting electricity prices. The report cited b y 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 1 0**  **:** 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 c oal fired units retired in response to the proposed rule 3. In creases in natural gas prices 4. In creases 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, IC F , and Burns & McDonnell and explain how its approach as directed b y EO 13563 utilized the best available techniques to quantify

anticipated present and future benefits and costs... ” The commenter further states that the EPA does not consi der 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 1 0**  **:** The a gency did not prepare a cumulative impact anal ys is to accompany the rule for the following reasons: 1) the various EO requirements that the a gency must compl y 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 analy sis. A cumulative impact anal ys is lumps several regulations together and can potentially mask a high

- cost/low benefit regulation among other rules that may have large net benefits. By anal yz ing 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 the 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 impac ts of MATS. These results are presented in Chapter 3 of the RIA. Additionally , the a gency

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 and495

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/summary report.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 C AA Amendments and associated programs significantl y 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 b y which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikel y 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 1 1**  **:** Commenter 17702 qu estions 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 especiall y questions the EPA ’ s assumption that new natural gas from shale formations will provide sufficient gas to allow fuel switching f rom 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 Comm ent 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 anal ys es that explore key parameters in order to ensure its anal ys es are as accurate and reliable as reasonabl y possible , and the corresponding impacts (including cost) can be found in Chapter 3 of the RIA for the rule. To the extent that the background in formation 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 accuratel y 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 anal ys is. 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 anal ys es. The methodology and assumptions made for the anal ys is of the rule were included in the RIA that accompanied the proposal. **Comment 1 2**  **:** 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 greatl y 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 Kentucky496

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 1 2**  **:** 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 anal ys is 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

- effective ly than the EPA can sometimes anticipate. **Comment 1 3**  **:** Commenter 17743 stat es 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 1 3**  **:** The standards do not cover all power plants in Oklahoma. Rather, the standards appl y to coal

- and oil

- fired EGUs of greater than 25 MW
. The EPA has conducted a detailed national impact anal ys is 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

- effective ly than the EPA can sometimes anticipate. **Comment 1 4**  **:** Multiple c ommenters (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 carefull y anal yz e the cost estimates and impact on grid reliability and energy

costs and revise the final rule appropriatel y, or withdraw the rule entirely since it can ’ t be justified technicall y or economically. **Response to Comment 14 :**  The agency prepared a resource adequacy analysis for the proposed rule and has revised that anal ys is 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 re sults 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 1 5**  **:** 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. **Resp onse to Comment 1**  **5 :**  The EPA is sensitive to the concerns raised b y 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. A dditionally, a unit that employs neural net combustion optimization software during all periods of normal operation may497

not exceed 48 months between burner inspections. This allows the burner inspection to be combined with other criti cal work projects that require internal access to the unit, and reduces the overall cost burden of the work. **Comment 1 6**  **:** 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 1**  **6 :**  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 necessaril y project impacts based on an identical policy
. The EPA has conducted detailed impact anal ys is of the rule, which s hows 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 1 7**  **:** Commenter 17775 reports that a comparison of a Hg

- onl y 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 1 7**  **:** 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 compl y with the rule (including the potential for an additional year for the installation of controls), and capital costs are typicall y amortized over an extended period of time. Comparing the estimated costs of complyingwith today ’s rule with those of a Hg

- onl y rule is inappropriate, as the EPA is establishing standards for all HAP emitted from EGUs consistent with CAA section 112. The preamble provides further discussion of the legal req uirements that the EPA has sought to compl y 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

- effective ly than the EPA can sometimes anticipate. **Comment 1 8**  **:** Commenter 17813 points out that fabric filters were not included in costs for beyond

- the

floor limits, but should be included since it is still unknown if ESPs c an meet the PM standard. **Response to Comment 1 8**  **:** 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 haz ardous 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 s , and under highways. These costs are not498

considered in the estimated cost for the p roposed 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 pro viding a response. The EPA is addressing issues related to coal combustion residuals in a separate rulemaking. **Comment 2 0**  **:** Commenter 17824 discusses the proposed ozone limits being lowered from 0.075 ppm to 0.060
- 0.070 ppm **.** The commenter states that a limi t 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 non

attainment status, leading to a cost of $20

- $90 billion annually and potentially

costs up to 7 million jobs by 20 20 and close many

of these counties to new business. **Response to Comment 2 0**  **:** 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 r ulemaking. **Comment 2 1**  **:** 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 currentl y targeting utilities. **Response to Comment 2 1**  **:** Th e 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 final rule 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 anal ys is
. **Comment 2 2**  **:** Commenter 176 86 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 consi der 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 SO X contro l technologies to cost approximately 3 times more per MW for small units. (The commenter includes the following references : U.S **.** Utilities: Coal

- Fired Generation I s 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 2 2**  **:** The EPA ’ s anal ys is includes scaling factors for pollution controls, depending upon the size of a particular unit. See documentation for the IPM for more detail
. **Comment 2 3**  **:** 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 modif ications to meet HCl limits. The costs are estimated to be $60 million for one facility
.499

**Response to Comment 2 3**  **:** 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 2 4**  **:** Commenter 18425 expresses concern about the compliance costs of the acid gas c ontrols, 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 2 4**  **:** 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 anal ys is 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. Comments concerning the necessary finding and section 112(d)(4) standards are addressed elsewhere in the final rule record. **Comment 2 5**  **:** Commenter 19121 considers the EPA ’ s estimated compliance costs to be underestimated since forced retirements and fuel switching are not properl y attribut ed. **Response to Comment 2 5**  **:** 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 2 6**  **:** 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 **] Respons**  **e to Comment 2 6**  **:** The EPA has included a separate category for non

- continental liquid oil

fired EGUs (see preamble). **5. Proposed rule does not properly account for all other impacts. Comment 2**  **7 :**  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 2 7**  **:** 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 a very small amount of the coal fleet could retire in response to the final rule 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy
.500

**Comment 2 8**  **:** 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 coal

fired 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 comm enter 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 2 8**  **:** The benefits of this rule encompass the benefits of Hg reductions and co

benefits to health achieved via PM 2.5 reductions. The EPA has conducted detailed economic impacts anal ys is on the regulated sector, and finds the impact s of th e rule on the regulated sector are 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y 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

- ye ar period for sources to come into compliance. Sources may also seek a 1

- year extension of the compliance period 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. C omm enters believe energy efficiency

had onl y 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 complian ce 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 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 considerable flexibility in accordance with the requirements of CAA section 112
. 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 believe s 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 may 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 3**  **0 :**  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 b y $2 billion in 2015, $6 billion in 2020 and $11 billion in 2030. Commenter 18434 believes that since energy

- efficiency investments are concentrated in densel y501

populated areas with highest demand, even limited policies in the existing sensitivity anal ys is are likely to have greater benefits than estimated. This commenter also states that both state and federal policy makers 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 anal ys is 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 favorabl y from facilities making efforts to advance efficiency
. **Response to Comment 3 0**  **:** 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 may occur b y 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 3 1**  **:** Some commenters (17689, 17824, 17887, 17912, 18021, 18037, 18500, 19212, **18023** ) express concern about the combination of multiple regulations currentl y proposed and the limited timeframe for compliance with these proposed rules. Commenter 17689 mentions the NSR and permi tting requirements for the installation of control technology , and the fact that this process can take over a ye ar. This would be likely to create a backlog at state agencies, making it nearl y impossible to meet the compliance timeline. Commenters 17824 an d 18023 in particular cite the EEI **s** tudy that found 50% of the U.S **.** coal fleet may be unavailable b y 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 p articularly problematic for IP Ps , because 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 eco nomies of scale, or co

- benefits that could be realized by the installation of one ty

pe of equipment as opposed to several. Also, this commenter discusses the phys ical 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 financiall y imprudent. **Response to Comment 3 1**  **:** One of the purposes of developing the NSPS and MATS rules in tandem was to facilitate more cost

- eff ective compliance planning by affected source owners and, 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 3 2**  **:** 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 3 2**  **:** 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 to502

the extent possible
. Inaddition, 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
- 21 98 (D.D.C.). That decree requires the EPA to sign the final MATS rule by December 16, 2011. **Comment 3 4**  **:** Commenter 18023 reports that the roughl y 400 GW of capacity affected by

the proposed rule and other pending or new regulations are vital to adequate ele ctricity supply and provide substantial generator- supplied frequency control capability

to the bulk power s ys tem. 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. Sy stem changes in the electricity industry must be evaluated in advance so the s ys tem can be planned and operated such that the causes and effects can be understood, and cost s and problems minimized. **Response to Comment 3 4**  **:** The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2 % of all coal

- fired capacity) and that coal

- fired generation will not change significantl y. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence that will help serve load. Inaddition, 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. C**  **omment 3 5**  **:** 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 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 b enefits while maintaining s ys tem reliability and minimizing costs. **Response to Comment 3 5**  **:** To the extent possible, the EPA has coordinated the rulemakings. However, CAA section 112 provides statutory compliance times which preclude doing much of what comme nter seeks. Other comments on the compliance time issue are responded to elsewhere in the final rule record
. **Comment 3 6**  **:** 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 elderl y, minorities and low

- income citizens. The commenters consider the prominent rules at issue to include: (a) 2010 NAAQS for NO 2 **;** (b) 2010 NAAQS for SO 2 **;** (c) 2011 NAAQS for ozone; (d) 2011 NAAQS for PM 2.5 ; (e) 2011 Cross State Air Pollution Rule (CSAPR);503

(f) 2012 Revisions to the CSAPR; (g) 2011 Industrial Boiler MACT ; (h) Regional Haze Rule; (i) GHG PSD and T itle 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 L oad 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 3 6**  **:** The EPA acknowledges that elderl y, 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 elderl y, 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 anal ys is to accompany the rule for the following reas ons: 1) the various EO requirements that the agency must compl y 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 regulati on; 3) estimates specific to a particular rule are more transparent than those from a cumulative impact analysis. A cumulative impact anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low benefit regulation among other rules that may have large net benefits. By

anal yz ing each regulation separatel y, 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 Cle an Air Act Amendments. The study examines the cumulative impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summary report.pdf). As shown in the report, the direct benefits from the 1990 Clean Air Act Amendments reach almost $2 trill ion 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 signific antl y 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 unlikel y this result would be reversed504

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 every thing 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 sufficientl y quantified. The commenter questions the validity of the statement and asks the EPA to develop and implement a proce dure 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 PM 2.5 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 anal ytical ob jectives 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 RIA s hy pothesize, 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 merel y illustrative and are not int ended 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 PM 2.5 and ozone NAAQS RIA , but these effects are only counted once when considering cumulative costs and benefits. **Comment 38**  **:** Commenter 18033 addresses the EPA ’ s decision to wait until the NSPS for GHG emissions rulemaking before considering coordinated c ontrol 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 re gulations 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 , whi ch 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.** 505

**Comment 39**  **:** Commenter 17732, as a trib al nation and small government landlord of affected EGUs , states that the EPA is obligated to consult with the commenter and anal yz e 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 significantl y. The commenter is concerned that the proposed rule will create a recurring threat of severe reductions in the revenue rece ived 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 **,** S0 2 , PM, Hg and other hazardous pollutants from these EGUs , which would signif icantl y 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 anal yz e 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**  **:** L andlords of affected facilities are not included in the definition of an affected small entity

and, thus, were not included in the EPA ’ s anal ys is 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

- ye ar 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). **8. Methodology and assum ptions in calculations.**  **Comment 4 0**  **:** Commenter 17810 recognizes that the EPA can consider costs as part of the beyond

- the

floor anal ys is, but asks that the EPA clarify the methodology

and assumptions used and expand the anal ys is to include potential cost e ffectiveness 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_Table2Pa ge17.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.506

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 scientificall y sound, since the report onl y 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 o r 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

anal ys is showing the costs of retrofit options for different size units and fuel price points. C ommenter 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. **R esponse to Comment 40**  **:** The EPA disagrees with commenter's assertion that NGCC repowering and coal

- to - gas (CTG) switching at existing coal plants were not adequatel y evaluated. The EPA's IPM modeling inherently

considers new NGCC capacity as an alternative to continued operation of existing coal units, with and without retrofit air emission controls. The EPA's IPM modeling for MATS also offers a CTG option for existing coal units, wherein the CTG capital cost is properl y scaled to the existing unit size. The EPA's TSD discussion of CTG used an average unit size of about 300 MW only to illustrate the approximate average economics of alternative (and collective) control options, including CTG. The EPA has full y 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 generation technology

assumptions, pollution control cost assumptions, fuel supply assumptions, and financial assumptions governing the power sector
. **9. Energy efficiency reduces compliance costs and emissions.**  **Comment 4 1**  **:** 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. (February 2011), at http://www.rggi.org/docs/Investment_of_RGGI _Allowance_Proceeds.pdf (accessed July 8, 2011). **Response to Comment 4 1**  **:** 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 rul e with considerable flexibility in accordance with the requirements of CAA section 112 . 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 th e 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.507

**Comment 4 2**  **:** Commenter 17929 states that new boilers can reduce emissions by incorporating energy

efficient 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 4 2**  **:** The EPA generall y agree s and thanks the commenter for their observation. **Comment 4 3**  **:** Commenter 18421 discusses the role of energy efficiency

in reducing costs and preserving reliability . The commenter cites studies by McKinsey and Company , M IT ’ 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 typ e. A report b y Sy napse 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 Il lustrative 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 Crey

ts , Anton Derkach , Philip Farese , Sco tt Nyquist , and Ken Ostrowski **(**http://www.mckinsey .com/clientservice/ electricpowernaturalgas/downloads/us_energy _efficiency_full_ repo rt.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_Summary AssessmentAchievableEEPotential0109.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 Sy napse Energy Economics, Inc, No Need to W ait: Using Energy Efficiency and Offsets to Meet Early Electric Sector Greenhouse Gas Targets , May 2009.) **Response to Comment 4 3**  **:** The studies cited provide information on the cost

- effectiveness of energy efficiency policies that are generally consistent with the sources cited for the EPA anal ys is. **10. Fuel switching. Comment 4**  **4 :**  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 suppl y/ 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 nat ural 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.508

**Response to Comment 4 4**  **:** 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 anal ys is has fully considered and included the multitude of compliance options available to sources. The IP M analysis indicates that there will be a small amount of coal retirement s ( less than 2% of all coal

- fired capacity) 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. Th e EPA modeling full y reflects the costs of competing fuels, and the results can be found in Chapter 3 of the RIA . The EPA responds to comments associated with requiring units to switch to natural gas in response to comments on the beyond the floor anal ys is elsewhere in the final rule record. **11. Miscellaneous. Comment 4**  **5 :**  Commenter 17752 expresses concern about the risk of noncompliance for earl y action. The commenter explains that if controls are installed based on the proposed rule do not achieve the reductions required b y 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 4 5**  **:** The EPA is allowing a 3

- year compliance timeframe for existing sources affected b y the rule, and there are also conditions under which extensions could be granted (see preamble for additional discussion on timing
. **Comment 4 6**  **:** 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 4 6**  **:** 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. **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 inc orrect because the costs are more than what is necessary to protect public health. **Response to Comment 48**  **:** The EPA’s response to comments concerning the regulation of all HAP emitted from EGUs is addressed elsewhere in the final rule record
.509

**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 identif ied 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 b y the proposed rule on the sale of coal ash potentially

int erferes 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 u se of sodium

- based DSI and the impact it could have on marketability and beneficial use of fl y ash in concrete, wallboard, asphalt products, bridge construction and mine reclamation. The commenters state that around 134 million tons of coal combustion resi duals 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 beneficiall y, causing econo mic, 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 fl y 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 beneficiall y reused b y their organization annuall y, but this will end if they must install sodium

- based DSI or ACI . This will lead to loss of jobs and an econom ic impact on the utility plant and end users of the coal ash/coal combustion residuals.510

**Response to Comments 1 -**  **5 :**  Multiple commenters declare that DSI and ACI controls contaminate coal ash/coal combustion residuals, thereb y rendering the co

- mingled material unmarketable. The EPA notes (from the comments submitted) markets purchase d 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 qu antity 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 combusti on residuals producers, only 42 percent of ash sells to the market (56 million tons of 136 million tons) thereb y 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. Finall y, 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

fl y 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 ACIremain 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 considerabl y. 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 deriv ed 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 les s 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 SO 2 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
.511

As for activated carbon contamination issues, proper location of the injection point will prevent contaminating salable b y -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 thereb y eliminating the need for ACI . The dissolved water

- soluble Hg species is easily separated in the gy psum dewatering/wash ing 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 bui ldings, 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 increasingl y 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 likel y to be necessary and will increase compliance costs and the number of plants to retire since they cannot afford compliance. Some c ommenters (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 accuratel y 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 benefit s. 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 :**  DSIis commerciall y proven for acid gas control as vouched b y Babcock & Wilcox Company, one of the largest suppliers of air emission control systems in the world. According to B&W (http://www.babcock.com/library /pdf/ps

- 451.pdf

): “Dry sorbent injection (DSI) for acid gas control is not a new technology. DSIs ys tems have been in service for more than 20 years as an effective tool to reduce acid gas levels. SO2 and HCl emissions are typicall y controlled together. In some industrial applications, HCl may need to be controlled512

separately . Current and impen ding legislation are the drivers in determining the required emissions levels. DSIis a cost

- effective solution to control these emissions.” As discussed in the preamble, the EPA has used very conservative assumptions in modeling the projected use of DS I technology . See the preamble for the final rule for a more detailed discussion of DSI
. **Comment 8**  **:** Commenter 17758 agrees that DS I can be used for compliance at many units cost effectivel y, but strongl y 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 onl y five of those units use DSI without FGD
. **Response to Comment 8**  **:** The EPA does not believe that DSI and dry scrubbers will be the onl y compliance options for control of acid gases, and utilities will choose compliance pathways based on a variety o f considerations and available technologies. DSIis a commerciall y available technology and the EPA believes it will play an important role for achieving compliance. See preamble for further discussion on DSIand 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 s ystems using sodium bicarbonate indicate SO 2 removal rates in the range of 20

- 60%, which is below the >90% SO 2 removal ty picall y associated with wet scrubbers. The commenter includes a table showing removal rates for HCl and SO 2 at increasing bicarbonate flow rates in the range of 75

- 95% for HCl and 20

- 60% for SO 2 . The commenter reports that analysts believe th at DSI is likely to be used b y 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 SO 2 and NO X 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 l ogistically 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 ACIand 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, respectivel y 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. Th e commenter mentions the 26 GW of new SCR controls that came on line in 2003 to meet the NO X 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 ACIand 26 GW of new SCR for NO X control. Commenter 17648 confirms that ACI is a feasible control technology for Hg emissions, regardless o f the control technologies presentl y used to control for PM, SO 2 or NO X 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 b y the proposed rule. The commenter believes that sources can513

reasonabl y 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 F GD 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 th e proposed HCl limits. The commenter points out that 73% of the sources with HCl emission data in the I CR 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 SO 2 u sing DSI
. **Response to Comment 11**  **:** The EPA thanks the commenter for the information provided in support of the proposed rule. **Comment 1 2**  : 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 sy stem, such as conserving water with a dry scrubber as opposed to a wet scrubber and finding a way to use the calcium by

products. However, the proposed emission limits will require ACI, which will interfere with the ability to sell the by

product. **Response to Comment 1 2**  **:** Although wet scrubbers (WFGD ) use considerable amounts of water, approximately 90 weight percent of the w ater can be recovered in a gy psum 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 con figuration burning fuels with sufficient halogen content will oxidize Hg in the SCR followed by capture in the downstream WFGD thereb y eliminating the need for ACI . The dissolved water

- soluble Hg species is easily separated in the gy psum dewatering/washing process. Current scrubbing technology captures MATS acid gases with superior effectiveness relative to SO 2 ; 20 as a result, the EPA does not anticipate scrubber retrofits for MATS compliance on units equipped with a wet or dry

scrubber. 21 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. 22 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, especiall y bituminous coal units, high co

-
20 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011, pp. 11

- 12, 21 21 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 2011; p.7, Table 2

- 1 22 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011, p. 20514

benefit capture occurs without the need for ACI. For low rank coals, capture can be enhanced with bromide addition. Experience has shown that addition of oxi dizing agents (i
. e., bromide) and/or the use of sorbents designed to mitigate or avoid the adverse effects of activated carbon on fl y ash, including mineral

- based sorbents, are available and effective. 23 As a result, the EPA believes that facilities with dry s crubbers are especially well suited to comply

with the rule at relatively low expense. **Comment 1 3**  : 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 emplo ying 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 SO 2 removal by DSI to be too costly

and cumbersome to be practically applied. Specificall y, the commenters find the nozzle 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 SO X and other acid gases and will substantially benefit from regulation requiring DSI technology . The commenter points out that the document referenced b y 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 SO 2 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 fo rced to rel y 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 plug gage 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 1 3**  **:** The E PA has determined that DSI is an effective acid gas control technology

since MATS acid gas removal exceeds SO 2 capture rates with this technology
. 24 Despite comments claiming DSI as too costly or cumbersome, this control technology occupies less space and requires substantiall y less capital investment than a unit employing a wet or dry scrubber. 25 However, a DSIs ys tem ’ 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 DSIretrofit opt ion to units combusting fuel less than 2.0 lb SO 2/MMBtu. Pluggage issues result from poorl y designed s ys tems for powdered solids conveyance. A variety of causes can lead to blockage; for example, poorly designed piping s ys tems, inappropriate storage practi ces, incorrect sy stem 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 commerciall y available solutions to address these issues. 26 Pluggage problems at a particular facility do

23 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 ” Sy mposium, August 30

– September 2, 2010, Baltimore, MD 24 NESCAUM report; “ Control Technologies to Reduce Conventional and H azardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011, p. 22 25 ibid, p. 13 26 UCC web site; DSIFAQ #3 Plugging Issues. Web site: http://unitedconveyor.com/dsi.aspx515

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 1 4**  : 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. C ommenter 17758 also mentions that the cost for DSI varies from $4/MWh to $15/MWh and there are few suppliers of DSI technology , especiall y the Trona. C ommenters 17758 and 17775 cite difficulties with the Trona suppl y 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. Finall y, the commenters note that units using DSI or ACI often need PM control downstream, such as a baghouse or ESP and a baghouse ty

picall y 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 significantl y lower. On a levelized cost basis, however, the difference is far less significant... ” Commenter 17781 agrees with this conclusion and say s 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 1 4**  **:** The EPA disagrees with the commenters and does not expect that scrubbers are necessary

solel y for acid gas control under the MATS rule. The EPA has analyzed the suppl y 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 suppl y. Trona is a very reactive substance, and relativel y small amounts are required to control HCl. Trona DSI has also been shown to improve ESP performance, so that a fabric filter is generall y not necessary unless otherwise needed for PM contro l
. As discussed in the preamble, recent testing shows that trona DSI control of HCl with an ESP is very nearl y as effective as with a FF. 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 1 5**  : Commenters 17765 and 18033 report that private sector estimates of retirements are higher than the EP A ’ 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 . C ommenter 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 informatio n 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 1**  **5 :**  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 generally516

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 m ay involve owner preferences and site specific circumstances. Also see the preamble for the final rule for a further discussion of DSI
. **Comment 1 6**  : 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 adversel y affect s baghouses, and require s that three times the normal amount of ACI be used to achi eve 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 1 6**  **:** The EPA is aware that there is some data suggesting DSI can adversely impact ACIperformance. Inparticular , the Presque Isle tests where this was observed were for SO 2 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 ty picall y has low HCl emissions and likely will not nee d additional controls for HCl in most cases. On the other hand, DSI can improve ACI performance for bituminous units because of the reduction in SO 3 , which interferes with ACI capture of Hg. DSI using 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 adversel y affects PM and Hg control. Insufficient bag house capacity or excessive sorbent injection rate can adversel y affect PM co ntrol performance
. 27 An improper operating temperature reduces activated carbon ’ s ability to capture Hg 28 while high concentrations of SO 3 compete with mercury for capture. 29 DSIs ys tems failing to remove sufficient SO 3 negativel y impact ACI system performanc e. 30 Hg speciation exiting the furnace significantl y impacts controls selection and performance, with multiple factors affecting speciation (e.g., fuel constituents, halogen presence, installed emissions controls, and temperature). 31 , 32 ESP performance ty

pically improves with sodium based sorbents; on the other hand, a calcium based species tends to negatively impact operation. 33 The brown plume phenomenon apparentl y can occur under conditions of high treatment rates on units that do not have NO X controls, 34 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 b y the Presque Isle tes ts, one sy stem produced a brown plume; on the other hand,

27 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 2011; p.A

- 10 28 Ib id., p.A

- 8 29 Ib id. 30 Ib id. 31 Solvay Chemicals publication “ Mercury (Hg) ” 32 Tutorial: Mercury

Chemistry

in Boilers and Mercury

Control Technology

(Part 1) by

C Senior, Reaction Engineering Intl., 30 th International Technical Conference on Coal Utilization & Fuel Systems; April 17

- 21, 2005 33 UCC web site; DSIFAQ #1 ESP Performance. Web site: http://unitedconveyor.com/dsi.aspx 34 Sjostrom, S.,Senior, C., Durham, M., Bustard, J., “ INTEGRATED MACT COMPLIANCE PLANNING, ” http://www.adaes.com/PDFs/presentations/AQVIII

Integrated%20MACT%20planning.pdf517

over 30 other DSI s ys tems did not generate a brown plume. 35 Also see the preamble for the final rule for a further discussion of DSI
. **Comment 1 7**  : 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 b y 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 1 7**  **:** 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 tons in 2010. 36 Production peaked at 18.1 million tons in 2006. 37 In2010, end consumers received 176,000 tons of Trona via direct shipment 38 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 one

half of the 10 million tons of soda ash produced in 2010. 39 Currently , the industry ( ANSAC ) alleges unfair foreign practices negativel y impacting domestic exports. 40 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 competitio n practices negativel y i mpact export s - 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. S ee the preamble for the final rule for a further discussion of DSI
. **Comment 1 8**  : Commenter 17790 explains that the EPA ’ s anal ys is of emission reduction technologies required b y 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 anal ysis showed that DSI is only economical on units which are able to achieve compliance

- level r eductions of HCl using ESPs, and spending additional money on fabric filters is not economical for them. **Response to Comment 1**  **8 :**  The EPA ’ s IPM modeling for the MATS final rule now takes into consideration that there are less costl y options than FF for PM c ompliance, particularl y the upgrading of

35 “ Comparison of Sodium Bicarbon ate and Trona for SO2 Mitigation at a Coal

- Fired Plant” b y 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 36 http://www.wma

- minelife.com/trona/TronaPage2/trona_production.htm 37 ibid 38 http://www.onrr.gov/ONRRWebStats/StateAndOffshoreRegions.aspx?state=WY&yeartype=FY&year= 2010&dateT yp e=AY 39 http://minerals.er.usgs.gov/minerals/pubs/commodity /soda_ash/mcs

- 2011
- sodaa.pdf 40 http://www.ansac.com/news/2011/06/01/518

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 anal ys is has conservatively has not incorporated. For the se reasons, many units that were previousl y modeled as installing a FF may find that only the installation of DSIupstream of the existing ESP may be needed for MATS compliance. Also see the preamble for the final rule for a further discussion of DSI. **Comm ent 1**  **9** : Commenter 18033 requests that the EPA address integrated planning after the proposed NSPS for GHS from EGUs are issued to create a cumulative cost anal ys is. 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 ty pe 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 SO 2/MMBtu. ” (Footnote 57 to EPA

- HQ
- OAR
- 2009
- 0234
- 18033
- A2 gives NMA revi sed cost estimates for DSI.) **Respons e 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. **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 currentl y 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 ye ars 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 SO 3 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 SO X and HCl reduction. However, the method can also lead to air preheater pluggage in some cases. The commenter describes a field te st program in which Trona or sodium bicarbonate was used to achieve high HCl and SO 2 removal rates without pluggage problems. The commenter explains that the site has an atypical s ys tem including both hot

- and cold

- side ESP, and sorbent was injected upstre am 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 SO 2 removal perf

ormance 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.519

**Comment 21**  : Commenter 18424 considers the EPA estimates for control technologies to be su spect since they may not be appropriate for use b y 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. S ee 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 in each subcategory for the different emitted HAP. The EPA 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 2 2**  : Commenter 18023 disagrees with the assumption that 56 GW of coal plants will not need a FGD s ys tem 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 re quired 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 . ( Comme nter 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 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 co mpliance costs so the commenter asks that the EPA update cost assumptions to account for these requirements. **Response to Comment 2 2**  **:** 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 2 3**  : 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 2 007 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 2 3**  **:** 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 anal ys is for the MATS final rule. **Comment 2 4**  **:** Commenter 17775 questions the EPA ’ s conclusions about the effectiveness of DSI since they are based on limited information and incomplete anal ys es. The commenter points to I CR data from plants using DSI systems to see that only 11 of the 28 units using DSI do so to control SO 2 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 &520

Lundy report cited b y 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 SO 2 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 2 4**  **:** The EPA disagrees with commenter ’ s conclusions. Also see the preamble for the final rule for a further discussion of DSI. **Comment 2 5**  : Commenter 18963 notes that there have been no commercially demonstrated applications of DSIfor the control of HCl from coal refuse

- fired CFB units. Further, even to the extent that it is technologicall y 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 b y acid mine drainage. **Response to Comment 2 5**  **:** S ee the preamble for the final rule for a further discussion of DSI
. **Comment 2 6**  **:** 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 ( “ IP M Parsed Results

- Policy Case, ” Unplanned DSI Installations by 2015 includes Asbury : 2076_B_1). **Response to Comment 2 6**  **:** The EPA believes that DSIhas 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, potentiall y, low

- sulfur bituminous coal). **3. Electrostatic precipitators. Comment 2**  **7** : 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 SO 3 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 HLSpurlock plants in the I CR PM database as examples of this approach and explains that this alternative has the advantage o f using existing air pollution control equipment with low increase in pressure drop.521

**Response to Comment 2 7**  **:** 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 2**  **8 :**  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 originall y 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 2 8**  **:** Commenters recalling price escalation during CAIR ’ s implementation phase understandabl y 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 wi ll compete for work to utilize idle resources. As an indicator, demand for power plant construction labor declined from its peak in 2008. 41 For example, Colorado Springs Utility

plans to retrofit its 254 MW Martin Drake unit with a FGD for $113 million with projected construction completed b y 2014. 42 , 43 Timeline compliance date attainment and available resources are addressed in the preamble fo r the final rule and Response to Comments section 5C01 “ Compliance Dates. ” **Comment 2 9**  : 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 generall y do not allow any construction preparation until permits are granted. **Response to Comment 2**  **9 :**  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

41 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 42 http://www.power

- eng.com/articles/2011/10/coal

- fired

-power -plant

- to - receive

- emissions

- control

system.html 43 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

- control522

units) with scheduled start dates of 2013 and 2015. 44 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, especiall y 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. **Re sponse 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 . Th e EPA’ s IPM analysis for MATS limits DSIretrofit controls for compliance to fuels containing less than 2 lbm SO 2/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, solicit ation, review of bids and contract negotiations, permitting, landfill issues, obtaining financing, final design, mobilization of workforce, construction, process tie

- ins and startup testing. Commenter 17775 includes a memo (J. Edward Cichanowicz, “ Feasibil ity of Retrofitting Fabric Filter Particulate Matter Control Technology to the Electric Generating Unit Inventory as Projected b y 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
- ye ar compliance schedule, and even if given 4 years to comply , only 54% would be able to comply . The comm enter 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. C ommenter 17904 refers to Davis Cnty. Solid W aste 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 3 2**  : 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 ye ar. 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

44 B&W press release June 29, 2011 ; “ B&W to Design and Suppl y $54 Million Emissions Control System for Indiana Power Plant” ref: web site: http://www.babcock.com/news_and_events/2011/20110629a.html523

concerned that a facility

in the process of building replacement power may decide to operate a high

emitting unit for an additional year, specificall y 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 3 2**  **:** Iss ues regarding compliance dates, extensions, state programs regarding agreements, replacement power construction, etc., are discussed in the preamble for the final rule
. **Comment 3 3**  : Commenter 18017 states that if the proposed rule and other pending rules re quire installation of new control equipment costing hundreds of millions of dollars, the potential result could be earl y 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 3 3**  **:** The EPA will work closely with other regulatory

authorities to suppo rt timely implementation o f MATS. **5. One technology per pollutant. Comment 3**  **4** : 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 emissi ons, and which may

impact PM and Hg emissions. The commenter asks that the EPA refrain from developing 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 adequatel y reflect the cost for other sources of energy that may be required to make up for lost coal

fired 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 3 4**  **:** The agency reviewed all technologies presented within the proposal for adequacy and commercial avai lability ; moreover, independent publications and trade organizations conf irms their capability

towards achieving MATS compliance. 45 , 46 , 47 See the preamble to the proposed rule for a discussion of the pollutant

- by

-pollutant (or HAP

- by

- HAP) approach for establi shing section 112(d) standards
. Average projected cost increases to the rate payer are addressed in the preamble for the final rule
.

45 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011 46 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 47 EPA
- HQ
- OAR
- 2009
- 0234
- 17622524

**6. Dual liquid -**  **powder sorbent technology. Comment 3**  **5 :**  Commenter 17721 discusses a multi

- emission reduction technology calle d involving a dual liquid

-powder sorbent (DLPS), which is particularl y effective in removing Hg and other HAP by up to 98.7%, along with SO 2 and NO X emissions from coal

- fired EGUs without adding control equipment into the flue gas stream. The commenter sug gests that the effectiveness of the DLPS sy stem for high

sulfur 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 3 6**  : 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 ACIor 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 s ystem 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 3**  **7** : Commenter 17721 questions the proposed rule ’ s focus on ACItechnology , which works differentl y from DLPS technology because ACI and DSI involve injecting a sorbent into the flue gas 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, SO 2 and NO X 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 SO 2 mitigation, making it a reasonable or superior choice compared to the DSI sug gested 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 SO 2 emissions limits as an alternative to the HCl emissions limit. **Comment 3 8**  : 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 SO 2 emissions before the exhaust reaches the stack, where further emissions reductions could be achieved b y a scrubber. **Response to Comments 3 5**  **- 38**  **:** Multiple comments were received advocating control technologies that were not represented in the EPA ’ s compliance cost anal ys is 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 technologi es 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.** 525

**Comment 3 9**  **:** Commenter 17731 questions the EPA ’ s view that utilities can easil y 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 3 9**  **:** 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 eq uipment 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 als o been developed to avoid the sensitivity to SO 3 , so a high rate of Hg capture is maintained in ESPs. The commenter requests that the EPA revise the proposed rule to clearl y state that newl y developed and commerciall y- available products besides powder acti vated 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 analy sis 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 sele cting , 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 4 1**  : Commenter 17761 reports a dramatic decrease in performan ce of an ACI s ys tem 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 4 1**  **:** 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 understan ding its operation to continuously

achieve compliance. ACI is a proven technology for Hg removal with multiple successful installations. 48 This issue is addressed more full y el sewhere in the final rule record
. **Comment 4 2**  : 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 appl ying 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

48 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011526

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 4 2**  **:** The EPA thanks the commenters for the comments suppor ting the standard. **Comment 43**  **:** Commenters 17813 and 17816 state that the EPA fails to provide complete cost

- benefit anal ys is 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 beyond

the

- 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 anal ysis 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 b eyond

- 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 Prop osal 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 4 5**  : Commenter 17904 questions the EPA assumption that a unit equipped with ACIand a fabric filter can achieve the beyond

- the

- floor standard with no additional cost. The commenter explains that such sy stems have performance limitations and will not achieve the proposed limit consistently , so alternative and additional controls will need to be considered. The commenter agrees w ith the dismissal of fuel switching because the variable Hg content of lignite combined with captive mine mouth designs makes the economic impact a marker for establishing actual costs of compliance, which would be prohibitive. **Response to Comment s 4**  **3 -**  **45 :**  A quantitative analysis of costs was included in two beyond

- the

- floor TSD s 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
. 49 Comments claiming BTF Hg emission rates for lignite fuels as financially impractical and technicall y unattainable are unfounded. C ommercial products exist to augment 50 Hg capture by ACI
- such as ToxeconTM for hot side ESPs , halogen addition for PRB, 51 brominated sorbents for low chlorine fuels. 52 Sources may also blend fuels as part of a compliance approach.

49 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” p. 19, March 31, 2011 50 IC AC Report: “ Enhancing Mercury Control on Coal

- Fired Boilers with SCR, Oxidation Catalyst and FGD ” 51 NESCAUM report, op. cit., p.20527

The EPA acknowledges lignite coal may 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 financiall y prohibitive. ACIselectivel y captures the oxidized form of Hg regardless of fuel source or rank. 53 Yet, the presence of SO 3 interferes with Hg capture and req uires removal to avoid high activated carbon injection rates. 54 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 additi on 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. 55 , 56 Meanwhile, adjusting carbon injection rate will compensate for fuel Hg variability . Consequentl y, 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 4**  **6 :**  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 i ssued by the EPA. **Response to Comment 4 6**  **:** EPA notes that the statutory requirements for the Acid Rain Program are distinguishable from standards under CAA section 112. The EPA addresses subcategorization issues elsewhere in the final rule record. **Comment 4 7**  : 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 wes tern coal with low chlorine levels emits higher amounts of elemental Hg, and is more readil y 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 s ys tems 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 4 7**  **:** The EPA thanks the commenter for the comments submitted.

52 Assessment of Technology Options Availabl e to Achieve Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 2011, http://www.supportcleanair.com/resources/studies/file/4

- 8
- 11
- URSTechnologyReport.pdf 53 NESCAUM Report, op. cit., pp.19

- 20 54 Ib id. p.19 55 Solvay Chemicals publication “ Mercury (Hg) ” 56 IC AC Report, op. cit.528

**Comment 4 8**  : 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 4 8**  **:** The EPA det ermined further fuel subcategorization is unwarranted. The EPA addresses subcategorization elsewhere in the final rule record
. **Comment 4 9**  : Commenter 18033 quotes the EPA position stated in CAMR, “ [a]t some point in the future, the performance of control te chnologies 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 4 9**  **:** The EPA determined further coal subcategorization is unnecessary for compliance since commercially available technologies for SO 2 control exhibit superior removal performance for MATS acid gases. 57 For scrubbed units firing high sulfur coals, sufficient MATS acid gas capture is expected for compliance. 58 , 59 The EPA addresses subcategorization issues elsewhere in the final rule record. **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 approxi mately $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 es timated 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 update d 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 anal ys is performed by commercial entities to contest EPA ’ s IPM results. The EPA contends these sources incorporate

57 “Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants ” by L ipinski, Leonard, Richardson; published by URS; April 5, 2011 58 Ib id. 59 NESCAUM report; “ Control Technologies to Reduce C onventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” p. 19, March 31, 2011529

inaccuracies within their models which dramatically influen ce 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 g ives the SCR cost estimates as an example, as they are below industry

estimates for installed costs and should be increased b y at least 20%. The commenter also states that it is unclear if the EPA is correctl y 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 SO 2 , 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**  **:** IP M calculates fabric filter AFUDC correctl y for a 2

- ye ar construction cycle; the typicall y anticipated cycle for a fabric filter. 60 The B2 calculation description (as illustrated on the spreadsheet view) is in error. The mathematical calculation actuall y performed is: B2 = 6% x (CECC+B1) {incorrectl y ty ped as: 6% x CECC + B1}. Both ACI and DSI estimated costs calculations include all equipment from unloading to injection. Due to surrogacy

co - benefit effects of controls, FGD controls capture HAP acid gasses more efficiently than SO 2 . 61 Depending upon a unit ’ s control configuration, equipment performance and fuel characteristics, ACI may be unnecessary
. 62 **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 th at 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 inc lude future regulatory

constraints within the model or risk understating the impact of the rule being proposed. **Response to Comment 52**  **:** Besides retrofit controls, pay roll, 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 full y 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 IP M 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 pro cess - engineering model and data sources used to characterize North American conventional, unconventional, and frontier
60 Sargent & Lundy, “ IPM Model

– Revisions to Cost and Performance for APC Technologies Particle Matter Control Cost Development Methodology FINAL, ” March 2011, Pro ject 12301

- 009, Perrin Quarles Associates, Inc 61 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants ” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011 62 NESCAUM report; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” March 31, 2011530

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 coal

fired retirements. IPM Natural Gas (NG) modeling is discussed in the preamble for the final rule
. **Comment 5 3**  : Several c ommenters (19 536, 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 b aghouses at fluidized bed boilers, and/or DSI with baghouses to achieve SO 2 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 require d level of SO 2 controls soon under other state or federal regulation to meet ambient air quality standards. The commenter goes on to list additional findings b y 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 f ederal 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. **1 0**  **. Difficulties with control technologies. Comment 5**  **4** : 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 by product material from a dry fabric filter. **Response to Comment 5 4**  **:** The EPA does not anticipate units with fabric filters necessaril y 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 th e other hand, activated lime reagent effectively removes acid gases and should not adversel y impact fly ash marketability . Mineral

- based Hg sorbents are effective and commerciall y available for overcoming concerns with activated carbon. 63 Additionally, see response to comment 4 (above). **Comment 5 5**  : 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 onl y 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 indus try ’ s coal

- fired capacity will
63 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 ” Sy mposium, August 30

– September 2, 2010, Baltimore, MD531

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. C ommenter 17868 believes the EPA ’ s estimates of the number of plants that will require additional controls, and thes e impacts will hit the upper and lower midwest, southeast, and southwest the hardest. **Response to Comment 5 5**  **:** 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 emi ssions 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 5 6**  : Commenter 18433 states th at 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 5 6**  **:** The EPA thanks the submitter for their input. The agency responded by creating a subcategory

for liquid oil

- fired, non

- continental units (not including 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 ty pically 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 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. **1 1**  **. Natural gas prices. Comment 5**  **7** : 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 anal ys es of control options using updated information. **Response to Co mment 5**  **7 :**  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. **Comment 5 8**  : 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 the532

environmental issues recently cre ated 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 deplo ym ent 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 CO 2 . **Response to Comment 5 8**  **:** The agency full y doc uments 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 u sed to capture pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key gas market parameters. **1 2**  **. Fuel switching. Comment 5**  **9** : 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 currentl y. **Response to Comment 5 9**  **:** The difficulties American territories experience is acknowledged. The agency created a subcategory

for oil

- fired, non

- continental units (excluding Alaska

- based units) realizing the unique situation and limitations these units face

– see final rule. The MAT S standard allow s the owner flexibility to select controls and fuels plus establishes alternatives for compliance. See the preamble for the final rule. **Comment 60**  : Commenter 19114 expresses concern with the IPM anal ys is suggesting that units will switch fu el 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 u sed b y 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 b y rail instead of truck or conveyor like lignite fuel generall y 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 , subcategories, and b eyond

- the

- f loor (BTF) issues are discussed elsewhere in the final rule record. The agency

believes that the fuel switching costs used in IPM are accurate , as explained at proposal
. That said, the final rule does not require fuel switching, instead we establish numeric emission standards and sources are required to comply in any manner they choose. The IP M modeling indicates that some sources may

choose to switch fuels as a valid comp liance option. If sources are unable or unwilling to employ fuel switching, they

can comply

through the installation of controls or other means available to533

reduce HAP emissions. We discuss fuel switching as a compliance option elsewhere in the final rule record. **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 bitumin ous coal. Both of these studies were short

term 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 s orbent injection. The commenter is not aware of other demonstrations of this approach that have been conducted b y independent, third parties. However, because of their citation in the technical supporting documents for the proposed MACT rule, we also discu ss 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 b y DOE under the Clean Co al Power Initiative. The primary objective of the project was to demonstrate the TOXECON configuration

- downstream of a hot

- side ESP in this case

- with ACIfor Hg control. A secondary goal was to determine the ability of powdered Trona injection to reduce SO 2 by 70% and also to realize some NO X 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 SO 2 , but that it also conv erted enough nitrogen oxide (NO) to nitrogen dioxide (NO 2 ) to produce a visible brown plume. Trona injection also reduced Hg capture b y AC I 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 th at 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 b y AC I. Tests b y 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 this one test campaign, Solvay Chemicals reported 50% HCl removal at a sodium bicarbonate injection rate sufficient to capture 10% of the SO 2 - i.e., a relatively low injection rate (Davidson, 2010). Since brown plumes have been observed at plants using sodium sorbents for SO 2 control, but not at plants using these sorbents for SO 3 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 impo rtant 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. Onl y 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.534

In1996
- 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 typicall y contained less than 1.0% sul fur 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 test s, 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 b y 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 typ ically become very

flat at high injection rates

- i.e., increase very

slowl y 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. **Respons e to Comment**  **61 :**  The EPA appreciates the commenter’s observations. See the preamble for the final rule for more discussion on DSItechnology
. **1 3**  **. 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 b y 2015, so cost will be associated with upgrading these scrubbers to achieve compliance. Also, the commenter points out that the scrubbers were onl y required to achieve 70% SO 2 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 earl y 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. **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. 64 Consequently , th e agency believes owners will operate emissions control equipment well beyond a 20

- ye ar period and shall attempt the more economically attractive option of upgrading equipment rather than replacement. Depending on scrubber age and current SO 2 removal rates , a wet scrubber can be upgraded for $5

- $100 per kW of unit size. 65 Furthermore, for acid gas removal compliance, an owner ’ s option includes augmenting existing controls b y installing DSI.

64 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/MJBAandAnal ys isGroupReliability ReportAugust2010.pdf 65 Assessment of Technology Options Avai lable to Achieve Reductions of Hazardous Air Pollutants ” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011535

**Comment 63**  **:** Commenter 18023 reports that many of their units have SC Rs 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 compl y 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 b illion 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 anal ys is 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 th e 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 6 4**  : 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 s ystem that mu st 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 6 4**  **:** Based on the concerns submitted, the EPA establishe d a “ limited

- use ” subcategory

for liquid oil

- fired EGUs. F or a detailed discussion, see the preamble to the final rule
. **Comment 6 5**  : 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
. **Response to Comment 6 5**  **:** Many factors influenc e retrofit cost besides locality ; 66 a neighboring facility does not necessarily

mean an “ identical ” facility . The present economic conditions differ drasticall y from the situation experienced in 2007

- 2008; retrofit controls cost models were determined durin g this time period and based on 2009 pricing. With excess resources currently available, the agency anticipates aggressive competition by suppliers to win project award subsequentl y resulting in price relaxation from pre - 2009 levels. **Comment 6 6**  : Commenter 17296 provides information regarding the use of calcium bromide as a cost

effective 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 contro lled 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 “ T echnologies 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 .)
66 Steam, 41 st Ed. 2005, Babcock & Wilcox Company53 6

**Response to Comment 6 6**  **:** 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 anal ys is 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 6 7**  : 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, SO 2 , NO X and PM emissions in 2010 by 90%, 94%, 91% and 87%, respectivel y, 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 6 7**  **:** The agency set emissions standards based on data collected (ICR) from existing EGUs 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 SO 2 mitigation ty picall y suffice for MATS acid gas capture while economical upgrades of existing controls or op timization may suffice for compliance. 67 **Comment 6 8**  : Commenter 17842 believes the implementation of a “total ” PM limit in the proposed rule contributes largel y to the rule ’ s estimated costs as utilities will need to replace existing PM controls with more co stly

fabric filters. **Response to Comment 6 8**  **:** 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 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 b y 10
- 20 percent. 68 As another option, an EGU may consider retaining the old ESP and install a supplemental smaller

- sized “polishing ” baghouse 69 to augment particulate collection. In short, the EPA does not foresee ESPs becoming obsolete with promulgation of MATS. **Comment 6 9**  **:** 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 o r cost - effectivel y justify the retrofits. The commenter expresses

67 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants ” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011 68 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants ” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011 69 NESCAUM report ; “ Control Technologies to Reduce Conventional and Hazardous Air Pollutants from Coal

- Fired Power plants ” p. 19, March 31, 2011537

concerns with the practical application of the proposed rule and the procedures used b y the EPA in the rulemaking process. **Response to comment 6 9**  **:** The EPA believes that the flexibility of th e 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 b ypassing 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. **Re sponse 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 bags 70 and/or pre

- coating the bags 71 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
.

70 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 ] 71 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

- Lo cks

and

- Barges
- Are
- an - Aging

- Workforce

- Too_36.html538

**6G -**  **Im pacts/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 month s 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 appro ximately

$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 generall y 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 s ys tem 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, especiall y 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 unlikel y 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 must run 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 oi l

- 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 ty p e 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 b y 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 st ack 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.539

**Response to Com ment 3:**  The EPA disagrees with the commenters ’ notion that PM is an appropriat e surrogate for HCl emissions. HCl testing frequency has been reduced to a quarterl y requirement and is required onl y if SO 2 controls and monitoring, or HCl monitoring (optional) are not emplo yed. 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 anal yz er span that provides accurate data. Coupled w ith the Part 75 requirements, the three linearity

gas concentrations are sufficient to determine that the anal yzer is linear. Commenter 18014 states that the system will need to be modified to include an additional regulator, the data acquisition and handl ing 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 SO 2 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 1 7718 requests guidance from the EPA on what should be included in a site

specific 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. **Re sponse 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 analy te to meet both the MDL of the anal ytical 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 anal ytical Method Detection Limit in ng

B = % (%) of the sample required per analy tical 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.540

**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 routinel y and will eliminate new coal

- fired units. However the commenter appreciates the EPA ’ s providing of the alternative of conducting fuel anal ys is 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 EP A ’ 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 s ys tems will need extensive u

pgrades as they

will require three more CEMS be installed to meet the proposed requirements. Also, full quality assurance measures have onl y 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 inexplicabl y 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 b y the proposed rule. In addition to the equipment

- related expenses, the commenter lists costs associated with modifying the data acquisition and reporting s ys tems 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 generall y 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 accordingl y. The EPA does not agree that existing mercury CEMS installations would need upgrades to compl y with this rule and the commenter provided no information demonstrating the case. **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 generall y scheduled onl y 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 s ys tem 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 b y onl y 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 b y the commenters and has altered the requirement for burner inspections to a schedule more likel y to coincide with planned major outage schedules. **Comment 8** : Commenter 17772 requests clarification on the proposed rule language that veri fies no requirement to retrofit boilers with viewing ports where none previousl y 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. The541

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 NO X l evels. **Response to Comment 8:** The EPA generall y 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 NO X emissions. The commenter recommends that oxygen monitors be calibrated annuall y 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 usuall y fi xed 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 NO X emissions to be dependent on oxyg en, 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 generall y 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 shortl y after the rule is finalized and again 3 year s 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 month s 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 I CR testing requirements were designed with the goal of collecting data representative of the cross section of units. The UPLcalculation performed on emissions test data takes variability into account in the effort to find542

levels where 99% of emissions test results will fall below the set limit. Performance testing conducted to assess control technology effec tiveness 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 quarterl y 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 woul d be shown b y 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 Comme nt 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). **Comme nt 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 costl y approach than stack testing. The commenter mentions that having the EPA revise the monthly and bimonthly testing requirement to quarterl y 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 exten sive 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 bimo nthly

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 generall y 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 th e 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.543

**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 anal ys is 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 anal ys es 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 anal ys is by the ICP instrument. Since this instrument analyzes all metals concurrently , there would be no or little reduction in the anal ys is cost for the impinger contents. In addition, for a few of the Method 29 tests conducted for the Phase III portion of the I CR, substantial percentages of the metals were in the impinger anal ysis. Eliminating the results of the impinge r 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 non

continental unit, they

contract with emissions testing firms located in th e 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 complianc e testing per megawatt of capacity to be significantl y higher than for continental EGUs with little environmental benefit associated with frequent emissions testing. **Response to Comment 15:** The EPA generall y agrees with the commenter and has modified the t esting 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 anal ysis of DSIsignificantl y underestimates the time needed for, as well as the cost of, compliance in many circumstances. First, DSIcould 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 DSIcould impact beneficial use of fl y 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 ye ar s and will spend more than the EPA estimates to achieve compliance. **Response to Comment 16:** The EPA also believes that DSIhas the potential to be a useful and cost

effective 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 lower

sulfur content coal (including, potentiall y, 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 p rimary 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 separatel y. However, the EPA did include an anal ys is evaluating the impact of increased disposal costs for ash residuals that contain sodium containing sorbents (such as Trona or sodium carbonate). The EPA’s544

anal ys is 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 DSIwaste 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 fac tored 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 qu estion (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 anal ys is 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 E GUs subject to the acid rain program choose to monitor stack moisture on a continuous basis.545

**6H -**  **Impacts/Costs: Projection of New Units Comments are addressed in Section 4 of this document.** 546

**6I -**  **Impacts/Costs: Economic Impacts/Employment Impacts Comme**  **nters** : 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, 1769 0, 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, 1 7811, 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, 18 498, 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, 1713 7, 17656, 17736, 17840, 17887, 17901, 17931, 18488, 18023, 19742 ) believe the proposed rule will weaken industry , cause job losses and hurt power consumers. C ommenter 16549 reports that the proposed rule will affect 1,350 coal

- and oil

- fired units at 525 p ower plants and that NERC reports that by 2018 nearl y 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 likel y to be up to 24% in s ome 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 be lieve coal

- fired plants in the southeast especiall y 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 earl y 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 generati on sector over the last 15 years. The agency ’ s anal ys es are credible and accurate to the extent possible. Limitations and caveats to these anal ys es 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 employ ment nationally

should be small on net, with about 46 ,000 job

- ye ars 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 peer

reviewed studies in the preparation of the emplo yment impact anal ys es. In addition, commenters are not comparing apples to apples. EIA has at no time provided an anal ys is 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 , l ike 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 impact547

jobs and electricity rates, leading to closed businesses. Commenter 17123 also calls for a practical, affordable, achievable energy solution. Commenter 17771 expresses concern specificall y 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 employ ment impacts on the power sector of up to 46 ,000 job

- ye ars of construction labor supported or created from new pollution control equipment installed, and a range of annual employ ment 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 anal ys is. 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 anal ys is 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 regulati on could result in double

- digit price increases for power. **Response to Comments 4 -**  **5:** The agency ’ s anal ysis in the RIA for the rule finds that retail electricity prices will increase b y 1.3 to 6.3 % in 2015. No region of the U.S. is expected to experience a double

digit increase in retail electricity prices in 2015 or in any

year later than that, according to the agency ’ s anal ys is. In addition, the agency finds that sectors experiencing these electricity price increases will not experience increases in pri ces 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** : Co mmenter 17842 questions the lack of consideration of the cumulative effects of interrelated rules, which may collectivel y lead to more retirements. The commenter states that local utilities have reported temporary job gains due to the replacement of retire d generation, but a net decrease in full

- time work. The commenter asks the EPA to reassess the costs and impacts of the proposed rule.548

Commenter 18424 states that the EPA ’ s conclusion that bituminous coal production will increase as a result of Utility

MAC T 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 b y utilities, the EPA projects approximately

10 GW of coal units wil l be retired because of Utility MACT. In contrast, the NERA anal ys is, 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. O ther 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 analy sis f or MATS. The agency did not prepare a cumulative impact anal ys is 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 anal ys is. A cumulative impact anal ys is lump s several regulations together and can potentially mask a high

- cost/low

- benefit regulation among other rules that may have large net benefits. By

analy zing each regulation separatel y, the EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this particular regulation. The EPA anal ysis also indicates that there will be relativel y modest amounts of retirements and installation of pollution controls will be a cost

- effective compliance measure. In addition, many co al 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 emplo ym ent anal ys is which shows some potential positive and ne gative employ ment changes from the rule, but overall expects the employment impact to be relativel y s mall 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 diff erences 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 anal ys es 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 f

amilies. **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, an d 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 this549

proposed rule. The anal yses 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 employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy . This is also co nsistent 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 anal ys is of employment impacts finds a short

- term impact of 46 ,000 job

ye ars su pported 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 employ ment beyond the regulated sector. We do not provide an estimate of a change in GDP. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ

ment impact to be relativel y s mall in comparison to the affected sector and the overall economy. This is also co nsistent with the economic literature. **Comment 1 1**  : 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 1 1**  **:** 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 greatl y impacting electricity prices. **Comment 1 2**  : Comm enter 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 co st to the utility caused b y 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 EP A ’ s responsibility to factor rate increases into the adoption of the proposed rule. **Response to Comment 1 2**  **:** The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions and other regulatory authoritie s 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).550

**Comment 1 3**  : 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 1 3**  **:** 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 1**  **4** : Commenter 17868 refers to the American Coalition for Clean Coal Electricity (www.cleancoalusa.org) projecting net nationwide employ ment losses totaling 1.44 million job years by 2020 as a result of the propos ed rule. **Response to Comment 1 4**  **:** The estimate of employ ment losses supplied by

the commenter reflects a cumulative estimate of employ ment losses over the time period of 2012 to 2020 related to implementation of both the CSAPR and the MATS proposal, and ha s many weaknesses. Thus, this estimate is not for the proposed rule alone, and is not a transparent anal ys is 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 ty pe of employ

ment impacts are assessed (construction, operation, etc.). The Agency ’ s estimates both short

- term and long

- term employ ment impacts specific to this rule, which can be found in the RIA for the rule. The updated emplo ym ent analysis for th e final rule shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. This is also consistent with the economic literature. **Comment 1 5**  **:** Commenter 19042 presents the results of an anal ys is 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 an d costs absorbed by federal agencies for boiler modifications. The anal ysis 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 1 5**  **:** The agency has considered this data as part of its UMRA analysis for the final rule. **Comment 1 6**  : Commenter 18023 estimates that capital spending and fuel switching required for compliance with the proposed rule could increase electricity prices b y 10 to 2 0% 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 comparabl y 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.551

**Response to Comment 1 6**  **:** The agency ’ s anal ys is 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 short

term increase of 46 ,000 job

- ye ars 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 anal ys is, 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 greatl y impacting electricity prices. In addition, the EPA has conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the emplo ym ent impact to be relatively small in comparison to the affected sector and the overall economy . This is also consistent with the economic literature. **Comment 1 7**  : Commenter 17761 expresses concern about the potential impacts on e lectricity 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.nar

uc.org/Resolutions/Resolution%20on%20the%20Role%20of%20State%20Regulatory%2 0Policies%20in%20Development%20of%20Fed%20Enviro%20Regs.pdf .) **Comment 1 8**  : 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 1 9**  **:** 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 1**  **7 -**  **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 regulatio ns 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 greatl y 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 millio n 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 federal552

impacts presented b y 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 2**  **1** : Multiple commenters (12050, 17844, 17854, 17875, 17880, 18025, 18421) support the EPA ’ s impact anal ys is and dispute claims by other commenters that the projected rule will harm economic growth. Several c ommenters (12050, 17875, 18421) mention testimonials by power company CEO s stating that the proposed rule will not affect the economic health of the industry and a survey showing nearl y 60% of the coal

- fired units already compl y with the EPA ’ s proposed Hg standard, as well as several other meaningful quotes from utility executives. C ommenters also point out that 17 states already require plants to address Hg pollution, with some imposing more stringent emission limits than the EPA proposes. C ommenters 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 nearl y 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 m aintenance jobs will result. **Response to Comment 2**  **1:** The agency thanks the commenters for their comments. The agency ’ s estimates of employ

ment impacts, which are found in the RIA for the rule, are smaller than the commenters ’ though we use a different meth odology that focuses on impacts to the electric power sector. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ

ment changes from the rule, but overall expects the employ ment impact to be relativel y 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. C ommenters believe the EPA has underestimated the impact. C ommenter 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 elderl y, minorities, and low income populations, resulting in: 1. Average electricity

rate increase of nearl y 25% 2. Gross State Product loss of nearl y $18 billion (nearly 2.5%) 3. Annual job losses of 157,000 4. Unemploy

ment rate of nearl y 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 e quipment, 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 accuratel y 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 agency553

also estimates employ

m ent impacts of an increase nationally of 46 ,000 job

- ye ars 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 employ ment estimates specific to individual states due to a lack of specific information to provide credible estimates. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 2 3**  **:** Commenter 19580 believes that if the EPA finalizes this rule it is only a matter of time before our strong manufacturing base moves overs eas, 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 2 3**  **:** The EPA has design ed 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 comp liance 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 anal ys is 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 greatl y 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 2 4**  **:** Several commenters ( 19536, 19537, 19538) state that the EPA is obligated to impose lower HCl emission limits because th e 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 anal ys is likel y underestimates true benefits of a 0.0001 lb/MMBtu HCl limit. Also, comment ers point out that the EPA anal ys is does not take into account the SO 2 controls required to meet other rules, so the costs are likel y to be overstated. **Response to Comment 2 4**  **:** The agency has quantified the reductions in HF emissions as part of its anal ys is 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. Finall y, the agency has included SO 2 controls in existence or planned that it is aware of for sources to be subject to this rule in the baseline for the anal ys is presented in the RIA. **Comment 2 5**  : Commenter 17648 believes the proposed rule will promote long

- term economic health by encouragin g investment in modern, efficient EGUs . The commenter cites upgrades to existing nuclear plants to improve zero

-pollution nuclear generation by several gi gawatts , 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 2 5**  **:** We thank the commenter for their comments and the data they have provided. The agency ’ s employ ment impact anal ysis does not include estimation of impacts using this BL S data, but we think our anal ys is of employ ment 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 likel y outcome of this rule. The agency does believe that retail554

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 2 6**  : 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 wil l 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, nati onwide, 85% of monitored counties will become non

- attainment for ozone and the cost for coming into attainment will be $20

- $90 billion annually

. **Comment 2 7**  **:** Comment 18488 cites the IC F 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 2 6**  **- 2**  **7 :**  The EPA has designed a rule that is intended to offer flexibil ity, 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 greatl y impacting electricity prices. In addition, the EPA has anal yz ed 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 2 8**  : Commenter 18023 states that the estimated costs do no t include billions of lost economic productivity

that may be incurred due to load shedding to manage the bulk power s ys tem. **Response to Comment 2 8**  **:** The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring pu blic 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 h as an excellent track record of installing pollution controls without greatl y impacting electricity prices. In addition, the EPA has anal yz ed 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 2 9**  : 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.555

**Response to Comment 2 9**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is 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 anal yz ed 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. C ommenter 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. **Respons e 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 anal yz ed 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 deman d. 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 earl y 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 anal ys is 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 full y reflects. In addition, the EPA has anal yz ed resource adequacy

issues and finds that there is ample existing spare capacity to s erve 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 util ities some additional time to comply , if conditions warrant (see preamble). **Comment 3**  **2** : 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

w ith 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 economicall y healthy power plants. ” The commenter reports that the study also notes that the prov en technologies for controlling Hg and other air toxics are commercially556

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
- ye ar old units that are already “ economically chall enged ̈ and nearing the end of their design life expectancies. (Ensuring a Clean, Modern Electric Generating Fleet while Maintaining Electric S ys tem Reliability , M.J . Bradley & Associates LLC and Anal ys is Group. August 2010. http://www.mjbradley.com/documents/MJBAandAnaly sisGroupReliabilityReportAugust2010.pdf ) **Response to Comment 3**  **2:** The EPA agrees with the commenter. The EPA has conducted detailed updated economic anal ys is of the rule, and believes that the impacts to be reasonable given the large benefits. **Comment 3 3**  : Commenter 17761 states that the impact anal ys is 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 3 3**  **:** The EPA has conducted as detailed and comprehensive an updated economic analysis of the rule as reasonabl y possible to reflect the true costs and benefits, and commenter does not substantiate the claims made. **Comment 3 4**  **:** Multiple commenters (16549, 17114, 17639, 17698, 17782, 18033) ask that the EPA delay indefinitel y 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 3 4**  **:** The EPA does not have the flexibility to delay th e rule, which is governed by a consent decree and the requirements of the CAA. However, it has conducted detailed economic impacts anal ys is on the regulated sector, and finds the impact of the rule on the regulated sector is small compared to the overall b enefits, 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y 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

- ye ar period for sources to co me 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. **Comment 3 5**  : Several commenters (17811, 18436, 18478) offer support for the EPA ’ s proposed rule, stating that many power plants currentl y 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, effectivel y providing for equivalent, less costly technology

in achieving the proposed emission standards. C ommenters 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 roughl y $5 billion in economic investments were lost in the Birmingham metro area due to non

- attainment air quality status. **Response to Comment 3 5**  **:** 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 being achieved b y a number of s ources using certain technologies. The agency will be flexible in allowing sources to comply with this rule consistent with the requirements of the CAA.557

**Comment 3 6**  : Commenter 17877 believes that finalization of the proposed rule will result in increased co sts that non

-profit cooperatives will need to pass on to consumers, which will negativel y impact economic development and jobs. **Response to Comment 3 6**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail ele ctricity prices. The anal ys is includes the specific operating parameters and variability

of other technologies, 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 anal yz ed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry

has also shown th at it can build new capacity quickl y 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 3 7**  **:** 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 in stallations were successfull y coordinated with unit outages and position the facilities to comply with the proposed rule in advance of the deadlines. **Response to Comment 3 7**  **:** The EPA believes that coal units that have already installed pollution controls wi ll be well situated to comply with this rule by

taking relativel y modest steps to ensure compliance. The EPA also believes that the pollution control installations can be managed b y industry. Industry has shown that it can install large amounts of pollutio n controls and often finds more cost

effective compliance options than the EPA can anticipate. **Comment 3 8**  : 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 intend ed 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 3 8**  **:** 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 less than 2% of all coal

- fired generating capacity may be uneconomic to maintain and removed form operation b y 2015 in response to the rule, and this result is the product of business decisions rather than a specific requirement of the rule. This anal ys is has been updated for the final rule. **Comment 3 9**  **:** 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 shows558

the reverse to be true. The co mmenter 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 b enefit in present value over the period were $22 trillion and the benefits outweighed the costs by 40 to 1. **Response to Comment 3 9**  **:** The EPA generall y 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 initiall y projected. The EPA has conducted detailed economic impacts analy sis 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 greatl y 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 anal ys is 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y 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

- ye ar 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
. **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. C ommenter 18023 notes that less affordable electricity prices would have other indirect consequences, such as the loss of energy

intensive manufacturing operations, the loss of U.S . manufacturing jobs, a decline in tax revenues, and risk to nati onal security if military bases and key manufacturing and production operations do not have a steady and reliable supply

of electricity . C ommenter 17765 states that utilities are already requesting residential rate increases of up to 19% (see http:/ /www.c ourier

- 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 +559

MACT , ” NERA Economic Consulting, Draft May 2011). Similarly , commenter 17904 cites research conducted b y Bernstein that predicts costs in both the PJM and MI SO RTOs are expected to go up significantl y and remain volatile. Commenter 18484 believes the proposed rule wil l cause irreparable harm to the economy and national security due to energy cost increases negativel y affecting the ability to compete in the global market and increasing unemplo ym ent. 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 ye ars 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 imp acts 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 implem ent 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 w ithdraw 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 anal ys is includes the specific operating parameters and variability

of other technologies, 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 anal yz ed 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 quickl y 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 4**  **3:** 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 4**  **3:** As discussed elsewhere in this document, the EPA has conducted detailed impact anal ys is of the rule, which does not show significant impacts to the economy , and the costs of the rule are greatly

outweighed by

the benefits. **Comment 4 4**  **:** Commenter 18907 foresees negative effects for smaller businesses, including retail gasoline outlets.560

**Response to Comment 4 4**  **:** The EPA does not anticipate a notable impact on retail gasoline outlets as a result of this rule , and its detailed economic anal ys es, discussed elsewhere in this document, show the impacts to businesses and consumers to be relatively small
. **2. State/regional impacts, low income.**  **Comment 4 5**  **:** 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 comm enter 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 s ees 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 currentl y uses to generate electricity. **Response to Comment 4 5**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is includes the specific operating parameters and variability

of other technologies, and is unlikely to lead to extensive substitution away from coal

fired g eneration. 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 anal yz ed resource adequacy issues and finds that there is amp le existing spare capacity to serve load, and industry

has also shown that it can build new capacity quickl y in response to demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. Public utility commissions and oth er 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 4 6**  : 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 4 6**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is includes the specifi c operating parameters and variability

of other technologies, 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 anal yz ed 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 quickl y 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).561

**Comment 4 7**  **:** 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 4**  **7 :**  The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is includes the specific operating parameters and variability

of other technologies, 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 anal yz ed resourc e 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 quickl y 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 re sponse measures. In addition, there are certain provisions for granting utilities some additional time to comply , if conditions warrant (see preamble). **Comment 4 8**  **:** 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 4 8**  **:** The agency has estimated that less than 2% of all coal

- fired generating capacity may be uneconomic to maintain and removed form operation by 2015 in response to the rule, and this result is the product of business decisions rather than a specific requirement of the rule. The EPA has conducted detailed impact anal ys is of the rule, which shows reasonable impacts to retail electricity prices. The EPA will work wi th 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 4 9**  **:** Commenter 19214 believes the EPA should expand the quantity and quality of their review so that accurate, realistic and broadl y- accepted expectations of the cost, development timeline and performance of emission control systems can be considered in the final rule. **Response to Comment 4 9**  **:** The EPA has revised the detailed impact analysis of the proposed rule for the final rule in a number of way s , and believes that the anal ys is 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 anal yz ed resource adequacy issues and finds that there is ample existing spare capacity to serv e 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 ext ensive 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 utiliti es some additional time to comply, if conditions warrant (see preamble). **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 que stions the EPA ’ s estimates as a result and calls into question the EPA ’ s estimates of the following:562

1. Impact of Rule on the National Economy 2. In crease in Electric Rates ( commenter expects costs to increase b y s everal percentage points) 3. Financing costs for emission retrofits 4. Loss of external revenue streams from sale of CCR 5. In creased costs for disposal of CCR 6. Loss of revenue from increased parasitic load at power plants 7. Decrease in Disposable Income 8. In crease in Cost of Operation for Small Political Subdivision s The commenter requests that EPA conduct a more robust study of the economic impact of this rule. **Response to Comment 50**  **:** The EPA has anal yz ed many of these impacts, which can be found in the RIA of the rule. The EPA has not anal yz ed 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 anal ys is for the proposed rule shows some increase in short

- term ( i.e., by 2015) employ

ment associated with the installation and operation of pollution control equipment. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule in the long

- term, but overall expects the employ

ment 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 18 424 and 18425 believe the EPA has underestimated the impact of the proposed rule on EGUs burning bituminous coal and will severel y impact the Indiana coal industry and Indiana jobs in general. The first commenter explains that Indiana produces bituminous c oal 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 IC C study showing Indiana job losses at more than 12,000 due to the l oss of coal production. The commenter also notes that the cost of compliance will increase electricity costs and erode the competitive advantage enjo yed b y Indiana in manufacturing, leading to a total loss of 50,000 jobs in the state. **Response to Comment 5**  **2 :**  The EPA ’s anal ys is 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 anal yz ed 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 conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy . This is also consistent wi th the economic literature.563

**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 co ordinate requirements for the control of multiple pollutants and thus is being responsive to the goal of multi

pollutant control strategies. **Comment 5 4**  **:** Commenter 19041 expresses concern that the proposed rule will have effects on the ability of their coop erative 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 5 4**  **:** Utilities that have already installed pollution controls are likel y to be well positioned to comply

with this rule with modest modifications. **Comment 5 5**  **:** 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 negativel y impact businesses. Commenter 19653 especiall y 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 coul d delay progress on new construction and remodeling. **Response to Comment 5 5**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is includes the specific operating parameters an d 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 anal yz ed 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 sin c e electricity prices are projected to increase only modestly
. **Comment 5 6**  **:** 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 5 6**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to ret ail electricity prices. The anal ys is 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. Thus reliability issues are not expecte d 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 adequacy564

issues and finds that th ere 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 5 7**  **:** 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 5 7**  **:** The EPA has conducted detailed impact analysis of th e rule, which shows reasonable impacts to retail electricity prices. The anal ys is 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 ty picall y the oldest and least efficient units in the coal fleet. **Comment 5 8**  **:** Commenter 18933 states that textile production in North and South Carolina and Georgia will suffer f

rom an estimated increase of 11.5%. This expense is likely to make the industry

less competitive with foreign businesses. **Response to Comment 5 8**  **:** 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 anal ys is indicates that coal

- fired generation will maintain its large share of generation. In addition, indu stry 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 anal ys is 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 larg e amounts of pollution controls and often finds more cost

- effective compliance options than the EPA can anticipate. **Comment 5 9**  : 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 strongl y impact the s ys tem 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 co nducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is includes the specific operating parameters and variability

of other technologies and coal types, and is unlikely to lead to extensive su bstitution away from coal

- fired generation. In addition, separate standards are being finalized for non - continental oil

- fired EGUs (see preamble). **Comment 6 0**  : 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 negativel y impact residential565

customers and energy

- intensive business and the jobs they create. The commenter points out that environmental regulations in Europe have sent manufacturing businesses elsewhere. C ommenters 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. C ommenters 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 anal ys es are flawed and asks that they be revised to consider the full impact of all the new and proposed rules. **Response to Comment 6 0**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is 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 anal yz ed 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 c onditions 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 largel y driven b y 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 :**  Co mmenter 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 additional energy

efficie ncy

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.566

**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. C ommenters point out that the southeast is particularl y 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. C ommenters 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 18 021 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. **R esponse 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 roughl y 3.1 % in 2015 nationwide, based on the agency ’ s an al ys is contained in the RIA for the rule. This increase, while not trivial, is not expected to yield significant impacts to manufacturers. The EPA ’ s anal ys is indicates that coal

- fired generation will maintain its large share of generation. In addition, ind ustry 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 6 4**  : Commenters 17712 and 17743 explain that cooperative EGUs will generall y 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 timel y manner. **Response to Comment 6 4**  **:** 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 anal ys is also indicate s that there will be relativel y 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 6 5**  : Commenter 17718 considers the proposed rule to be hardest on states which rel y 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. **Respons e to Comment 6**  **5 :**  The EPA ’ s anal ys is 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 6 6**  **:** Commenter 17055 mentions that their initial assessment did not consider impacts the RI CE 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 s ys tem 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.567

**Response to Comment 6 6**  **:** The agency is currently

reconsidering the Compression Ignition and Spark Ignition RI CE NESHAP. The outcome of this reconsideration may affect the congestion and other issues the commenter points out. **Comment 6 7**  **:** 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 adequatel y reduce the burden to such organizations and their financial well

being 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 6 7**  **:** The EPA will work with relevant authorities to ensure a smooth transition with this rule. Inaddition, there are certain provisions for granting utilities some additional time to comply , if conditions warrant (see preamble). The EPA anal ys is also indicates that there will be relativel y 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 6 8**  : Commenter 17745 expre sses 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 6 8**  **:** 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 autho rities 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 , th ose 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 PM 2.5 emissions a s shown in Appendix C of the RIA. In addition, the EPA has conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 6 9**  **:** Multiple commenters (16705, 17400, 17697, 17868, 18038, 18433) consider the EPA ’ s RIA to be flawed in suggesting that onl y 97 municipal utilities will face a compliance cost of $666.30 million annually . C ommenter 16705 states that these costs underestimate the impact on states such as Indiana, Ohio, Wisconsin, Michigan, Minnesota, Kentucky, Georgia, Alabama and Texas. C ommenter 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. C ommenter 17697 explains that the cost anal ys is does not include the cost of purchasing power during scheduled outages for retrofit, the costs of 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.568

**Response t o Comment 6**  **9 :**  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 anal ys is. 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 tim e to comply, if conditions warrant (see preamble). There are also separate standards for non - continental liquid oil

- fired EGUs . The EPA is addressing coal combustion residuals in a separate rulemaking. **Comment 70**  : Several commenters (17689, 17697, 17710, 1 8433) 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 unemploy ment and cause economic hardship for the already disproportionately high percentage of the island ’ s population currently unemployed or underemplo yed. **Response to Comment 70**  **:** The EPA is required to regulate acid gas HAP such as hydrochloric and hydrofluoric acids under this rule, a s explained elsewhere in the final rule record . 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 oil

- fired EGUs that should address some of commenters ’ concerns. **Comment 7 1**  : 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 7 1**  **:** The agency ’ s anal ys is 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 ret ail 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 s ys tem 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 sy stem reliability and costs, such as the increased impacts on regions relying heavil y 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 TSD to document this study , and this document is the docket for this rulem aking. The agency has considered impacts on a regional basis as part of its overall anal ys es done using the IPM; these results are documented in the RIA for the rule and in several TSDs.569

**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 st ates 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 less than 2% of all coal

- fired generating capacity may be uneconomic to maintain and removed form operation b y 2015 in response to the rule, and this result is the product of business deci sions rather than a specific requirement of the rule. In addition, the EPA has anal yz ed 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 resp onse 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 7 4**  **:** 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 elderl y, poor and those who have lost jobs at a time when the Low In come Home Energy

Assistance Program has been decreased significantly
. **Response to Comment 7 4**  **:** The rule does not dictate any particular technology

and the EPA h as 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 anal ys is indicates th at 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 anal yz ed 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 quickl y in response to demand and also manage the installation of pollution controls. The EPA will work with re levant 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 7 5**  : 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 significantl y affected b y the rule, including increased unemploy ment. **Response to Comment 7 5**  **:** The agency ’ s anal ys is 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 region s 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 slightl y on average b y 2015. Thus, there may be some negative impacts from this rule in these regions, but these570

same regions will also experience some of the benefits, such as reduced premature mortality from less exposure to PM 2.5 emissions as shown in Appendix C of the RIA. In addition, the EPA has conducted an updated emplo ym ent analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the empl oy ment impact to be relativel y s mall in comparison to the affected sector and the overall economy. **Comment 7 6**  : Commenters 17901 and 18023 state that communities near existing coal

- fired generation units will be especially

hard

- hit if the plants are permanentl y retired. The communities will suffer from job loss and diminished tax revenue. **Response to Comment 7 6**  **:** 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 earl y 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 greatl y 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 employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment 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 compl y, those same regions will also benefit from the emission reductions such as through reduced premature mortality from less exposure to PM 2.5 emissions as shown in Appendix C of the RIA. **Comment 7 7**  : Several c ommenters (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 comment ers ask that the rule be reevaluated to be more realistic and cost

- effective. **Response to Comment 7 7**  **:** 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 7 8**  **:** 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 anal ys is 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 commi ssions 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).571

**Comment 7 9**  : Commenter 17648 offers projections showing that 2015 electricity prices in most areas will be the same or lower than they w ere 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 ye ars. 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 anal ys is are set forth in Figure 1 (See 17648
- A2_Figure 1_ComEd and PECO Generation Rates.docx)
. **Response to Comment 7 9**  **:** The Commenter’s statements are not inconsistent with the results of EPA ’s anal ys is , 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 advanc ed facilities take precedence over less efficient plants because Sy napse 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 mar ket 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 b y 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 wil l 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 consumer s, 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 utiliti es 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 result of substituting higher

- cost forms of electricity for coal. Commenter 18033 states that coal

- derived energy will rapidl y become more expensive, especially in the “ rust belt” and southeast region, as can be seen b y 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,572

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 anal ysis 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 anal yz ed 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 quickl y 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. T he price increases in electricity and natural gas should be considered in light of the substantial benefits offered b y this rule. In addition, history has shown that the impact of EPA regulations is much lower than anticipated, and predictions of severe ec onomic impact have been often repeated, but not realized. **Comment 8 2**  : C ommenters 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 Commen t 8**  **2 :**  The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ys is 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 employ ment analysis which shows some potential positive and negative employ ment changes from the rul e, but overall expects the emplo ym ent 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 severel y impact the economy of the coal

-producing states and utilities that provide almost 50% of their electricity from coal. C ommenters 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 anal ys is indicates that coal will remain the largest source of electricity . Industry has shown that it can install large amounts of polluti on controls and often finds more cost

- effective compliance options than the EPA can anticipate. In addition, the EPA has conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy
. **Comment 8 4**  : Commenter 17627 considers the EPA ’ s RIA document to be lacking in local economic impacts associated with reduced operations or p lant closures. **Response to Comment 8 4**  **:** 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 for the final rule, which has detail for the 32 power regions across the country . In addition, the EPA has conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy
.573

**Comment 8 5**  : 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 capac ity , market structures, approaches to energy efficiency , transmission options, electricity demand projections and consumer concerns. **Response to Comment 8 5**  **:** The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retai l electricity prices. The anal ys is 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 th ose impacts in the RIA. **Comment 8 6**  : Commenter 18030 quotes the NERA study could cost Michigan 40,000 jobs and increase electricity prices b y 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 8 6**  **:** 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

ha s 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 e conomic 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 greatl y 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 j obs, 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 8 7**  : 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 pay ments 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 re tain 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 basi s. 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 1854 0 explains that it receives its entire water supply through the CAP s ys tem 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 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 care full y consider the possible effects of its proposed rulemaking on the continuing viability of the CAP sy stem and requests that the EPA consult with it and574

other tribes that may

be affected by

the proposed rule, pursuant to the Agency ’ s May 2011 Consultatio n Policies. **Comment 8 8**  : Commenters 17732 and 18017 report that the power plant associated with the Navajo Nation (FCPP ) employs nearl y 600 people, most of them Navajo Nation members. The commenter goes on to explain that the Navajo Mine provided $69 millio n 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 8 9**  : 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 b y 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 los ses so extreme they would impugn the solvency of the Navajo Nation government. The commenter states that the EPA failed to anal yz e the impacts to the Navajo Nation as part of the impact anal ys is. The commenter points out that unemploy ment 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 b y 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 anal yzed by the EPA. **Comment 90**  **:** Commenter 19214 requests that the Table 8.8 showing that NGS will be likely to shut down by 201 5 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 8 7**  **- 90**  **:** The EPA mode ling 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 re flect actual compliance decisions, since those will be made individually b y 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 s mooth 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. **Comment 91**  **:** Commenters 1 7807 and 17901 expresses concern about economic impacts to residential and commercial customers, particularl y minorities, the elderl y 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.575

**Comment 92**  : Commenter 17813 questions the results of the IPM model becau se 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 projection s are intended to be a reflection of possible compliance using specific tools, assumptions, and methodologies that the a gency believes to reflect the best and most current information related to the power sector. It is not intended to reflect actual compli ance or retirement decisions, since those will be made individually b y the affected industry based on what makes most sense using existing technologies or other, more cost

- effective strategies. **Comment 9 3**  : 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 emplo ye e 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 9 3**  **:** The EPA has conducted detailed impact analysis of the rule, which pro vides 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 significantl y since sources are anticipated to install pollution controls. In addition, the EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy **Comment 9 4**  **:** 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 northwe st while the midwest and other regions will face large cost increases. **Response to Comment 9 4**  **:** 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 significantl y since sources are anticipated to in stall pollution controls. In addition, the EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 9 5**  **:** 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 state s that the importance of the coal industry to Virginia makes that state especiall y painful. **Response to Comment 9 5**  **:** The EPA has conducted detailed impact analysis of the rule, which provides a rich characterization of regional issues, and reflects the diff erences 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 significantl y since sources are anticipated to install pollution controls. In addition, the EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the576

rule, but overall expects the employ ment impact to be relativel y s mall in comparison to the affected sector and the overall economy
. **Comment 9 6**  **:** Commenter 18477 believes that non

- continental oil

- fired EGUs should have a separate regulatory

impact anal ys is. 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 economi c 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 addresse d 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 oil

fired units as part of the final rulemaking, the EPA should address non

- continental liquid oil

- fired units separately in that anal ys is. **Response to Comment 9 6**  **:** The final rule contains provisions that are specific to non

- continental liquid oil

- fired EGUs. See preamble for further discussion of the treatment of these sources. **3. Retiring coal -**  **fired EGUs, shutdowns. Comment 9**  **7 :**  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 coal

fired E GUs 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 anal ys es of the proposed rule to be incomplete and misleading and the proposed rule structured to avoid unnecessarily

eliminating jobs. **Response to Comment 9 7**  **:** The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity). In addition, the EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **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 c ommenters (17623, 1786 8, 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 earl y closure of many facilities as a result of the proposed rule and reports that these EGUs play a central ro le in a region ’ s economy since they are a source of jobs and577

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 onl y 3% of all coal

- fired cap acity by the ye ar 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 anal ys is given the compliance framework and timeline of the proposed rule. **Response to Comment 9 8**  **:** The agency prepared a resource adequacy analysis for the propo sed rule and has revised that anal ys is 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 anal ys is 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 anal ys is would be as accurate and transparent as anal ys es for each of these individual rules. The EP A has outlined the various flexibilities associated with the rule, and the approaches to reliability issues in the preamble. **Comment 9 9**  **:** 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 T oxics Rule and other EPA electric power industry regulations, some power plants were already economicall y 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 face s 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 fleet is equipped with scrubbers and the number will increase to nearl y 2/3 by 2015. (Footnotes in comment provide references to the studies and further quotes.) **Response to Comment 9 9**  **:** 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 adversel y affect the cost

effective 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 ’ s578

“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 po wer plants have announced earl y 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 earl y 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 c ommenters (17682, 178 13, 17904, 17930) mention the proposed rule ’ s impact on mining. C ommenter 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. Co mmenters 17904 and 17930 see mining impacts being disproportionall y large for lignite mines, which are dependent on their co

- located lignite

- fired power plants. C ommenters 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 10**  **1 :**  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 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 anal ys is indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity). In addition, the EPA has conducted an updated employ ment analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 102**  : C ommenter 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 EPA579

must recognize that by

changing market dy

namics 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 Am erican 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 unprod uctive 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 b y 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 b y all the electricity generated b y nuc lear, 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 M odel (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 in cluded these compliance costs is not yet available, PJM ’ s graphical representation shows that of the roughl y 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 pric e. (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 in clude 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 currentl y there are 307,006,550 people in the U.S. and approximately 51 million of them live in the PJM Market. This mean s 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 reflecti on of retail price impacts, which will be dampened since the cost of generation is just one of several components of retail prices. The auction also resulted in significant new capacity and additional demand

- side resources, which show that there are multip le 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 anal ys is presented, the incremental effect of the rule alone and is lumping in other important industry trends and dy

namics that will impact future prices. The EPA has updated its anal ys is of price impacts of MATS, which are presented in the RIA on a regional and nationwide basis.580

**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), I CF 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 anal ys is 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 Indep endent 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 on e, electric rates are going to go up. Number two, whether or not construction jobs in the green industry are created, Ithink there ’ s [sic] virtually no manufacturing jobs that are likel y 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 ( less th an 2% of all coal

- fired capacity) 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 anal yses also conflate other issues, like natural gas prices and low electricity demand, and do not isolate the effect of this rule separatel y. 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 emissio ns. 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 significantl y since sources are anticipated to install pollution controls. The EPA wil l 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 consumer s, 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 emplo yment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. **Comment 10 4**  : Commenter 16469 states that the coal units more likely to retire due to the proposed rule are over 40 ye ars ol d, under 400 MW and are cycling or “ load

- following ” units for which the costs 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 gen eration for these units. **Response to Comment 10 4**  **:** The EPA agrees with the commenter. **Comment 10 5**  **:** Commenter 17881 explains the process b y 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 ye ar 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.581

**Response to Comment 10 5**  **:** 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 anal yz ed 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 quickl y 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 10 6**  : 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 10 6**  **:** 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. **Comme nt 10**  **7** : Commenter 17403 believes the EPA has not adequately assessed the costs associated with the retirement of smaller units, just as job losses and emplo ym ent shifts as workers are retrained and re

- employed elsewhere. **Response to Comment 107 :**  The EPA ha s conducted an updated employment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. **Com ment 10**  **8** : 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 10 8**  **:** The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capac ity) 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 fin d least economicall y viable to control. Inaddition, the EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ

ment impact to be relativel y s mall in comparison to the affected sector and the overall economy. **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 expecte d compliance. **Response to Comment 10 9**  **:** 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 successf

ul track record of responding to air reduction programs through innovation, often a cost much less than what the EPA originall y anticipated.582

**Comment 1 1**  **0:** 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 s ys tem reliability and allow the maximum compliance flexibility for electric utilities provided for under the Clean Air Act. **Response to Comment 1 1**  **0:** 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 resource adequacy analysis for the proposed rule and has revised that analy sis 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 1 11**  **:** 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 1 11**  **:** The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity) and coal

- fired generation will not change significantl y. 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 emplo ym ent analysis which shows some potential positive and negative employ ment changes from the rule , but overall expects the employ ment impact to be relativel y s mall 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 pre amble). **Comment 1 12**  **:** 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% SO 2 removal efficiency. If s ources cannot comply with the proposed limits using bituminous coals, they will not use those fuels or they will retire the units. **Response to Comment 1 12**  **: :**  The EPA disagrees with the comment. Since scrubbers effectivel y capture acid gas HAP more efficiently than SO 2 , units equipped with this control device operating at 95% SO 2 removal efficiency are expected to suffice. 72 For those scrubbers operating below 95% SO 2 capture, controls upgrades are available to improve performance. 73 Potential impacts to coal supply are di scussed in the preamble for the final rule and in the RIA. **Comment 1 13**  **:** Commenter 17852 asserts that the proposed rule can and should promote the orderl y retirement of old, high

- emitting power plants. It is widely re cognized 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 coal

fired g eneration have been recentl y announced for retirement. However, current regulatory provisions do not always sufficientl y promote utility planning for these retirements, causing some in the utility sector

72 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants ” by Lipinski, Leonard, Richardson; publish ed by URS; April 5, 2011 73 Ib id.583

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/I SOs only require 90

- day

notifications for retirements, construction sch edules 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 earl y planning, the EPA said that it “ encourages state environmental regulators to consider the extent to which a utility engages in earl y planning when making a decision regarding granting a 4th ye ar 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 1**  **13 :**  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 e arl y 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 1**  **14 :**  Several commenters (17004, 17022, 17026, 17028) consider the purc hase 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 needlessl y 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 1 14**  **:** 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 , and EPA is also making revision s to the current NSPS. Implementation deadlines in the final rule are in response to the underl ying requirements of the CAA, and any flexibility that the agency

can offer must be consistent with the CAA. **Comment 1**  **15** : 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. **Response to Comment 1 15**  **:** The agency ’ s anal ysis 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 11 6**  : Several c ommenter s (17707, 17824, 18419) state that Alabama uses coal to supply nearl y 60% of electricity needs and emplo ys 1500 workers to run the coal

- fired power plants. C ommenters 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

- fired584

units and succeeded in dropping NO X and SO 2 emissions by 65% since 1996. C ommenters consider the proposed rule to be unreasonable and unfounded, with the cost vastly outweighing the benefits. **Response to Commen t 11**  **6 :**  The agency ’ s anal ysis shows that the national average retail electricity price is projected to increase b y 3.1 % in 2015. The EPA has attempted to provide the greatest degree of flexibility permitted by

law. The EPA anal ys is indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity) and coal

- fired generation will not change significantl y. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existen ce that will help serve load. In addition, the EPA has conducted an updated emplo ym ent analysis which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y s mall in compariso n 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 11 7**  : Commenter 17648 observes that “ the positive economic impac ts of the proposed Toxics Rule strongl y 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 anal ys is showing that the proposed r ule ’ 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 anal ys es 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 annuall y, 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 anal yses already completed. **Comment 11 8**  : 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. J osh 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 anal ys is 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 this regulation destro ys jobs are flat wrong: The jobs

- impact of the rule wi ll 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 employ ment, likel y leading to the creation of 28,000 to 158,000 jobs between now and 2015. 2. The emp loy

ment 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 suppl iers such as steelmakers). 4. Between 31,000 and 46,000 jobs would be lost due to higher energy prices leading to reductions in output.585

5. Assuming a re

- spending multiplier of 0.5, and since the net impact of the above impacts is positive, another 9,000 to 53,00 0 jobs would be created through re

- spending. C ommenters 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 th e 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 employ ment created by

these capital investments is estim ated at 1.46 million jobs, or about 290,000 jobs on average in each of those years. **Response to Comments 11 7**  **and 11**  **8 :**  The EPA has conducted an updated employ ment anal ys is using the approach applied for the proposed rule which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relatively small in comparison to the affected sector and the overall economy . It should be noted that the agency ’ s employ ment 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 anal ys is and the anal ys is itself are in the RIA for the rule. **Comment 11 9**  **:** Commenter 18419 asks the EPA to perform a true economic anal ys is, evaluate the proposed rule with other new and pending regulations and provide more flexible standards and reasonable compliance guidelines. **Response to Comment 11 9**  **:** The EPA has attempted to provide the greatest degree of flexibility in the rule that is permitted by

law.The agency ’ s economic anal ys is 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 b y OMB in 1993. The agency did not prepare a cumulative impact anal ys is to accompany the rule for the following reasons: 1) the various EO requirements that the agency must comply

with require us to estimate impacts spec ific 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 anal ys is. A cumulative impact anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low

- benefit regulation among other rules that may have large net benefits. By anal yz ing each regulation separately , the EPA makes clear statement s 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 respon d 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/summary report.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.586

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantl y 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 unlikel y this result would be reversed using any reasonable alternative assumptions or methods. This conc lusion is likely to also be attributable to this rule as shown in the RIA. **5. Job analysis: temporary versus permanent jobs. Comment 1**  **20 :**  Commenters 17811 and 18436 believe that installation of new pollution controls would be a job

- growth opportunity in Al abama because money spent on controls for power plants creates high

quality 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 Associ ation 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 1 20**  **:** The EPA finds commenters’ economic predictions and statements of benefits to be reasonable. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employment impact to be relativel y s mall in comparison to the affected sector and the overall economy. **Comment 1 2**  **1:** Commenters 17834 and 18033 disagree with the EPA speculation that job losses will be offset b y increasing jobs in air pollution technology production. C ommenters believe the proposed rule will decrease job creation and sees no assurance or conclusive data that jobs will be created. C ommenters 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 u sually taken seriousl y enough in professional journals. Based on the foregoing, it is difficult for EPA to legitimatel y cl aim that the proposed rule ’ s benefits anal ys is is accurate. ” **Response to Comment 1 2**  **1:** The EPA does not have the flexibility to withdraw or delay

the rule, which is governed b y a consent decree and the requirements of the CAA. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the empl oy ment impact to be relativel y small in comparison to the affected sector and the overall economy . All of these anal yses are found in the RIAs for the respective rules. **Comment 1 22**  : 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 b y 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.587

**Response to Comment 1 22**  **:** The EPA has conducted extensive anal ys is of the rule, which can be found in the RIA. The cost analy sis 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 empl oy ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment 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 anal ys is does not find it to be reas onable. **Comment 1 23**  : 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 emplo y 75
- 100 people versus 25

- 30 for a gas plant of equivalent size. **Response to Comment 1 23**  **:** The EPA has conducted an updated employment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. The commenter points to only one potential change in employ ment, 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 1**  **24 :**  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 b y industry
. **Response to Comment 1 24**  **:** The EPA has conducted an updated emplo yment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expect s the employ ment impact to be relativel y 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 an d 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 1 25**  **:** Commenter 19121 says that the EPA appears to have overstated the job creation estimates due to economic growth under the proposed rule. **Response to Comment 1 25**  **:** The EPA has conducted an updated emplo yment anal ys is which shows some potential positive and negative emp loy ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. **Comment 12 6**  **:** Commenters 16469 and 18500 estimate the potential job losses associated with the clos ure 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. C ommenters note that the EPA ’ s anal ys is did not estimate the effects of adverse emplo ym ent 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 data588

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 20 07 DOE/NETLCoal 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 12 6**  **:** The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity) and coal

- fired generation will not change significantl y. 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 employ ment anal ys is which shows some potential positive and negativ e employ ment changes from the rule, but overall expects the employ ment impact to be relativel y 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 li ght of the significant benefits of the rule. **Comment 12 7**  : 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. C ommenters 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. C ommenters ask that the EPA ’ s anal ys is account for the loss of tax and support for local schools due to job losses. **Respon se to Comment 12**  **7 :**  The EPA analysis indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity) and coal

- fired generation will not change significantl y. 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y 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 12 8**  : C ommenter 17409 quotes estimates by I CF International that employ ment 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 12 8**  **:** The EPA has co nducted an updated employment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y 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 anal ysis is as accurate, transparent, and well

- supported.589

**Comment 12 9**  : Commenter 17839 states that the transition to clean, renewable energy will create many more job s than may

be lost due to the proposed rule and questions if jobs will actually be lost at all. **Response to Comment 12 9**  **:** The EPA agrees that this can be one source of new emplo ym ent resulting from today ’s rule. It has conducted an updated employ ment analys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 1 30**  **:** 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 b y coal mines or trucking companies out of work as well. **Response to Comment 1 30**  **:** The EPA analysis indicates that c oal

- fired generation will not change significantl y. The EPA has conducted an updated employment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **Comment 1 31**  **:** 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 1 31**  **:** The EPA generall y agrees with the thrust of commenters’ assertions and those of the World Resources Institute. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy. **Comment 1 3**  **2** : 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 1 3**  **2:** The EPA disagrees and notes that its anal ys is indicates that there will be a small amount of coal retirements ( less than 2% of all coal

- fired capacity) and coal

- fired generation will not change significantl y. 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 requirements to reduce emissions. Overall, coal

- fired generation is not expected to change significantly since sources are anticipated to in stall pollution controls. The EPA has conducted an updated employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected sector and the overall economy
. **6. Natural gas. Comment 1**  **33 :**  Numerous commenters (17403, 17639, 17640, 17797, 17799, 17806, 17829, 17919, 18488, 18023 ) point out that the compliance dates underestimate the time needed to compl y with the590

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 electric ity

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 EEIreport 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 ag ency has prepared anal ys es 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 relativel y 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 economicall y 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 anal yz ed 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 significantl y in recent ye ars, and prices have remained fairl y stable since their peak in the earl y 2000s. **Comment 1 34**  **:** Commenter 17852 states that n atural gas prices are not more volatile than for other comparable commodities . Though not strictl y part of the EPA ’ s “beyond the floor” anal ys is, 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 m ajor price swings during short
- lived weather events. ” Simply put, natural gas prices today are not inherentl y more volatile than other comparable commodities, and the U.S.

- given the abundance of natural gas

- is likely to experience significantl y 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 future. These reasons include: an enhanced resource base due to shale gas, improved drilling technology , improved storage and delivery infrastructure, and the eli mination 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 1 34**  **:** The EPA’s anal ys is 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 historicall y. The re asons given b y commenters for expecting less591

natural gas price volatility in the future are not unreasonable, however, nor are observations about increasing coal demand elsewhere. **Comment 1 35**  **:** Commenter 17725 states that natural gas use is onl y an option in places where infrastructure exists to supply sufficient natural gas to the EGU and other local needs and reports that ye ar- round reliable gas delivery is rare due to requirements to meet the other nee ds. The commenter says that gas interruptions are prevalent in the winter, but can happen ye ar - 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 ye ars. 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 s ys tem to allow natural gas combus tion. **Response to Comment 1 35**  **:** The EPA ’ s anal ys is of the impacts to the power sector can be found in the RIA of the rule. The agency has anal yz ed 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 quickl y 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 significantl y in recent ye ars, and prices have remained fairly stable since their peak in the early 2000s. **Comment 1 36**  : 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 1 36**  **:** The EPA has designe d 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 e conomy , 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 13 7**  : Multiple commenters (17403, 17812, 17 868, 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 co ntrols. The commenters quote NERA estimates that natural gas prices will increase b y 17% in 2016, much higher than the EPA estimate of 0.6% to 1.3% increase. This translates to a natural gas expenditure increase b y residential, commercial and industrial se ctors by $8.2 billion per year, or $85 billion (present value) for 2011

- 2030. Commenter 17868 agrees that prices will increase more than the EPA estimates and asks that the EPA use a minimum set of natural gas prices such as the provided graph of average n ational 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 13**  **7 :**  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 documentation592

(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 det ailed 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 suppl y 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 b y end

- use consumers at any particular point in time. The natural gas market in the U.S. has historically experienced significant p rice 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 allo wing the market to successfull y align immediate supply and demand needs; however, end

- use consumers are typicall y s hielded from experiencing these rapid fluctuations in natural gas prices b y retail rate regulation and by hedging through longer

- term fuel su pply contracts. IPM assumes these longer

- term price arrangements take place “ outside of the model ” and on top of the “real

- time ” shorter

term price variation necessary to align suppl y 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 13 8**  : Commenter 17868 discusses the factors that could lead to higher natural gas prices not currentl y 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 n atural 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

b e 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 m ore 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 per MMBtu was determined. Page 10

- 13 o f 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 onl y, so it must be fed an exogenous a ssumption on LNG imports (or exports) and cannot predict or capture changes in world

- wide development and trading of natural gas.593

**Response to Comment 13 8**  **:** 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 pro cess - 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 suppl y of and demand in competitive markets for the fuel across the modeled time horizon. As such, it should be understo od that the pattern of IPM natural gas price projections over time is not a forecast of natural gas prices incurred b y 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 successfull y align immediate supply and demand needs; however, end

- use consumers are typicall y s hielded from experiencing these rapid fluctuations in natural gas prices b y 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 ” shorter

term price variation necessary to align suppl y and demand. Therefore, the model ’ s natural gas price projections should not be mi staken 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 13 9**  : 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 13 9**  **:** 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 1 40**  **:** Commenter 17627 quotes the Babcock & Wilcox Wh ite Paper MS

- 14 “ Natural Gas Conversions of Existing Coal

-Fired Boilers ” 2010 and recommends the EPA project capital costs based on the B&W cost s. **Response to Comment 1 40**  **:** 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 1,594

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 14 1**  : 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 exac erbate the nation ’ s weak economic situation. The commenter worries that the widespread conversion from coal or oil to natural gas b y power plants will lead to an increase in natural gas consumption and costs. **Response to Comment 14 1**  **:** 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 analy sis shows only modest conversion to natural gas and that coal will continue to play a ma jor 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

effici ency

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 1 42**  : 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 propo sed 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 1 42**  **:** 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 analy sis 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 beli eves 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 improvem ents. **Comment 1 4**  **3** : 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
- 178 53
- A2_Figure1and2Page3.doc.) **Response to Comment 1 4**  **3:** . 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 generall y 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 1 44**  : 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,595

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 le ad 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 1 44**  **:** 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 significantl y as a result of this rule. Nonetheless, th e 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 1 45**  **:** 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 b y Brattle Group, ICF, Credit Suisse, CRA, FBR, Wood McKenzie and Bernstein Research on the way s the proposed rule will lessen the use of coal and increase natural gas use. **Response to Comment 1 45**  **:** The EPA ’ s anal ys is of the impacts to the power sector can be found in the RIA of the rule. The analysis indicates that onl y a small number of coal plants will retire, and coal

- fired generation will continue to be the largest source of electricity . The agency has anal yz ed 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 earl y 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 1**  **46 :**  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 sho rt timeline for these rules will increase the cost of power in most regions and threaten reliability
. **Response to Comment 1 46**  **:** 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 14 7**  **:** 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 equip ment 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.596

**Response to Comment 14 7**  **:** 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 14 8**  **:** 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 negativel y impact the economy and federal budget. **Response to Comment 14**  **8 :**  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 14 9**  **:** Commenter 19213 states that small utilitie s 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 14 9**  **:** 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 1 50**  : Commenter 17834 states that the proposed rule will require costs be passed on to consumers, meaning state public utility comm issions 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 Co mment 1**  **50 :**  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 feas ibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply , if conditions warrant (see preamble). **Comment 1 51**  : Commenters 17743 and 17761 express concern that the short compliance deadlin e will require many facilities to be taken offline at that same time to make upgrades, leading to reliability issues. **Response to Comment 151 :**  See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for grantin g utilities some additional time to comply , if conditions warrant (see preamble). **Comment 15 2**  **:** 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.597

**Response to Comment 15 2**  **:** 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 1 53**  : Commenters 17881 and 18033 expresses concern that even with a blanket 1

- ye ar 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 b y the CAA. **Response to Comment 1 53**  **:** 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 1 5**  **4:** Commenter 15002 states that the proposed rule should regulate emissions to the average emissions achieved b y the top performing 12% of sources since this provides a satisfactory balance between emission controls, the monetized value of the associated health benefit s and the projected costs. The commenter also urges the EPA to adopt a review schedule for Hg and HAP emissions, such as a 5
- ye ar review cycle as defined under the CAA NAAQS review process. **Response to Comment 1 5**  **4:** The rule will impose HAP emissions limits consistent with the requirements of section 112(d) of the CAA. Although the EPA has conducted a detailed anal ys is of the costs and benefits of the rule, the setting of a MACT floor is not based on the costs and benefits of control
. S etting standards beyon d the MACT floor does consider costs and non

- air quality health and environmental impacts and energy requirements . The review cycle for standards such as this one is not longer than 8 years as set forth in CAA section 112 (d)(6)
. **Comment 155 :**  Commenter 1765 4 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 1 55**  **:** See preamble and TSD on feasibility for further dis cussion. In addition, there are certain provisions for granting utilities some additional time to comply , if conditions warrant (see preamble). **Comment 1 56**  : 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 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 adequat e 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 reco ver capital commitments made before the rule is final. Commenters 17886 and 18441 states that earl y 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 flexibili ty, and the proposed rule requires units to meet limits to be shut down. C ommenters believe utility decisions on unit retirement versus additional control installations must factor into all anticipated and existing regulations.598

**Response to Comment 1 56**  **:** 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 15 7**  **:** 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 15 7**  **:** 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 15 8**  **:** Commenter 17911 explains the different approac hes used to obtain funding b y 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 publicl y 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 b y the proposed rule. The commenter also explains that municipal bonds have been hit by threatened bankruptcies of municipalities, which makes it increasingl y 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 increasingl y difficult to borrow. Municipalities are legall y prohibited from skipping or speeding up regulatory or legal processes. All of these factors make it difficult for municipal utilities to move forward quickl y with construction of new controls or generation. **Respons e to Comment 15**  **8 :**  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 t ax 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 15 9**  : Commenter 18447 explains that they wi ll 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 $1 8.2 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. **Response to Comment 15 9**  **:** 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 1 60**  : Commenters 17808 and 18421 do not believe that labor availability will constrain control installation in the required timeframe and cites I CAC response that it will not for these reasons: 1. Power sector has demonstrated ability to install large number of s ys tems in short time period. 2. Majority

of coal plans have installed control sy stems already
.599

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 deploy ment of technologies. **Response to Comment 1 60**  **:** The EPA thanks the commenter for their comments. Th ese comments are generall y consistent with the conclusions of the agency ’ s anal ys es on feasibility of control installations for this rule as found in the TSD on this subject in the docket for this rulemaking. **Comment 1 61**  : Commenter 18498 considers the comp liance 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 complian ce 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 ye ars with extensions allowed for 2 additional years. **Response to Comment 1 61**  **:** See preamble and TSD on feasibility for further discussion. The EPA has anal yz ed 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 quickl y 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 b y the CAA. **Comment 1 62**  : 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 especiall y 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 1 62**  **:** See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions f or granting utilities some additional time to comply , if conditions warrant (see preamble). **Comment 16 3**  : Commenter 18435 states that a wide range of technical and economicall y feasible practices and technologies are available currentl y t o meet the emission limits and are in use around the country
. **Response to Comment 16 3**  **:** 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. **Comment 1 64**  : Commenter 17403 disagrees with the employ ment 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 employ ment opportunities while protecting the environment. **R esponse to Comment 1**  **64 :**  The EPA has conducted an updated employment anal ys is which shows some potential positive and negative emplo ym ent changes from the rule, but overall expects the employ ment impact to be relativel y small in comparison to the affected s ector and the overall economy
.600

**Comment 1 6**  **5** : Several c ommenters (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 neces sary . 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 1 6**  **5:** 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 1**  **66** : 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 facilitie s 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 perio d 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 1 66**  **:** 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 16 7**  : Commenter 18025 explains that betw een 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 ye ars 2009 and 2010, which shows the industry can complete large numbers of retrof its in a short time period. C ommenter 18025 encourage s the EPA to finalize the rule on the planned schedule to avoid market uncertainty. **Response to Comment 16 7**  **:** We agree with the commenter and are issuing the rule consistent the consent decree
. **Comment 16 8**  : 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 sy stem reliability . This would increase costs for consumers by 5% in 2014, and trend up to 10% for 2018 and later ye ars. 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 16 8**  **:** See preamble for discussion of requirements for non

- continental liquid oil

fired EGUs
. **Comment 16 9**  **:** Commenter 18538 believes the EPA has underestimated the time needed to plan, permit and construct sufficient new generation and transmission to compensate for the retirement s caused by the proposed rule. **Response to Comment 16 9**  **:** The claims of retirements in recent studies of the impact of EPA rules are addressed in the preamble for the final rule
.601

**Comment 1 70**  **:** Commenter 19121 states that the rule ’ s timeline combined with over

- regulated HAP place a threat to grid reliability
. **Response to Comment 1 70**  **:** 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 supp orting materials, the EPA disagrees that HAP are “over

- regulated” b y the rule. **8. Large burden, little environmental gain. Comment 1**  **71** : Several commenters (17681, 17731, 17761) state that the EPA has no data relating to benefits from reducing non

- Hg HAP, s o the costs of the proposed rule exceed the HAP benefits by 29,000 times. Commenter 17761 states that the impact anal ys is was largel y focused on Hg with little support for other HAP reductions and failed to provide account of true costs and benefits. **Response to Comment 1 71**  **:** The benefits of this rule include the reductions in non

- HAP emissions such as SO 2 and PM 2.5 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 b y 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. **Comm ent 1**  **72 :**  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 1 73**  : Commenter 17842 cites the E PA estimate that the rule will cost $10.9 billion and create social benefits of $42 to $140 billion annually and states that other anal ys es suggest costs will be more severe due to the cumulative impact of interrelated emission regulations. **Response to Com ments 1**  **72 -**  **1 73**  **:** 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 quickl y in response to demand. The EPA has not provided a cumulative impact anal ys is of vario us rulemakings for a variety of reasons, which are outlined in the preamble and elsewhere in this document. **Comment 17 4**  **:** 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 c ommenters (17656, 17681, 17917) believe the EPA ’ s estimates are incorrect and the true co st 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 ev aluating 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 benef its and costs as accuratel y as possible. ” and include analyses b y EIA, EEI, NERC , NERA, Credit Suisse, IC F and Burns & McDonnell.602

**Response to Comment 17 4**  **:** The EPA ’ s anal ys is of the impacts to the power sector can be found in the RIA of the rule. The methodology applied in that anal ys is was subjected to extensive external peer review and this is documented in the RIA and supporting materials. In contrast, not all of the anal ys es cited by the commenters are completely transparent, and the lack of su fficient documentation of methodologies and assumptions prevents the EPA from subjecting them to critical review. Industry has also shown that it can build new capacity quickl y in response to demand. The EPA has not provided a cumulative impact anal ys is 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 employ ment anal ys is which shows some potential positive and negative employ ment changes from the rule, but ov erall expects the employ

ment impact to be relativel y s mall in comparison to the affected sector and the overall economy. **Comment 1 75**  **:** Commenter 17637 states that the emission reductions achieved by the proposed rule would be realized b y other rules such as the NAAQS for PM, SO 2 and SO 3 and related transport rules. As such, the benefit of adding further control equipment and work practices will be minor. **Response to Comment 1 75**  **:** The emission reductions from these rules are based on the agency ’ s best estimate s of how emissions of HAP and non

- HAP pollutants are affected by the control options examined for this proposed rule. 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 1 76**  **:** 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 co mbust only fuel oil and natural gas. **Response to Comment 1 7**  **6:** Natural gas

- firing is not impacted by this rule, and the EPA has included anal ys is for some modest improvements available to oil

- fired units to achieve compliance, which can be found in the RIA. **Comment 17 7**  **:** 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 cos ts and quotes the NERA study ’ s prediction of 1.44 million job

- years lost b y 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 analy sis, so the total benefit of $50 billion per year is likely to be a lo w 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 decrea se production. **Response to Comment 17 7**  **:** The agency ’ s anal ysis 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 of603

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 earl y b y 2015 and that short

- term construction labor will experience an increase of 46 ,000 job

ye ars 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. Finall y, 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 anal ytical 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 17 8**  : 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 17 8**  **:** The agency has issued its rule consistent with the DC Circuit Court ’ s vacature and with the requirements of CAA section 112(d). **Comment 17 9**  : 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 SO 2 and PM 2.5 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 analy sis 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 b y at least six

- fold. More information on the estim ates 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 HAP emissions from EGUs . Conclusions regarding the appropriate and necessary finding under section 112(n) (1)(A) of the CAA can be reviewed in the elsewhere in the final rule record
. **Comment 1 80**  **:** Several **c** ommenters (17765, 17840, 18033) find the proposed rule to produce little to no public health or environmental benefit while imposing unnecessary costs or losses of employ ment. C ommenters state that the pollutants are already regulated under the NAAQS program or other regulations. **Response to Comment 1 80**  **:** 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 concomitantl y with the HAP reductions. **Comment 1 81**  : Commenter 18421 cites the EPA ’ s estimate that the proposed rule will yield monetized net benefits of up to $130 billion every year, once th e 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 ecos ys tem benefits of reducing nitrogen and sulfur emissions and deposition and vegetation benefits from reducing ozone.604

**Response to Comment 181 :**  The agency agrees with the commenter. **Comment 1 82**  **:** Commenter 18428 considers the proposed rule to be very costly while offering few benefits. The commenter points out that s ince the year 2000, their company has achieved a 62% reduction in Hg. **Response to Comment 1 82**  **:** 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. **Commen t 1**  **83 :**  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 compl y 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 1 83**  **:** 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

nati onwide may

retire early

as a result of the rule, and this estimate is based on calculations from IPM, a peer

- reviewed model. **Comment 1 84**  **:** 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 EP A to develop a separate RIA for non

- continental oil

- fired units. **Response to Comment 1 84**  **:** 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 non continental liquid oil

- fired units in the final rule and has provided an anal ysis for non

- continental oil

fired units as part of the RIA for the final rule
. **9. State regulators. Comment 18**  **5 :**  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. C ommenters 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 th e EPA in justifying their request for appropriations and states in justifying permit fee increases. The commenter requests the EPA consider state administrative costs and605

make this information available as directed in UMRA, EO 12866 and EO 13132. The commenter urges the EPA to accuratel y assess the implementation costs on states, so the rule may be implemented properl y and in a timel y manner to avoid adverse health effects. Commenters 16859 and 17400 explain that for each new EPA rule, states may incur slightl y 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 s tart - 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 properl y and in a timely manner without adversel y 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 c onsider the availability of funding support in its planning for new rule adoption schedules and other implementation activities following the rule issuance. **Response to Comment 18 5**  **:** The agency has addressed the impacts on state and municipal agencies in co mpliance 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 accordingl y to requests for additional state and local agency

funding if it is determined that such funding is needed for implementation of this rule. **Comment 1 86**  **:** 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 anal ytical burden associated with this rule and others recently proposed will increase and reliance on the EPA ’ s technical and econ omic 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 1 86**  **:** The agency may consider changing Grant Agreements and help states in other ways if the anal ytical burden to them is substantial enough to warrant agency action. **Comment 18 7**  **:** Commenter 17620 discusses the increased workload of state and local air pollution control agencies as a result of the proposed rule. The commenter explains t hat 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 will also conduct in spections 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 ye ars when the majority of implementation activities will occur. **Response to Comment 18 7**  **:** The agen cy will respond accordingl y to requests for additional state and local agency

funding if it is determined that such funding is needed for implementation of this rule. **Comment 18 8**  **:** Commenter 17620 states that the reductions in SO 2 and PM 2.5 required b y 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 emissions606

made b y the very l arge 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 h ealth and a cleaner environment. **Response to Comment 18 8**  **:** The EPA thanks the commenter for the comments. The MATS is a standard to reduce HAP, but we are also finalizing revisions to the NSPS for NO X , SO 2 , and PM emissions limits for utilities. Much of the HAP requirements will also lead to co

- benefits such as PM 2.5 and SO 2 reductions that could be of aid to states working on implementation of various NAAQS and regional haze strategies
. **Comment 18 9**  : 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 i s placed on state agencies and develop a rule that reduces air pollution but provides for efficient implementation and enforcement. **Response to Comment 18 9**  **:** The agency is careful to mitigate the impacts of this rule to permitting authorities to the extent possible. The agency will respond accordingl y 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 1 90**  **:** 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 exp erienced 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 1 91**  : Commenter 17409 quotes a Stanford University study that says the U.S. could be run entirely on clean energy

w ithin 10 years, at reasonable cost. The commenter goes on to acknowledge other innovations in the power generatio n 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. **Response to Comment 1 91**  **:** We agree with the commenter that new re gulations 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 1 92**  : Commenter 17 855 discusses the difficulties for waste coal industry in compl ying 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 c ommenter explains that waste coal power plants control NO X and SO 2 and PM currentl y, 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 use607

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 1 92**  **:** 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 economicall y unviable as s uggested b y commenter. Should additional controls be required at certain facilities, such controls can be added just as at other EGU s . Facilities that have already achieved significant control of emissions are likel y to face lower costs to comply

with today’s rule. **Comment 1 93**  : Commenter 17867 explains the Boardman 2020 Plan as an innovative approach to achieving environmental goals b y ending coal

- fired generation at relativel y yo ung and efficient EGUs. The commenter cites to key features contributing to su ccessful 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 appropriatel y 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 earl y cessation of coal operations and interim co ntrols 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 s olutions 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 clearl y 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. **Response to Comment 1 93**  **:** 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 1 94**  : Commenter 18039 believes that power plants in Massachusetts and other states with reduced Hg limits have been placed at a competitive disad vantage 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
.608

**Response to Comment 1 94**  **:** 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 1 95**  : 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 pl acing stricter limits on Hg from power plants. **Response to Comment 1 95**  **:** The EPA agrees with the commenter. **Comment 19 6**  : Commenter 19042 cites the Executive Orders and policy directives from the Obama Administration that encourage federal agencies to increa se 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 anal ys is 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 anal ys is 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 19 6**  **:** 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 EPA’s anal ysis projects a near

- term increase in the average retail electricity price of 3.1% in 2015 falling to 2% b y 2020 under the final rule in the contiguous U.S. **Comment 197** : Commenter 19042 discusses the fe deral deficit of $1.6 trillion and the states ’ defi cit of $130 billion and points out that the proposed rule will affect the federal budget in two ways: 1. direct compliance costs to electric generating units (EGUs) owned b y federal agencies; and 2. pass - through compliance costs paid in the form of higher prices for electricity purchased b y federal agencies. **Response to Comment 19 7**  **:** The agency estimated the increase in direct compliance costs at federally

owned 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 b y 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.609

**Comment 19 8**  : Commenter 19042 notes the EPA identifie d 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 op erating 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 analy sis 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, s uch 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 annuall y 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 b y 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 ye ar 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 deplo y 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 ye ar electricity and associated GHG emis sions 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 anal ytical basis. (See http://www.whitehouse.gov/administration/eop/ceq/sustainability /omb

- scorecards .) **Response to Comment 19 8**  **:** The agency estimated the retail electricity price nationwide to increase on average b y 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 19 9**  **:** Commenter 19042 provides analyses of the estimated federal budget impacts, taking into account the variation by region. However, since publicall y available data is aggregated b y agency, disaggregation b y region was not possible, and the commenter suggests the government do this anal ysis. 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 es timate the610

magnitude of the unfunded mandate being imposed on states and local governments and the cumulative impact of pending EPA rulemakings. **Response to Comment 19 9**  **:** The agency has revised its UMRA analy sis for the final rule. The agency did not prepare a cumulative impact anal ys is 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 anal ys is. A cumulative impact anal ys is lumps several regulations together and can potentially mask a high

- cost/low

- benefit regulation among other rules that may have large net benefits. By

analy zing each regulation separatel y, 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 actio ns (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 wi ll 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 re gulations. 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/summary report.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 significantl y 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 unlikel y 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 prematurel y retired. **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 20**  **1** : 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 o f the rules. The commenter reports investing nearl y $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 ty pes and believes that expansion of nuclear and alternative energy

sources will occur as well. The commenter also explains that the proposed rule and611

other new regulation will increas e 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 20**  **1:** We agree with the commenter that this rule could lead to an increase in the energy efficiency

of the electric power boiler fleet.612

**6J -**  **Im pacts/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 b y 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 SO 2 . The agency has prepared an extensive anal ys is 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 naturall y. The commenter considers the rule to be adversel y affecting efforts to stimulate the economy and job growth and causing electric rates to rise. **Response to Comment 2:** The agency ’ s anal ys es of costs and benefits reflect the latest, peer

- reviewed science that is available. The benefits anal ys is 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 anal ys es are also based on peer

- reviewed studies and analyses . The RIA for the rule documents both anal ys es . **Comment 3:** Commenter 16850 explains that Florida ’ s investor

- owned e lectric 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 am ong 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** : C ommenters 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 are613

estimated can be found in the RIA for the rule. The employ ment impacts estimated by the agency

for the rule reflect both construction labor associated with new c ontrol 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 anal ys is 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. C ommenter 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 elec tricity 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 th e estimated price increase s . 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. Co mmenter 17766 explains that 71% of African Americans and 80% of Hispanics live in an are a 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 proxi mity to power plants means that they

are more likel y 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 likel y to live in poverty , they

are less able to m ove 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 discu ssed 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, SO 2 , and other pollutants in our RIA . Populations that are the focus of EO 12898 (low

- in come, 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 PM 2.5 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 PM 2.5 - related deaths and points out the EPA estimate of deaths among those exposed to PM 2.5 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.)614

**Response to Comment 7:** The EPA disagrees that the method the EPA uses to monetize PM 2.5 benefits produces unreasonabl y large estimates. The EPA estimates health benefits below the lowest measured level ( LM L), as n o evidence suggest a health effect threshold for PM 2.5 . These methods have withstood continuous regular reviews by the EPA ’ s SAB
. Analyses conducted for the proposed rule demonstrated that the vast majority

of PM 2.5 health benefits occurred above the LM L
. 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 ye ar. ” 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 $1 67 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

- bene fits of this rule resulting from PM 2.5 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 conc erned that the estimated costs and affects of the proposed rule do not adequatel y 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 electric ity 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 th e estimated price increase s . State and local rate setting agencies are best equipped to deal with the issues concerning higher electricity rates in their areas. As to anal ys is including the effects of pending regulations, the agenc y did not prepare a cumulative impact anal ys is to accompany the rule for the following reasons: 1) the various EO requirements that the agency must compl y 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 anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low benefit regulation among other rules that may have large net benefits. By

anal yz ing each regulation separatel y, the EPA makes clear statements about what impacts, costs, and benefits will be generat ed 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 accuratel y 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 respond615

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 cos ts 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 / summary report.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 significantl y 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 b y which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikel y 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 / summary report.pdf ). As shown in the report, the direct benefits from the 1990 CAA Amendments reach almost $2 trillion for the ye ar 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 increa sed 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. ( Wh itman 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 to616

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. Wh itman 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 b y increased regulatory

compliance costs. Cf

. International Un ion 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 stro ng 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, hous eholds 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 unemploy ment rates at 9.2% and effective unemploy ment 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” anal ys is does not co nsider 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 final rule establishes emissions standards that 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 other HAP emission reductions, along with the substantial benefits from reductions in emissions of PM, SO 2 , 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 regio ns seeing increases of 6.3% while other consumers in different regions will see increases of onl y 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 f

rom 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 th ose from a cumulative impact analysis. A cumulative impact anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low benefit regulation among other rules that may have large net benefits. By anal yz ing each regulation separatel y, 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.617

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 re gulations (found at http://www.epa.gov/air/sect812/feb11/summary report.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 significantl y exceed their direct costs, which means economic welfare and quality o f 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 unlikel y 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 cop ywrite 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 largel y due to SO 2 emission. The commenter also cites a study

which estimates emission

- related damages from coal

- fired power plants to be between $0.02 and $1.5 7 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 b y 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 SO 2 , NO X and PM emissions from coal

- fired power plants account for $62 bil lion 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 specificall y (it is included in our benefits anal ys es in o ur 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 t urbines at the Crawford plant were installed in 1958 and 1961. The commenter says that pollution from these two618

plants cost neighboring communities $127 million annually in health damages, according to the October 2011 report b y Environmental Law and Polic y 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 unfairl y 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 employ ment 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 ye ars. Because the benefits in question are the health and wellbeing of children, the discount rate means the worth of children decreases b y half every 10 years. The commenter suggest s 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 anal ys is 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 c alls 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 b y 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 su fferers. In addition, reductions in Hg will also improve health and ecosy stems, 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.619

**Response to Comment 17:** We agree with the commenter that the pollutant reductions from this ru le 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 c ommenters (18432, 18435, 18541) urge the EPA to proceed with finalizing the proposed rule without changing it, as it will prevent more Americans and especial ly children from premature death or chronic illness. **Response to Comment 18:** The EPA thanks the commenter for their comments. We have review ed public comments on the proposed rule as required by law and issued this final rule in light after considering an d responding to such comments. **Comment 19** : Multiple c ommenters (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 cos t of the pollution emitted by EGUs is being unfairly placed on the public instead of the polluting source. The commenters considered the EPA anal ys es 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 limit ed. **Response to Comment 19** : The agency recognizes the need to include the effects on wildlife and ecos ys tems in the benefits analyses for our rules. We include these benefits to the extent that it is credibl y possible according to our understanding of the relevant science in our anal ys es , 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 p rovides societal benefits more than double the implementation cost by the ye ar 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 sh owed 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 c ommenters ( 19536, 19537, 19538) report that the Minnesota Pollution Control Agency and Legislative Commission on Minnesota Res ources 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. C ommenters 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.620

C ommenters state that a decline in angling of just 25% due to lake and stream fouling b y 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. C ommenters 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 ty pes of impacts and how the agency ’ s benefits anal ys is considered them, refer to the RIA for the rule.621

**6K -**  **Im pacts/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, 1788 2, 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, 1 9121, 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 b y 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 anal ys is, 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 anal ys is. The commenter states that despite criticism, the inclusion of PM 2.5 co - benefits as part of the monetized benefits are appropriate because HAP are part of the PM 2.5 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 15 002 further notes that PM 2.5 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 th e 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 s ynergistic and additive effects of the pollutants whose emissions will be reduced; (3) enhanced ecos ys tem services; (4) reduced acidification of ecos ys tems; (5) elimination or reduction of a variety of unquantified health impacts, including respiratory effects, resulting in increased hospital and emergency room visits, respiratory

s ymptoms, airway

hy per responsiveness, 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., & H ammitt, 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 to xicity 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 strictl y 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.622

**Response to Comment 1:** This rule is expected to achieve important non

- Hg HAP benefit s. However, monetization of non

- Hg HAP benefits is limited by currentl y 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. Ins tead, 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 me asure 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 decis ion makers understand the magnitudes of the effects of alternative actions. However, some important benefits and costs (e.g., privacy protection) may be inherentl y 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 Anal ys es (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, 1646 9, 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 PM 2.5 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 incrementall y 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 anal ys is of chromium emissions was flawed, in that hexavalent chromium, a carcinogen, may be converted to less toxic fo rms 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 , commenter623

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 res ources. **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 PM 2.5 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 anal ys is 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 th e anal ys is 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 especiall y 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 pub lic 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 PM 2.5 health co

- benefits expected as a result of direct PM 2.5 and SO 2 emission reductions is directed b y 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 ty

pically 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 ac counted 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 b y 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 anal ys is 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 directl y 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 associ ated with a regulatory

action, to the extent feasible. We further note that if we were able to fully monetize all of the624

benefit categories, the benefits would exceed the costs by an even greater amount than we currently estimate. **3. Methods used to calcul ate 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 s uggests 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 undere stimate because the EPA was not able to anal yz e 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), neurops yc hological tests that are not subtests of IQ tests and are not highl y 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, in cluding 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 ecos ys tems. **Comment 4:** Several commenters (17702, 17751, 18018, 18033, 18500) express concerns that the method the EPA used to monetize benefits produces unreasonabl y large estimates. Commenter 18033 cites the EPA ’ s counting of mortality estimates for PM 2.5 exposures below the lowest measured level (LML) as a ma

jor 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 drasticall y ov erestimates mortality associated with low levels of PM 2.5 . 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 VSLis 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 ye ars b y the625

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 VSLthan an 80

- ye ar- 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

- anal ys is 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 - anal ys is 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 - anal ys is. 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 b y the anal ys is 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

- anal ys es of WTP studies. The commenter recommends the following: 1. Bellavance, F., Dionne, G., Lebeau, M. 2009. The Value of a Statistical Life: A meta

- anal ys is with a mixed effects regression model. Journal of Health Economics 28: 444

- 464. 2. Bowland, B.J., B eghin, 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
- ana lysis. Accident Anal ys is 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 Policy Analysis**.** 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

- anal ys is 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 Li fe 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

asse ssed the effect of selection bias on meta

anal ys es 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 PM 2.5 benefits produces unreasonabl y large estimates. The EPA estimates health impacts of PM 2.5 below the LML , as evidence suggests that there is no discernable threshold for long

- term PM 2.5 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 EPA626

Administrator to be protective of public health within an adequate margin of safety, and are not set at a level of zero risk. Further, anal ys es conduct ed 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 re

an al ys is of the Pope et al. (2002) study found significant health impacts of PM 2.5 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 PM 2.5 that are successivel y lower than the LM L 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 VSLis 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 ye ar). The VSLdoes not represent the value of avoiding or postponing certain death for any particular individual. By convention, estimates of these willingness

- to -pay values are typicall y 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 VSLwould 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 expl ored 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 valuati on of mortality risk reductions.

. http://yosemite.epa.gov/sab/sabproduct.nsf/02ad90b136fc21ef85256eba00436459/41 28007E7876B8F0 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 des cribed as the source for these studies when the EPA originall y 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 o f 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

- anal ys es 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

- anal ys is (USEPA 2006). The agency has627

consulted with the SAB

- EEAC on how to evaluate and appl y meta - anal ys es, 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 anal ys is, 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 anal yses. This effort will include considerations of many potential biases in the re sulting 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 anal ysis is insufficient. Commenter 17621 argues that “th e 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 anal ys es. **Resp onse to Comment 5:**  The EPA disagrees with these commenters that the uncertainty anal ys is is insufficient. We conduct several different ty pes of anal ys es that examine the effects of the most important methodological choices on results. For example, we estim ate 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. (2 002) and larger than the effect estimate by L aden 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 anal ys es examining different income elasticity assumptions. The uncertainties that are not quantifiable are listed in tables to ackn owledge 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, 1849 8, 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 PM 2.5 emissions can be expe cted 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 prop osed 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 PM 2.5 emissions, consider the cost

- benefit anal ys is 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 PM 2.5 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 appreciable628

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 PM 2.5 , 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 PM 2.5 program. Commenter 17719 believes this is pertinent, since the EPA is mandated to find the most co st effective solution for regulatory

priority
. Multiple commenters (18023, 16469, 17621, 17718, 17751, 17761, 17800, 17816, 17919, 17855, 18033, 18963) find the EPA calculation of PM 2.5 NAAQS benefits to be incorrect because the commenters say the EPA is e ither double counting potential benefits of the NAAQS program in the calculation of benefits from the proposed rule, or rel ying on the supposition of health benefits from any PM reduction any where. Commenter 18023 considers this an unfounded supposition th at both the EPA and the EPA science advisors have rejected as too uncertain to adopt when setting PM 2.5 NAAQS. Commenter 18023 points out that if these PM 2.5 benefits are disregarded, the monetized benefits for the proposed rule drop to $0.576 billion, fro m CO 2 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 actuall y come from PM 2.5 reductions from reduced emissions of SO 2 , which is not a HAP, and did not indicate benefits from acid gas reductions. Commenters believe the same benefits would be delivered b y other CAA rulemakings including PM, SO 2 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 SO 2 reductions and the number of avoided outcomes per 1,000 tons of SO 2 reduction is nearl y identical for 2014 and 2016. However, the commenter points out that ambient PM 2.5 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 SO 2 reductions would be achiev ed by the proposed rule. Several commenters (18023, 17638, 17681) state that over 80% of the estimated PM 2.5 health benefits are assumed to occur in areas that meet the levels the EPA is currentl y considering for a new PM 2.5 NAAQS, and thus should not be c onsidered under this rule. Commenter 18500 cautions that the EPA ’ s monetizing benefits estimate due to CO 2 reductions should be considered carefull y 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 PM 2.5 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 PM 2.5 NAAQS or are being addressed b y 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 b y the “ contrived” benefits. Commenters 17919 and 18023 state that the NAAQS set a level of PM 2.5 that the629

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 s afe from health risks. Some commenters (17855, 17621, 17637, 17718, 17761, 18963) state that attainment of the NAAQS for PM 2.5 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] PM 2.5 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 clearl y 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.env soft.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 bel ieves 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 benefit s associated with PM 2.5 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 PM 2.5 health co

- benefits, the EPA disagrees with commenters that PM 2.5 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 PM 2.5 health benefits resulting from primary PM and SO 2 emission reductions, and these co

- benefits are thus an important category to quantify
. Consideration of ancillary benefits in benefit

- cost anal ys is 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 ty

pically 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 b y 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 anal ys is 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 directl y intended effects and associated costs, as well as ancillary (or co

- ) benefits and costs. ”630

In line with this guidance, the EPA estimates all of the anticipated costs and benefits associate d 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 PM 2.5 health benefits, and direct health benefits of reducing SO 2 . I f we were able to fully monetize these benefits, the benefits would exceed the costs by an even greater amount than we currentl y estimate. Regarding commenters ’ assertion that the EPA is double

- counting PM 2.5 health benefits achieved by MATS with those achieved by other regulations and NAAQS, the EPA disagrees with these commenters that the quantified PM 2.5 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 b y 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 b y MATS alone. Further, th e PM 2.5 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 co ntrol strategies for different sources. In short, NAAQS RIAs hyp othesize, 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 PM 2.5 NAAQS RIA. Regarding quantification of health benefits below the PM 2.5 NAAQS, the EPA notes that in implementing these rules, emission controls may lead to reductions in ambient PM 2.5 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, takin g 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 o f 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 ecos ys tem acidification is speculative and unsub stantiated. Commenters 18033 and 18963 point out that the EPA never provided a finding of public health concern to regulate631

non - Hg HAP, and provides no evidence that “more stringent control of acid gases would benefit ecos ys tems 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 PM 2.5 benefits in the RIA are solel y 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 1 1**  **:** 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 previousl y thought (given its presence in remote ecos ys tems, 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 Pol icy

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 ecos ys tems 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 1 2**  **:** Several commenters (16469, 17 621, 17715) take issue with the use of the two primary health studies used in the benefits anal ys is (Pope et al., 2002; L aden et al., 2006). Commenter 17715 argues that the studies take a simplistic approach to their calculations (grouping all PM component s 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 PM 2.5 relied on two studies and not a full review of the published literature, it is flawed and onl y 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 onl y 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 analy sis 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, particularl y 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 1 2**  **:** The EPA disagrees that the methodology used to estimate PM 2.5 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 c ontinuous interagency review. We note that the evidence on differential toxicity of PM 2.5 components and mixtures is currentl y 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 differ ential toxicity among PM 2.5 components could be an important issue, the Council concludes that the state of the632

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 Anal ys is (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 anal ys es, data choices, and methodologies to be sound
. The EPA bases its estimates of the mortality benefits of reducing f

ine 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 underl ying basis for PM mortality benefit estimates to be a good choice ” (p. 1). We further note that we also estimate mortality using functions derived b y 12 experts in an EPA

sponsored expert elicitation (Roman et al. 2 008). The Pope et al. (2002) and L aden et al. (2006) studies were found to be near the 25 th and 75 th %iles of the mortality effect estimates garnered from the expert elicitation. Our use of the expert elicitation functions provides one estimate of the rang e of possible impacts. **Comment 1 3**  **:** 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 19 80
- 2009, despite the decrease in SO 2 and NO X rates by 70%. Commenter 17824 asserts that such evidence raises doubt as to the link between air quality and asthma. **Response to Comment 1 3**  **:** 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 peer

reviewed science and methods that have withstood scrutiny from the EPA ’ s independent SAB, the National Academy of Sciences, and continuous interagency revi ew. Note that the EPA estimates the reduction in asthma attacks, not the onset of asthma, for the calculation of health benefits. **Comment 1 4**  **:** 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 cas es per ye ar. 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 thoroughl y 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 spe cifically

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 anal ys is 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.633

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 nearl y 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 (se e 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 scientificall y- accepted methodologies for estimating HAP

- related benefits. **6. Health impacts are significant. Comment 1**  **5 :**  Numerous commenters (16404, 17254, 17408, 17409, 17766, 17811, 17852, 17871, 18432, 18435, 18436, 18487, 18501, 19536/19537/19538, 18932) explain that the elderl y, 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 th e 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, kidney s, nervous s ys tem, particularl y 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 CO 2 , 1,500 tons of NO X , and almost 350,000 tons of particulates into the air annually ; a third o f 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 p aid 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 t he atmosphere as a result of gases emitted b y 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 fo r 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 1 5**  **:** The EPA agrees that e xposure 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.634

**Comment 1 6**  **:** Many

commenters (16404, 16826, 17157, 17283, 1 7409, 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, o f which 7.1 million are children. Commenters 18435 and 18425 state that SO 2 and NO X are dangerous pollutants that will be significantl y reduced b y this rule. Commenter 18435 argues further that many of the constituents of PM 2.5 are known to cause cardiovas cular 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 c ontrol technology

would avert 70 deaths per year in a population of 33 million people. Commenter 18421 points out the toxic effects of lead, particularl y 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 nicke l 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 ri sk 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 non

cancerous health effects and are known to seriously injure human health. Many of the toxic metals from coal combustion are emitted as fine particulates, which by pass 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 acros s 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 Penns ylvania 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 dioxin s, 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 ye ar nationwide at an economic cost of $100 billion. Some commenters (172 83, 18932) do not fully agree with the decision to use PM 2.5 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 an d 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,635

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, especiall y harmful to children. Commenter 18421 also states that acid gas emissions contribute to acidification of ecos ys tems, 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 PM 2.5 , especially in SO 2 and NO X . In addition, the commenter points out that fuel switching and retirements are also expected to reduce NO X emission and ni trate particles. **Response to Comment 1 6**  **:** 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 environmental risks from exposures of ecos ys tems 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 b y the commenter in the ecos ys tem 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 methyl ation in acidified s ys tems. Based on recent peer - reviewed research including Evans et al. (2011), acid gases can significantl y contribute to acidification and the EPA agrees that those acid gases pose a risk for acidification of ecos ys tems. 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 1 7**  **:** Commenter 17919 suggests that the proposed rule will adversely impact public health by increasing the cost of medical care, b y “ suppressing economic growth and the improved health it brings, ” and b y 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 1 7**  **:** The commenter ’ s assertion relies on the theory that the cost of the rule will result in lost income or employ ment that will, in turn, result in negative health effects that offset the636

positive health effects of the r ule. (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 anal ys es 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 b y the pass through costs of the regulation are unlikel y to cause large changes in any single aspect of household spending, such as health care. These anal ys es also fail to consider that household income may increase if individuals are able to work (or work more) as a result of improved he alth, 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 consistentl y advised against attempting to quantify any health

- health tradeoffs of regulation. **8. Support for the proposed rule.**  **Comment 1 8**  **:** 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 tox ics 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 strongl y support the rule. Commenters 18432 and 18435 further urge the EPA not to weaken the proposed rule. **Response to Comment 1 8**  **:** The EPA acknowledges generally supportive comments (including commenters 1 2267, 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 PM 2.5 health co

- benefits. The EPA agrees with these commenters that the large health co

- benefits of this rule resulting from PM 2.5 reductions far outweigh the costs and may underestimate the true benefits, as some health impacts ( e.g., ozone health benefits, enhanced ecos ys tem services, increased fish consumption by

women) were not able to be quantified. **9. Miscellaneous comments. Comment 1**  **9 :**  Commenter 16630 asks how averaging in combination with the credits affect the environment. **Response to Comment 1 9**  **:** 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.637

**Comment 2 1**  **:** 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 EGU s 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 accordingl y. **Response to Comment 2 1**  **:** Commenter appears to take issue with the EPA ’ s approach to evaluating whether it is “necessary” to regulate EGUs. See the preamble to the proposed and final rule for the EPA’s interpretation of the term necessary and determinations that it remains necessary to regulate HAP emissions from EGUs. As in dicated therein, we maintain that the 2000 finding was reasonable at the time it was made based on the available information and that our new analyses of wherein we considered whether HAP emissions remaining after imposition are reasonably anticipated to p ose a hazard to public health and the environment far exceeds what is contemplated in CAA section 112(n)(1)(A). **Comment 2 2**  **:** 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 2 2**  **: 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, in which EPA evaluates whether additional HAP emissions control is necessary to p rotect public health with an ample margin of safety. We have based the final rule on the performance of the be st performing sources in accordance with the statute. **Comment 2 3**  **:** Commenter 18502 argues that Puerto Rico currentl y is in compliance with all ambient air quality standards and thus further reductions in HAP emissions from the proposed rule will have no ben efits to air quality on the island. **Response to Comment 2 3**  **:** 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 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 2 4**  **:** 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 $9,000 at a 7% discount rate. The commenter requests that the EPA review the information and revise accordingl y, and also suggests that the EPA use a single base ye ar (2006$ or 2007$) when tabulating benefits. **Response to Comm ent 2**  **4 :**  Any discrepancies in the proposal will be corrected in the final RIA. All costs and benefits are presented in 2007$ in the final RIA.638

**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, 184 87, 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 analy sis. 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: //yo semite.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 lo wer if lags were properl y 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 yi eld the b enefits 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 underes timate 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), neurops yc hological tests that are not subtests of IQ tests and are not highl y 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. ”639

The EPA acknowledges that MMAP S does not account for a time lag in ecosy stem 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 la g times on benefits. **Comment 3:** Commenter 17621 states that with respect to the “hy pothetical full scale IQ ” this relatively small incremental change in IQ (0.18 on a 100

-point I Q scale) associated with a 1 ppm Hg increase in hair cannot itself be measure d for an individual, but must be estimated for the total population (through a series of anal ytical 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 th e “ 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 relativel y) 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 b y methylmercury

exposure. The EPA anal ys is 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 analy ses be retained but de

- emphasized in the documentation underl ying 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 anal ys is 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 b y 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 can cer, heart disease, neurological damage, birth defects, asthma, and premature deaths. Commenter12798 states that the health of Americans and the economy will be greatly aided b y these new regulations. The commenter quotes a Harvard study that found Hg emis sions 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 emission s. 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 sh own 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, Age640

standardized cancer mortality ratios in areas heavily exposed to methyl mercury , 88Int . Arch. Occup
. Environ. Health. 6 79, 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 b ecause 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** : C ommenter 19506 questions whether the benefits associated with the rule will actually be achieved. This commenter notes that the Hg emissions within Indiana have decreased b y approximately 20% over th e 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 beli ef 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 quickl y following reductions in Hg deposition. However, the time lag between reduced Hg deposition and reduced Hg levels in fish can vary greatl y and is not accounted for in the RIA benefits anal ys is. **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. **Re sponse 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 anal ys is of the benefit to IQ in children. The SAB has supported the model used in the RIA anal ys is 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 b y Bellinger (2005). ” (U.S
. EPA
- SAB , 2011) The analysis in the RIA is not intended as the basis of the rule. Itis 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 string ent 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 n eurological effects, 2) many health effects are unquantified , 3) benefits of reduction of other HAP are unquantified and 4) effects on ecosy stems and wildlife are likewise unquantified . In addition, the co

- benefits of reducing PM exposure are quite substantial and outweigh the costs of the rule.641

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 mo st sensitive indicators were in the domains of language (Boston Naming), attention (continuous performance) and memory (California Verbal Learning Test), neurops ychological tests that are not subtests of I Q tests and are not highly correlated with global I Q. 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 state s that the EPA ’ s anal ys is 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 ecos ystems and that “ a portion of the deposition is unlikely to reach the water at all. ” **Response to Com ment 8:**  The EPA acknowledges that MMAPS does not account for a time lag in ecos ys tem response to reductions in Hg emissions. Ecosystems are highl y 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 con cern 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 th e 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 oth er 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 annuall y 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:** C ommenter 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.642

**Comment 11:** Several commenters quote data from recentl y 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 ofMethylmercury , 2000, available on the Web at: http://www.nap.edu/openbook.php ?record_id=9899&page=327 , 327).
 Comm enter 18421 quotes a 2006 study by Dr. Kathry

n Mahaffey estimating that approximately 410,000 infants are born in the U.S . each ye ar to mothers with blood Hg concentrations in excess of the EPA ’ s reference dose.
 Commenter 18421 quotes a recent study of wom en conducted in Durham, North Carolina that found 30% of the women participating in the study had at least 1 ug/Lof 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 w omen of Asian/Pacific Islander decent had blood Hg levels above 3.5 ug/L(see Miranda et al., Mercury L evels 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 neuro degenerative 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 dev elopmental 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; 4 0(8): 186

–215).
 Commenter 18432 quotes a recent study conducted in the City

of Chester and Borough of Eddystone , Penns ylvania located in close proximity to coal

- and oil

- fired EGUs . This study shows that asthma rates among children in these communities exc eed 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 ty picall y did not exhibit any s ymptoms 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.643

**Comment 12** : C ommenter 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 are in fact likel y to res ult 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. C ommenter 15002 notes that the EPA ’ s own anal ys is 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. C ommenters 15160 and 18932 state that the North Carolina Department of Health and Human Services estimates that at more than 11,000 children per ye ar 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. C ommenters 17409 and 18435 identify recent studies such as the 2005 study by Transande that estimated between 300,000 and 600,000 children each ye ar have cord bloo d 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 prenatall y exposed to unsafe levels of Hg in 2005, resulting in a 0.10 point l oss 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 earl y childhood exposure to methylmercury can lead to neurological deficits in children and that the economic consequences of such deficits can be substantial. **Comment 14** : C ommenter 15002 believes that the EPA underestimated the impact of Hg on IQ by restricting the anal ys is to populations who consume self

- ca ught fresh

- water fish and omitting Hg exposures from other freshwater and saltwater fish. This commenter also stated there is no evidence to support the hy

pothesis 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. We acknowledge the commenter’s belief that the anal ys is of Hg impacts and health benefits may

be conservative.644

**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 annuall y, experiencing onl y 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. Commenter1 9506 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 anal ys is. Commenter 17681 argues that the aggregated bene fit estimate of 0.00209 IQ points lost is below the level that can be measured b y 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 I Q 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 I Q loss for the most at risk children, which is well bel ow the EPA

- determined 1

- 2 point I Q 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 conduct ed 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 anal ys is. **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 be cause 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 com es 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 I Q ’ s that are much lower or higher than the mean. ” ( SAB Report available at: http://yo semite.epa.gov/ sab / sabproduct.nsf / ea5d9a9b55cc31 9285256cbd005a472e/ aaf67ae4dd19940985 2578cb006bcb04 ! OpenDocument) The anal ys is in the RIA is not intended as the basis of the rule. Itis 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 unquantified645

and 4) effects on ecos ys tems and wildlife are likewise unquantified . In addition the co

- bene fits 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 es timates 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 anal ys is of Hg effects on IQ in the benefits estimates for the RIA . The estimates were generated using data and models reviewed b y 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) **C omment 17:**  Commenter 17621 states that with respect to the “hy pothetical full scale IQ ” this relativel y 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 anal ytical 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 relativel y) 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 b y methylmercury exposure. The EPA analy sis of potential IQ loss from methylmercury e xposure 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 underl yi ng epidemiological studies and the exposure estimates, the level of precision is to 2 signific ant 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 underl ying 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 anal ys is 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 th e impact of reducing methylmercury in water bodies. ” (U.S. EPA

- SAB, 2011) The EPA is following the SAB recommendation b y deemphasizing the IQ analysis and placing that analysis in an appendix to the revised TSD.646

**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 b y an IQ test. **Response to Comment 18:** The commenter is confusing a measurement based on an IQ test and the response predicted b y the linear model the EPA used to calculate IQ decrements caused b y methylmercury

exposure. The EPA uses a linear response model to predict IQ loss due to methylmercury

e xposure 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 h ave at the tails of the distribution. The SAB has supported the model used in the RIA anal ys is 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 b y Bellinger (2005). ” (SAB Report available at: http://yosemite.epa.gov/sab/sabproduct.nsf/ea5d9a9b55cc319285 256cbd005a472e/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 methy mercury in contaminated fish to be a primary health concern and they

believe that fish and shellfish are the main sources of human methy mercury exposure. Commenter 18932 states that, as of 2008, all 50 states had issued some ty pe 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 b y 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 th at 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 sy stems. Commenter 18 932 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 their647

bodies overall. In a 1993 study , the North Carolina Department of Health and Human Services discovered that fishermen and their families were consuming fish f rom 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/Llevel for w omen 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 propose d 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. **Res ponse 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 agre es that this rule will reduce Hg levels in fish. The EPA agrees that, in some cases, Hg levels in fish can decrease quickl y 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 anal ys is. **Comment 21** : C ommenters 15002 and 17679 believe the EPA ’ s anal ys is underestimates the impact of Hg emissions because the anal ys is focuses only on populations who consume self

- caught fresh

- water fish. C ommenters 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). C ommenter 17620 states that the EPA ’ s anal ys is is of limited usefulness in assessing the health impacts of the proposed rules because it is based on self

caught freshwater fish rather than on commercially caught freshwater fish and saltwater fish that constitute th e vast majority of the fish consumption in the U.S
. **Response to Comment 21:** The EPA agrees that the anal ys is presented in the RIA is an underestimate of the benefits of reduced Hg exposure in part due to the exclusion of some fish species especiall y 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 anal ys is is flaw ed 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 b y an EPA
funded 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 disagr ees 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 th e 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 multiple648

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 measure s. **Comment 23** : Commenters 17751 and 17681 argue that an analy sis 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 anal ysis of the health concerns relate d 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 clearl y i ndicates that Hg emissions and impacts from sources other than those derived from EGUs greatl y 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 comment er 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 that will lead to reductions of Hg emissions from EGUs
. The National Scale Mercury Risk Assessment shows that changes in Hg emissions from 2005 to 2016 are in fact likely

to result in reductions in U.S
. EGU attributable fish

- tissue Hg concentr ations. 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 re duce 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 faci e 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 milli on 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 worl d ’ 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).649

**Response to Comm ent 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 L ong - Range Transport of Key Air Pollutants to and from the United States http://www.nap.edu/catalog/ 12743.htmlreport , explains that “ Hg is trul y 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 sy stems, soils, biota, and the cryosphere . Hence intercontinental transport is an important process that clearl y 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 rea sonable 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 acco unting “ 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 produc tion 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 the re are other routes of exposure, including self

- caught saltwater fish and commerciall y purchased fresh and saltwater fish, these exposures are not evaluated because 1) for self

caught saltwater fish, we are unable to estimate the reduction in fish tissue m ethylmercury 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 erro rs that grossl y 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 anal yz e 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 m ethylmercury in water bodies. The reason is that I Q 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), neurops ychological tests that are not subtests of IQ tests and are not highl y 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 m odel that relates the reduction in Hg deposition to reductions in fish tissue concentrations is inappropriate. According to SAB650

“ 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 ecos ys tems can become quickl y 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 contamin ated b y 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 t o 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 largel y 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 covalentl y 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 Wy

ngaarden 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/ sw guidance/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 and651

subsistence populations, such as Native Americans, Hispanics, and Location subsistence fishers. Several commenters (17409, 18421, 18932 ) state that African Americans, Native populations, L atino communities, Asian Americans (e.g., Vietnamese in the gulf are a), and other low income communities who fish recreationall y are more likel y 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. Co mmenter 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 th at 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

c aught, 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 subsist ence 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 likel y 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 incom e 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 anal ys is 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 c ommenter 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 sub sistence 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 tho se experienced b y the average U.S . population. However, this commenter believes that fish consumption is limited and occurs primaril y during recreational activities. Commenter 17732 notes that a 2004 U.S . Fish & Wildlife report concluded that the Navajo “ c an 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 bette r understand the true public health and environmental impacts.652

**Response to Comment 29:** The EPA agrees that the anal ys es 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**  : C ommenters 16122 and 17732 note that Hg contamination of streams, rivers, and lakes threaten the economy of states and tribes that rel y 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 a pproximately

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 o f 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 f ishing. 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**  **3 2**  : 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 3**  **2:** The EPA disagrees that the benefits of the MATS rule do not justify the costs. As the anal ys es 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 anal ys is 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 , many653

other impacts of Hg emissions were not quantified including impacts on ecosystems and wildlife; especiall y fish, birds (both fish and insect eating), and mammals. Other HAP controlled by the MATS rule were likewise not quantified due to data, res ource 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 b y a substantial margin, even when taking uncertainty into account. Consideration of PM 2.5 health co

- benefits expected as a result of direct PM 2.5 and SO 2 emission reductions is directed b y 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 ty

pically unrelated or secondary

to the statutory

purpose of the rulemaking (e.g., reduced refinery emissions due to more stringent fuel economy stan dards 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 b y EP A ’ s Guidelines for Preparation of Economic Analyses (p. 11

- 2, available at: http://yo semite.epa.gov/ ee/ epa / e ed.nsf /pages/Guidelines.html ):

“An economic anal ys is 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 directl y 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 th e 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 currentl y 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 analysi s 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 are654

provided to the extent possible, and our limite d 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 inherentl y too difficult to quantify or monetize given current data and methods. You should carry out a careful evaluation of non

- quantified b enefits 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 Anal ys es (p. 11

- 3, available at: http://yo semite.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 canno t 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 HAP emissions not regulated 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 reductio ns 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 EPA
HQ
- 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 effo rts 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 inve stigate source - receptor relationships for Hg deposition in eastern Ohio. The site overlooking the Ohio River655

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 directl y 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 b y the models that have been utilized in previous policy decision making. ”( Keeler et al, 2006) Similarly , wet deposition data collec ted 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 strongl y influenced b y 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 3 6**  : Commenter 18487 points out that reducing emissions of acid gases will benefit acid sensitive ecos ys tems and the fish and wildlife that depend on those ecos ys tems. **Response to Comment 3 6**  **:** 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 c omprehensive report on those effects including increased Hg methylation in acidified s ys tems. To the extent that acid gases contribute to acidification, the EPA agrees that those gases pose a risk for acidification of ecos ys tems. However, due to data and m ethodological limitations, the EPA was not able to quantify

those risks and benefits.656

**6M -**  **Im pacts 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 rea sonabl y 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 b y 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 th e 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 projec tions 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 IP M 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 do es 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 NO X control listed in the file, but it is equipped with low NO X 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 IP M modeling for the final rule has been updated to reflect these corrections. **Comment 3:** Commenter 19686 states that the rule ’ s technical anal ys is 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 anywh ere between one to thousands of acres. The smallest lands, because of their size, may be wholl y or partially657

located in areas that heavily influence airflow unlike surrounding jurisdiction s ( 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 accuratel y, the commenter recommends that the EPA re do its CMAQ anal ys is 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. Trib al lands located in urban areas are also largel y unrepresented since they possess few monitors to discern the presence and amount of pollutants covered b y 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 generall y 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 any thing published in literature and represents the most advanced modeling platform used for a national Hg deposition assessment.658

**6N -**  **Im pacts/Costs: Other/Miscellaneous**  **Commenters** : 15002, 15160, 17620, 17884, 17973, 19214 **Comment 1:** Commenter 15002 recommends the EPA implement a 5

- ye ar review cycle for Hg and other HAP , similar to what is mandated b y the CAA for the NAAQS. The commenter notes that emissions will plateau at current levels due to population increases balanced out by improved emission contro ls 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
- ye ar review schedule is mandated b y the CAA for the NAAQS, the schedule prescribed b y the CAA for review of emission standards for Hg and other HAP cal ls for a review every 8 years. See CAA section 112(d)(6). 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 SO 2 , 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 Co mment 2:**  The EPA agrees with the commenter ’ s assessment that the rule achieves important reductions in the emissions of several air pollutants without being undul y 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 reasonabl y s afe 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 o f 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 rel y 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 re gulation are unlikely to cause large changes in any single aspect of household spending, such as health care. These anal ys es also fail to consider that household income may increase if individuals are able to work (or work more)659

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 o ther major source categories of HAP have implemented controls under MACT requirements already. The commenter believes that a well

controlled EGU equipped with a baghouse, SO 2 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 ty

pes 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 ty picall y supported with state and tribal air grant s. **Comment 8:** Commenter 16849 states that even under revised averaging periods, TRONA and DSI is not a viable option, as is incorrectly stated b y the EPA ( “ IPM Parsed Results

- Policy Case, ” Unplanned DSIInstallations by

2015 includes Asbury : 2076_B_1). **Response to Comment 8:** The EPA believes that DSIhas 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 b y reducing the disposable income people will have for the necessities of life. Because the purpose of the CAA i s 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

interpretati on 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 E PA 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 as sertion which relies on a theory that the cost of a rule will result in lost660

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. ” ) Th e 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 rel y o n 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 b y the pass

- through costs of the regulation are unlikel y to cause large changes in any single aspect of household spending, such as health care. These analy ses 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 health

health trade

- offs in EPA anal ys es of regulatory effects.661 **CHAPTER 7**  **: STAT**  **UTORY 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, 1780 6, 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 c ommenters (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 th e 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 anal ys is. Commenter 17715 suggests the proposed rule does not take into account har monization 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 ye ars. 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 PM 2.5 , ozone, and 1

- hour SO 2 ; 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

- effectivel y 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 anal ys is failed to take into account the impact of each of the CSAPR and the propose d 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 aff ecting 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 MACT662

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 r

ules 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 entirel y. 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 anal ys is to accompany the rule for the following reasons: 1) the various EO requirements that the Agency must compl y 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 anal ys is. A cumul ative impact anal ys is lumps several regulations together and can potentiall y mask a high

- cost/low benefit regulation among other rules that may have large net benefits. By anal yz ing 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/summary report.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.663

The direct benefits of the 1990 Clean Air Act Amendments and associated programs significantl y 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 b y which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikel y 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 PM 2.5 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 anal ytical 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 hy

pothesize, but do not predict, the control strategies that states may choose to enact when implem enting 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 PM 2.5 and ozone NAAQS RIA , but these effects are only counted once when considering cumulativ e 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, thereb y 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 anal ys is of government administrative costs or savings when those effects are expected to be significant. The EPA ’ s anal ys is of costs doe s 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 bel ieve 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 b y 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 acti on. 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 maintain that our action is consistent with the D.C . Circuit Court ’ s decision.664

**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 Transm ission Organizations (RTOs). **Response to Comment 4:** The EPA is separatel y 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. C ommenter 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

- ye ar extension to comply wi th 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 b y means of alternative regulatory strategies. **Response to Comment 6:** Although the propose d rule did not include a full quantitative analysis of a more and less stringent regulatory alternative, a quantitative anal ys is 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 c ontrol systems, including DLPS technology
. **Response to Comment 7:** The commenter is incorrect

– the EPA does not endorse any specific typ e of pollution control technology , nor does it mandate or prohibit technologies . The MACT standard is an emission

- based standard that is established by considering the maximum emission reductions currently achieved b y existing EGUs . 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 innovation665

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 accuratel y 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 accuratel y 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 analy sis. 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 anal ys es . 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 guidanc e as to use of this discretion. The commenter believes the projected cost for the rule is significant while providing onl y 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 SO 2 and NO X , resulting in lower ambient PM 2.5 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 PM 2.5 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 i s important to note that there are key

differences in the design and anal ytical 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 o n an array of emission control strategies for different sources. In short, NAAQS RIAs hy

pothesize, 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 cost s 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 PM 2.5 and ozone NAAQS RIA , but these effects are onl y 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 minimum, the commenter suggest the EPA must explain how its actions are consistent ·with the ‘‘‘ Gen eral Principles ” and “ Public Participation ” directives of EO 13563.666

**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 arbitraril y or capriciously with regard to these obligations. The agency is obligated to finalize the MATS by December 16, 2011, consistent with a consent decree
. This date reflects a 30

- day

extension the EPA obtained from the original November 16, 2011 deadline. The proposed rule was signed o n 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 m eets 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 o r additional costs that will be incurred b y 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 floor standard. The MACT floor standard is a technology

- based standard based on the performance of existing sources in the regulated source category . It provides th e 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 sources each category or subcategory

with 30 or more sources and the best performing 5 sources for each category or subcategory

with less than 30 sources
. Based on the requirements of the CAA , the EPA can only consider economic, environmental, and 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 low rank virgin coa l 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 gro wth. 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, rel ying on sound objective science, req

uiring 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 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.667

**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 requirem ents. The EPA believes the agency ’ s interpretation s of section 112(n)(1) and 112(d) constitute reasonable interpretation s of the statute . While we agree that the cited executive orders direct the EPA to maximize benefits and minimize costs to regulated ind ustries, we believe that we have done so within the constraints imposed by the CAA.668

**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.669

**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, 17 689, 17712, 17805, 17817, 17868, 17885, 17911, 18032, 19094, 19121, 8443 **1. General. Comment 1:**  C ommenters 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 propos als, 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. Th e 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 in stall controls. CAA section 112(i)(3)(B). If the situation described b y 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. **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. C ommenters ref erence 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 believ es the EPA ’ s formal SBAR Panel notification and subsequent information provided b y the EPA to the panel did not include information on the potential impacts of the rule as required b y 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 SB AR Panel through the abbreviate d 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 day s to prepare written comments on an incredibl y complex topic. C ommenters note that the lack o f 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 an d raw data upon which the EPA would eventually

make discretionary

judgments. C ommenters do not believe that the EPA ’ s670

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 specificall y that the EPA did not respond regarding the 3

- year compliance deadline and b y 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 b y 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 elec tricity 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 SB REFA , 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 s mall 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 m aterial the covered agency has prepar ed in connection with the RFA, the law does not prescribe the materials to be reviewed. The EPA ’ s policy , as reflected in its RFA guidance, is to provide671

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 pre

panel 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 b y 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

- ye ar 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 deter mined 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 b y 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

- ye ar extension. **Comment 13:** Commenters 17868 and 18032 believe the EPA did not adequately consider the di sproportionately

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 reall y considering the impacts on small municipal units, as public powers is critical to communities, jobs, economic viability

and electric reliability
. Commenter 17868 believes that the EPA has not full y recognized the number of small entities that are impacted b y the rule and underestimated the impacts of the proposed rule on smaller utilities despite the SER panel.672

**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 primaril y 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 anal ys es 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 1 3**  **- 15:**  The EPA disagrees with the commenters ’ belief that the impacts on smaller generating units were not adequatel y considere d 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 o f the final action. Specificall y, 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 anal ys is 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 s tate, 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 E PA 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 note s that the EPA has addressed such concerns previousl y, citing the RIA for the 1997 8

- hour ozone standard. The commenter also suggests smaller utility s ys tems generall y have less capital to invest in pollution control than larger, investor

- owned sy stems, du e 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. **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, w e believe that673

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 1 7:**  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. S orbent 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 sufficientl y 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 E PA seek to revise the court

- agreed deadlines to which this rulemaking is subject, re

- convene the SB AR 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 o f 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 anal ysis 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 anal yz e 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 anal yz e this option or to more clearl y state its policy reasons for excluding serious consideration of a separate standard for area sources. 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 any674

decision s 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, especiall y 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 re commendations made by the SER participants were ignored and not discussed in the rulemaking. Specificall y, 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 RI CE 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 1 8**  **- 21:**  The EPA disagrees with one commenter ’ s (17608) assertion that the agency has not compl ied 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 l ist 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. Specificall y, 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 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 public675

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 Consent Decree initially required the EPA to sign the final MATS rule b y November 16, 2011, but the EPA negotiated a 30

- day extension of the deadline with the plaintiffs in the litigation consistent with the requirements of the modification provision of the Consent Decree. If plaintiffs in the American Nurses litigation objected to an additional extension request, which we believe they woul d, 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 rul e b y 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 was able to complete the rule by December 16, 2011; acc ordingl y, the agency had no basis for seeking a further extension of time.676

**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 associat ed with enforceable duties falling on states. State administrative costs are not expressly included in UMRA as the ty pe of costs to be included in anal yz ing 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 b y the compliance costs of the propose d 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 publi c 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 Pay

ments 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 anal ys is of the cos t 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 Pay ment 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 pay ments; (4) The cost to the city budget of potential downgrade to municipal bond ratings caused b y 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 econ omic 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 propos ed 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 tribal677

governments, and the private sector. This anal ys is 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 specificall y 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 anal ys is, a “ small ” government jurisdiction is defined as the governm ent 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 anal ys is accounts not only for the additional costs these entities face resulting from compliance with the proposal, but also the impac t of higher electricity prices that government entities should face, and does account for projected earl y retirements due to the proposal among affected units owned b y 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 anal ys is 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 cost s 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 b y UMRA. The commenters discuss these shortcomings with respect to the EPA meeting with the “ Big Ten ” on October 7, 2010. Specificall y, the commenters submit that the “ Big 10 ” organizations are unlikel y to have stakeholders that will be impacted b y the MACT rule, and the commenters are not aware that any of the state/loc al governments that the EPA estimates will be impacted b y 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 e arly 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 unlikel y to have stakeholders potentiall y impacted b y the MACT rule. As examples, The National Association of Towns and Townships represent smaller communities, towns and townships, and other suburban and rural678

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 potentiall y 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

- ye ar 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

- ye ar perio d 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). **Comment 6:** Commenter 17911 states the EPA failed to fully evaluate the unintended consequences of this rule on local economies, especiall y 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 anal ys es in response to the statutory and executive orders requirements that it must follow for economically significant rules such as this one. The agency ’ s anal ys is included estimates of the increase in retail electricity price both nationally

and regionally , and this anal ysis shows no increases in retail electricity price above 7% in 2015, and lower price increases thereafter. Such an anal ys is 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 anal ys is that is presented in the RIA for the proposed and final rules. The agency presented its anal ys is 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 anal ys is 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.679

**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 (FSI S) containing a number of elements, including a statement of the extent to which the concerns of state and l ocal 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 Comme nt 1:**  As required b y 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 co sts 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. Specificall y, the commenter references section 3(b) of EO 13132, which requires agen cies to consult with state and local officials to determine whether federal objectives can be attained b y other means where there are significant uncertainties as to whether national action is authorized or appropriate. **Response to Comment 2:** Commenter imp lies 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 EPA determine d that it was appropriate and necessary to regulate EGUs in December 2000 and added such units to the section 112(c) list. Sources listed must be regulated pursuant to section 112(d). See section 112(c)(2). **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 subst antial and will impact ratepayers dramatically , potentiall y 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 wi th 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 con sulting 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, answer680

questions and solicit input from state/local governments. As required b y the EO, a FSI S 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 compl ying with the rule will be substantial and disproportionatel y 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 anal ys es 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 betw een 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 (SEE

Action). **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.681

**7F -**  **Executive Order 13175, Consultation and Coordination with Indian Tribal Governments Commenters**  : 12462, 15182, 16122, 17674, 17732, 17733, 17846, 18017, 19686 **Comment 1:** Several c ommenters (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 People s, their lands, waters and natural resources. Commenter 16122 also notes that the EPA has a responsibility to not onl y 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 disproportionall y 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 regularl y 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 full y 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 fro m 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 full y and adequatel y protects its environmental interests and its tribal resources. Commenters note that it is clear that Hg deposition from EGUs have significantly impacted culturall y- 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 anal ys is that full y assesses the rule ’ s impacts on Tribal air quality and health, as well as cultural and subsistence practices.682

**Comment 5:** Commenter 18540 believes that the EPA has a trust responsibility to ensure that the C ommunity ’ s water rights, and other guarantees and benefits provided in the Arizona Water Settlements Act (AWSA) are preserved, and that the trust responsibility prohibit s 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 b y the AWSA. The commenter believes th at 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 negativel y 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 consultatio n 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 federall y recognized tribes
. The EPA agree s 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 monthl y National Tribal Air Association calls, at the National Tribal Forum , and a webinar targeting tribal environmental professionals on the content of th e 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. Because of concerns raised b y s everal tribes, and in order to help us better understand their concerns, w e also participated in a face

- to - face meeting with tribes in Arizona who were concerned about the potential impact o f this rule on their income and water rights. Following th at meeting, we held an additional technical meeting on how IPM is 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 statement s that the EPA has not un dertaken 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 w as 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 believe683

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 currentl y regulated un der 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 affe cted 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 re spect 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 mos t current information related to the power sector. The inclusion of other regulatory

actions (including federal, state, and local actions) in the modeling reflects the level of controls that are likel y to be in place in response to other requirements apart from MATS and provides meaningful projections of how the power sector will respond to the cumulative regulatory requirements for air emissions. It is not intended to reflect actual compliance decisions, since those will be made individually by the affecte d 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 anal ys es about possible actions by NGS, including clo sure, 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

comm issions and other authorities, including tribe s, will need to develop and implement compliance plans in order to address harmful emissions. W ith regard to one c ommenter ’ 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 c ommenter ’ s recommendation that additional studies and anal ys es be conducted, we agree that additional analysis would be helpful to better understand the impacts of air pollution, particularl y 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 fall s 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 fall s 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 h ealth and well

- being of the natural environment and the people of the tribal nation are of utmost importance to the commenter. A s 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 anal yz e 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 reasonable684

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 severe reductions in the revenue received from the power plants and their supplying mines. The commenter asks that the EPA anal yz e 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 n ation 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

- ye ar period for sources to come into compliance as allowed b y section 112 of the CAA. Sources may also seek a 1

- ye ar 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). **Comment 8:** Commenter 17674 expresses concern wi th 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 addre ss 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 con cerns raised b y 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. Fol lowing that meeting, we held an additional technical meeting on how IPM is used in the RIA and provided one

on - 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 b y the affected industry

based on what makes most sense using existing technologies or other, more cost

- effective strategies. Thus th e EPA ’ s IPM anal ys is 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. Wewould point out that changes in the final rule are significant and will reduce costs, increase flexibility and alleviate industry concern s about achievability of standards
. **Comment 9:** Commenter 17674 discusses numerous c onsiderations 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 fulfill685

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. **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 s ection 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 N GS
. Pursuant to CAA section 112(d)(1), the EPA may subcategorize sources based on differences in class, ty pe, or size. Inthe preamble to the proposed rule, the EPA further explains that any basis for subcategorizing (e.g. class) must be related to an eff ect on emissions, rather than some difference which does not affect emissions performance. The EPA does not agree that a subcategory based on location on tribal lands is consistent with the statutory authority to subcategorize , and the commenter does not explain why emissions would be different for EGUs located on tribal lands
. Absent that showing, it would not be appropriate to subcategorize units even if we believed such a subcategory was consistent with the statute. 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 technologi es. 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 th e 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 earl y 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 s tringent 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 likel y to experience lower complianc e 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. **Comment 1 1**  **:** 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 a nd 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 sure686

that the individual and collective rights of Tribes are protected and advanced in the EPA ’ s efforts to 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 a nd other EPA actions with potential Tribal implications. **Response to Comment 1 1**  **:** 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 currentl y 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 en couraged 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 Indi an tribes. **Comment 1 2**  : Commenters 17846 and 19686 state that the Tribe and its members are greatl y 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 1 2**  **:** 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 th at 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 1 3**  : 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. Finall y, 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 th e statute.687

**Comment 1 4**  **:** Commenter 17846 states that the Tribe and its members are greatl y 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 1 4**  : The EPA shares the tribes concerns about Hg and its potential impact on tribes. We believe this rule will prevent local hotspots from occurring.688

**7G -**  **Executive Order 13045, Protection of Children From Environmental Health Risks and Safety**  **Risks Commenters**  : 10822, 12462, 16121 **Comment 1:** Commenter 10822 provides a cop y of a journal article entitled “ Pregnancy L oss and Maternal Methemoglobin Lev els: 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 c omplications 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 damag e. The commenter states in utero exposure to Hg, via contaminated fish eaten b y 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 adequatel y protected from Hg exposure in the environment. The commenter briefl y 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 comm enters and appreciates their input regarding health effects of Hg and other coal combustion emissions. Inaddition, the EPA thanks commenter 16121 for their general support of the proposal.689

**7H**

**– Executive Order 13211, Actions Concerning Regulations That S**  **ignificantly 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 anal ys is of the rule is reasonable, and does not understate impacts as the commenter suggests.690

**7I -**  **National Technology Transfer and Advancement Act** No comm ents 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.691

**7J -**  **E xecutive 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 impa cts 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 whi le the EPA developed these maps to show the potential impacts from fish consumption in nearb y 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 disproportionatel y 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 Af

rican 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 c ommunity 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 d ue 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 b y Hg. For these reasons, the EPA expects that minority, low

income 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 c oncentrations 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 substa ntial 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 anal ytical 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 di sagrees that there is a statistically

discernible downward trend in the NHANES data on blood Hg. The EPA is unaware that a formal statistical anal ys is 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 for692

women at child

- bearing age, could “not support the conclusion that there was a general downward trend in blood mercury

concentrations over the 6

- ye ar study period. ” However, the same pu blication noted that “there was a decline in the upper percentiles reflecting the most highl y 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 statisticall y 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 anal ys is of the data. The EPA remains concerned that substantial numbers of women of childbe aring age in the U.S . may have blood Hg levels that are equivalent to exposures at or above the RfD
. Mean and 95 th 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 95 th percentile. Modeled data from Tran et al., 2004 provided estimates showing hi gh blood Hg levels at the 99 th percentile for females of child

- bearing age (i.e., 24.41 ug/Lat the 99 th 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/Lin 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 eleme nts 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 NHANE S : identifying Asian, Pacific Islander, Native American, and multiracial groups. ” Environ Health Perspect 114(2): 173

- 175.) **Comment 4:** Several c ommenters (17697, 17710, 18433) note that Guam is designated as a “ distressed nonmetropolitan middle

- income ” area due to both high poverty and unemploy

ment 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 significantl y increased electricity rates that could cause economic hardship on its customers, such as the unemployed, underemployed and those with limited or fi xed incomes. **Response to Comment 4:** The EPA dis agrees 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 ye ar and would provide particular health benefits for693

children, preventing 120,000 cases of childhood asthma sy mptoms and about 11,000 fewer cases of acute bronchitis among children each ye ar. The EPA estimates that for every dollar spent to reduce pollution from power plants, the American public and American businesses will se e up to $13 in health and economic benefits. Itis 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 liquid oil

- fired 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 anal ys is 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. 200 4:

“ 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 th at 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 reje cted 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 indirectl y 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 wil l 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 a694

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 po wer plants. The commenter uses these statistics to show pollution from power plants is an issue of racial disparity as African Americans are most likel y to be exposed to the toxins coming from power plants and the impact is apparent through the higher rate s 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, generall y have worse health than whites and that many minority and low income communities are overburdened b y 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 so urces of HAP are located together, such as industrial areas, would be beneficial for addressing EJ concerns. **Response to Comment 7:** The EPA generall y agrees with the value of assessing cumulative impacts in such areas, and that additional data would be use ful 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 n ot 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 trad eoffs of regulatory action to control air pollution. Claims about health

- health tradeoffs rel y on questionable applications of cross

- sectional data and ignore key factors that may

influence changes in population health risks. Additionally , marginal decreas es 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 indivi duals 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, the695

EPA ’ s science and economic peer review panels have consistentl y advised against incorporating alleged health

- health tradeoffs in the EPA anal ys es 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, SO 2 , 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% o n average nationall y by

2015, with some consumers in certain regions seeing increases of less than 10% while other consumers in different regions will see increases of onl y 1%. These increases in electric rates may not be minimal in some areas of the U.S., but they should be s een 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, elderl y and minority populations. The commenter cites an economic anal ys is 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 cop y 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 b y 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 recentl y 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 significantl y 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 anal ys is suggest it is v ery unlikel y 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 p rograms 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 day s and lower medical costs more than offset the economy

- wide cost of investing in air pollution control.696

**Comment 10:** Commenter 17713 suggests that high energy prices from the rule will lead to businesses cutting costs b y 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 anal ys is shows that high energy

prices will not result from this rule, and increases are expected to be 3.7% o n average nationally by 2015
. The EPA estimates that the overall impact on short

- term employ ment will be an increase on net of 46 ,000 jobs associated with the rule, with an increase in long

- term jobs annuall y of 9,000 (with jobs being measured as job

- ye ars, or 1 year of employ ment for one full

- time worker). The range of employ

ment impacts in the long

- term is a loss of 1 5 ,000 to a gain of 3 0 ,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 b y minority population s 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% b y 2015, an d 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 unlikel y to significantl y affect the prices of basic goods, and are modest when considering th e substantial benefits from reductions of HAP and other pollutant reductions that this rule is expected to achieve. These benefits will be enjo yed 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 unemplo ym ent, 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, unemploy

ment, and prices for industries affected b y any predicted increases in energy prices in the RIA for this rule. As stated above, the EPA expects that the impacts of increased ele ctricity prices would be small and would be more than offset b y 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. Comm**  **ent 13:** Commenter 17766 believes the current rule as written, would significantl y 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.697

**7K -**  **Statutory and Executive Orders: Other Commenters**  : 15182, 16705, 17295, 17400, 17697, 17710, 17824, 18038, 18433, 18433, 18575, 19042, 19213, 19580 **Comment 1:** Commenter 15 182 requests that the EPA further regulate emissions from power plants to meet the goal of achieving zero emissions of nine critical pollutants (including Hg) b y 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 B inational Program to Restore and Protect Lake Superior, it is a critical step toward significantl y reducing overall emissions of these pollutants in support of that goal by the ye ar 2020. **Comment 2:** Commenter 17751 believes the proposed rule does not adequ ately 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 s tandard 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 PM 2.5 health benefits resulting from primary PM and SO 2 emission reductions and are, thus, an important category to quantify
. Consideration of ancillary benefits in benefit

- cost anal ysis is directed b y 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 unde r 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 reducti ons 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 anal ys es completed as part of compliance with the applicable statutory and executive order requirements. The results of these anal ys es 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 this698

rule. In adopting a final rule establishing national emission standards, the EPA is not required to conduct individual plant

- specific anal ys es 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 rec ommends the EPA more closel y follow the existing requirements for promulgating regulations and actuall y conduct detailed anal ys is prior to rulemaking. This anal ys is 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 anal ys is to determine the least costly , most cost - effective, or least burdensome alternative that achieves the objective of the rule ; and PRA analy sis 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 compl eted economic impact anal ys es for this rule that examined the impacts not only to the electric power sector but to sectors outside of the power sector. These anal ys es 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 anal ys es 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, rep orts, scorecards, and associated documents that assert implementation of various environmental regulations will reduce costs to the federal government and industry without any

supporting analy

tical regulatory documentation. The commenter notes several sust ainability 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 b y 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 th e 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 protec ted species have been documented with high levels of Hg, and the livelihood and reproductive success of these creatures can be affected b y 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.699

**Response to Comment 7:** The EPA generall y agrees that such species are threatened b y 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 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. 2 004).700 **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, 1780 5, 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 def initions for consistency

and clarity
. **1. Definition of n**  **atural g**  **as .**  **Comment 1:** Multiple c ommenters ( 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 I SO 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 wi ll be subject to the same standards as coal

- fired boilers despite the fact they burn substitute natural gas ( SNG), which is the same chemicall y as natural gas. Should such IG CC 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 post

combustion 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 quarterl y em issions 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 temp erature 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 b y volume or have a gross calorific value betwe en 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 p rocess which might result in highly variable sulfur content or heating value.701

**2. Definition of EGU**  **. Comment 2:**  Several c ommenters ( 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 b y 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 t aking 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 onl y 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 combu stion 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 cap acity 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 onl y 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 commente r 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 ye ars or for more than 15.0 % of the annual heat input during any one of those calendar ye ars to be considered a fossil fuel

- fired EGU but indicates that the provision for combusting more th an “ 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 the702

applicability

threshold in all Sections of the rule for consistency and clarity
. **Comment 7:** Commenter 17386 st ates 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 sy stem 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 C FR 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

thresho ld 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. **Co mment 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. Conversel y, the EIA listings also identif

y 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 increa se 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 the703

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

- ye ar 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 help s 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 f unction historically

has been to provide steam to an industrial process (paper mill), the Hibbard Renewable Energy Center boilers are more properl y 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 primaril y 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/gen erators 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 re quirements. 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 strongl y 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 definitio n 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 clearl y be contrary

to the intent of the CAA , and also clearl y 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 a s an EGU if the unit otherwise meets the CAA EGU definition. Further, Commenter 17733 strongl y disagrees with the EPA ’ s interpretation of the CAA section704

112(a)(8) definition “that a non - cogeneration unit must both have a combustion unit of more than 25 MW e and supply

more than 25MWe to any utility power distribution sy stem 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 indi cate 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 especiall y 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 thereb y avoid having to implement m ore 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 sy stem). By appl ying this standard, the EPA can ensure that units that do not meet the cogeneration efficiency requirements are appropriatel y treated like any other fossil fuel

- fired unit. This will allow the EP A 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 properl y to appl y to EGUs that meet the definition of EGU in CAA section 112(a)(8). The affe cted 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 relativel y small units. **Comment 14:** Commenter 17775 supports the EPA ’ s choice of dates f or 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 clearl y 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 inter pret 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 st ated 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 b y the combustion unit) as opposed to MWe which is the electric power generated b y the705

generator. The E PA 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 with 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 non

cogeneration 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 re quired 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 meg awatts electrical output to any utility power distribution sy stem 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 clarificati on 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 cogene ration 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 Cross

State 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 1773 3 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 fo ssil 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 ye ars or for more than 15.0 % of706

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 1 9**  **:** 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 1**  **6 -**  **19 :**  As noted in the preamble to the final rule , 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 2 0**  **:** 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 elec tricity

and the removal of all coal handling equipment, coal storage areas. **Comment 2 1**  **:** 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 “ fo ssil fuel

- fired” EGUs. **Comment 2 2**  **:** Commenter 18023 requests that the EPA update the definition of “ fossil fuel

- fired” to adequatel y account for fuel switching as a potential compliance strategy
. **Response to Comments 2**  **0 -**  **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 s ys tems 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 any three 3 calendar years or for more than 15.0 % of the annual heat input during any one calendar ye ars a fter the applicable compliance date . The EPA believes the definition provides flexibility for sources while simultaneously

preventing sources from improperl y avoiding regulation. EGUs that want to use fuel switching as a compliance strategy should include in their Title V permit provisions that preclude being coal

- or oil

- fired EGUs. **Comment 2 3**  **:** Commenters 18023 and 17775 state that the “ look

- back” period may potentiall y 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 define7 07

an affected unit b y whether it actuall y has heat input exceeding the stated thresholds. A unit that, beginning on the effectiv e 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 2 4**  **:** Commenter 17775 recommends that the EPA should revise the definition to change the “ look

- back ” perio d to begin 3 year s 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 outcom e 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 year s and remove all capability to burn coal or oil in order be exempt from the EGU MACT rule. Alternativel y, the unit could convert to biomass or natural gas b y 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
- ye ar 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
- ye ar average for the ye ars it was burning natural gas. **Response to Comments 23**  **and 24**  **:** As noted preamble to the final rule , 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 combus tion 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 alternatel y 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 ye ars. ” **Comment 26**  **:** Commenter18024 submits that the EGU MACT Rule should exclude the fuel input associated with compl ying 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 ye ar period to meet state reliability requirements shall be excluded from the heat input calculation. ” Alternativel y, 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
- ye ar rolling average). Based on historical operation, the commenter believes that 30 % oil firing at a708

facility would be sufficient to provide needed reliability in conformance with the State reliability rules. **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 u sed 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 “ oil

fired 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:** A s stated in the preamble to the final rule , the EPA is establishing a limited

- use liquid oil

- fired EGU subcategory and sources in the subcategory will be required to comply with work practice standards. See the preamble for specific responses to the comments. **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 clearl y 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 differentl y if read separate from the preamble. The comment er recommends that the final rule clearl y 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 in the preamble to the final rule , 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 t o 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 “ c oal

- fired EGU. ” **Comment 3 0**  **:** 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 3 1**  **:** 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.,709

No. 2/ No. 6), Commenter 17881 believes that fuel ty pe 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 ty

pes, and the onus is on the facility to demonstrate compliance. **Response to Comments 3**  **0 -**  **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 solel y on fuel heat content design criteria. Alternatively , the EPA should provide a definition of height

- to - depth 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 3**  **4:** Commenter 17914 states that it is the fuel properties that impact the potential H g 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 direc tly 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 respectfull y 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

actuall y 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 def inition 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 3**  **3 -**  **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 adequatel y define the subcategory without precluding fuel blending. 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 3 6**  **:** Multiple c ommenters ( 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 contains710

additional qualif

ying language that requires material to exhibit “ ash content greater than 50 % (b y 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 c ombusted 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 res trictions 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 facilitie s, 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 e ither coal refuse or coal would be classified, and whether it would therefore effectivel y avoiding regulation under the proposed rule altogether. The commenters further state that the heating value and ash content within the proposed definition of “ coal re fuse ” 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 Quali fying 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 refu se 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 3**  **6 -**  **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

ste am 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 b y 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 pursu ant the CAA section 129 (e.g., the final CI SWIrule); 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 sol id waste so all units that meet the definition of EGU and combust coal refuse are subject to this final rule. **9. Definition of f** 

**ossil fuel .**  **Comment 4 0**  **:** Commenter 18427 requests that the EPA revise the definition of “ fossil fuel ” in the proposed Utility

MACT as follows:711

“ 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 ” meaningfull y differentl y under the two relevant regulatory programs, both of which appl y 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 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 wo uld 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 o f 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 4**  **0 :**  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 differ ent regulatory actions, but we have determined that by products 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 b yproduct 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 by product 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
. The EPA believes that the definitions are sufficiently clear that onl y 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, clearl y not derived from “ foss il fuel ” and, thus, not covered under the final rule. “ Gaseous fuel ” in the definition of “ fossil fuel ” is clearl y linked to fossil fuels through the “ derived from ” phrase. The EPA does not believe that there is any confusion in the definition.712

**10. Definit ions of**  **m iscellaneous**  **t erms**  **. Comment 4**  **1 :**  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) lim it as a surrogate for non

Hg metal HAP instead of total PM (TPM). However, if a PM operating limit is used, the inconsistency between sections should be reviewed and corrected. **Response to Comment 4 1**  **:** The comment is moot because rule now allows compliance with filterable, not total, particulate matter (PM). **Comment 4 2**  **:** 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 lo west 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 flexibi lity 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 4 2**  **:** 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 p roposed 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 PM 2.5 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 revi se the definition of an operating day to be consistent with the NSPS. Specificall y, the commenter suggests that the definition of an operating day ’ s worth of data in section 5.2. 1, Sorbent Trap Monitoring S ys tems, should include no less than 18 hours of v alid 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 emi ssions control device operation, needs to occur during each period of unit operation,713

regardless of the duration. The rule maintains requirements to operate the monitoring s ys tem 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 4**  **5:** 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 3 0
- day period. **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 30 h 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 emissio n limits. ” **Response to Comment 46**  **:** This comment is moot because rule no longer requires monitoring of the sorbent injection rate. **Comment 47**  **:** Commenter s 17801 and 17821 recommend that the EPA modify the proposed definition (p. 25123) of gross output as fol lows:

“ 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 onl y el ectricity **(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 I SO 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 ste am generated and, for an714

IGCC electric utility

steam generating unit, the work performed by the stationary combustion turbines. For a unit generating onl y el ectricity, the gross useful work performed is the gross electrical output from the unit ’ s turbine/g enerator 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 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). **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 (s ynthetic 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 sy ngas 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 (s ynthetic 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, specificall y agreeing that receiving fuel from different suppliers does not constitute a change in fuel ty pe. **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 5 0**  **:** 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 notif ication of exceedances should be reported in semiannual compliance reports rather than the current proposed notification schedule. **Response to Comment 5 0**  **:** Even though the a gency 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 b y 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 st andard; or (ii) Fails to meet any term or condition that is adopted to implement an applicable715

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 alway s 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 5 1**  **:** 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. ” Inorder to avoid the 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 boil er need not be a separate add

- on air pollution control sy stem located downstream of the steam generating unit. **Response to Comment 5 1**  **:** 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. ” ) clearl y i ndicate 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 NO X 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 NO X limits throughout the normal range of operation and suggests that manufacturers ’ recommendations, if available, could be of considerable assistance in deve loping 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 NO X emission limits with these optimization efforts. Rather than drive tuning toward “minimal NO X ” or “minimal CO ” thresholds, we have developed language requiring tuning to conform with “best combustion engineering practice ” for each burner ty pe affected. We expect owners or operators of EGUs to maintain the balance of optimal combustion with NO X control and use sound combustion engineering practice to maintain that balance. In the final rule we have also added incentive s 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 are716

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 E PA 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 112.717

**8B -**  **Rule: Definitions (new) Commenters**  : 17655, 17696, 17711, 17718, 17721, 17725, 17755 , 17760, 17800, 17808, 17878, 17881, 18025 **Comment 1:** Several c ommenters ( 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 onl y two days (one on oil, one on gas) could be subject to the proposed rule, and a unit that combust s the same quantity of oil as the first unit but operates for multiple day s 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 ty picall y 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 uni t 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 b y 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 ty pically 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 th e final rule record
. **Comment 2:** Commenters 17808 and 18025 request that the EPA adopt a definition for a limited

- use oil

- fired EGU , which i s 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 year s (and not more than 20.0 % in each of those 3 year s). The co mmenters 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 dual

fired 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 f or 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

- fired718

heat input for all EGUs within the site averaging plan as follows:

“ For purposes of site av eraging, 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 ye ars prior to the effective date of the regulations or more than 15.0 % for any single ye ar within the three

- ye ar 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. **R esponse 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, CO 2 , or O 2 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 App endix A explicitly states that the certified flow rate, diluent gas, and moisture monitoring s ys tems that are used to convert Hg concentrations to units of the standard must be installed, certified, operated, maintained, and quality

assured according to 40 CFR Part 75. This is reinforced b y §§63.10010(b) through (d). **Comment 5:** Commenter 17715 recommends that the EPA use the part 72 definitions for CO 2 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 a gency 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 b elieves 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 b y 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 of719

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 sy stems 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 als o been shown to be effectivel y 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 SO 2 as well as nearl y complete control of emitted Hg. A dual liquid

-powder sorbent ( “ DLPS ” ) system consists of adding an aqueous solution of a halogen, especiall y a bromine compound, onto the coal upstream o f 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 h igh 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 fl y 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

-pow der sorbent ( “ DLPS ” ) s ys tem for controlling SO 2 , 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 sy stem. ”
 (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 s ys tems, 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 establ ished 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 s crubbers, DSI s ystems, and DLPS sy stems. ”720

 (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 re quirements (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). ”
 (fol lowing 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 b y 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) s ys tem, or dual liquid

-powder sorbent (DLPS) sy stem, 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 C omment 7:**  The a gency 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 onl y include times when the unit is producing electricity, or if operating includes when the boiler fans are being op erated ( 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 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 Sy stem ( 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 op erating load may vary widel y. **Response to Comments 9 -**  **10:** The a gency 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
.721

**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 a gency 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 b y 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 a gency 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.722

**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 th e 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 ty pes as most all facilities will be ≥ 8,300 Btu/lb, then by unit ty pes under each fuel se ction, 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 ref erence 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 a gency reviewed the concerns of this commenter, as well as other commenters, and the rule tables have b een 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 clearl y 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. **Comm ent 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 o f the preamble and the rule accordingl y. 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. I f 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:**723

**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 SO 2 CEMs option for acid gas compliance in new and reconstructed IG CC units, adjusting the SO 2 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 full y 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 ye ars. No indication was given as to how to determine compliance of the results, however the EPA did state that a relationship or correlation betw een 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 accordingl y. 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. I f 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 deter mine 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 a gency reviewed all comments and revised the rule to allow an SO 2 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 non

mercury HAP metal s alternative emissions limits and demonstrate compliance with the selected limit only . As mentioned elsewhere, the a gency 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 3724

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 reques t 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 tune

up 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 c ommenters ( 17716, 18498 , 17725 ) recommend that the phrase “performance test” in Table 3 b e replaced with “boiler tune

- up ” to avoid confusion and be consistent with the language in 63.10005(f). **Response to Comments 8**  **- 10:**  The a gency 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 , SO 2 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 clearl y state that: If continuous compliance is demonstrated with PM CEMS , a fabric filter bag leak detection system ( BLDS ) operating limit is not applicable. Tabl e 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 peri od, 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 clearl y 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. ”725

**Comment 13:** Commenters17174and 17775 suggest that the intended reference provided in Table 4 regarding fuel anal ys is procedures to demonstrate compliance with the applicable limits may be 63.10011(c) and not 63.10011(d). No provisions for fuel analy sis 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 appl y 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 not es 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 b y computing the average of all the 15

- minute readings taken during each test run. ” **Commen t 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 1 1**  **- 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.726

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 onl y be used if necessary to calculate output

- based emissions. **Response to Comment 19:** The a gency 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 c ommenters ( 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 a gency 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 c ommenters ( 17716, 17725 , 18498 ) note that for the SO 2 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 SO 2 is never mentioned in Appendix A. **Response to Comment 22:** The a gency has reviewed the comments, and the table now references Part 75 requirements and contains correct references. **Comment 23:** Several c ommenters ( 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 correctl y 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.727

**Comment 24:** Commenters 18498 and 17725 recommend that the EPA add the text below to Table 5, as applicable:

“Alternativel y, for an affected source that is also subject to the O 2 or CO 2 monitoring requirements of Part 75 of this chapter, the owner or operator may install, certify , maintain, operate and quality assure the data from an O 2 or CO 2 CEMS according to Part 75 of this chapter in lieu of the pro cedures 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 O 2 and CO 2 CEMS requirement s. **Response to Comment 24:** The a gency 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 O 2/CO 2 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 dat a 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 a gency 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 sy stems 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 th e 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 a gency 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 quarterl y emissions t esting or wait and use non

- FT IR 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 ox ygen 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 integrated728

average value. **6. Table 6: Comment 29:**  Commenter 17881 states that Table 6, which provides the fuel anal ys is 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 , particularl y 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 anal ys is for pollutants. **7. Table 7: Comment 30:**  Several c ommenters ( 17174, 17808 , 17881 ) state that the reference provided in the table regarding emission operating limits through fuel analysis should be 6 3.10011(b) as opposed to 63.10011(c). **Comment 31:** Commenters 17775 and 17808 state that the table onl y lists the operating limits for ESPs for units that operate wet scrubbers, therefore conflicting with other provisions, including proposed section 63.1001 1(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 av erages 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:729

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 performa nce 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 3 0**  **- 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 c ommenters ( 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 re

checked, 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. ” **Comm ent 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 c ommenters ( 17800, 17725 , 18498 ) state that the method for calculating 30 rolling average s 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 EP A 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).730

**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 abo ve the operating limit established during the performance test according to §63.10011(c). ” **Response to Comments 3 4**  **- 40:**  The a gency 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 c ommenters ( 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 tex t 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 (1 1), ” 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 specificall y 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 correctl y 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: Commen**  **t 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 th e 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)731

also requires compliance with §63.9(f). These provisions pertain solely to co mpliance 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) appl y. S ections (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 solel y to opacity monitoring, and should not apply , but the EPA must state whether or not they are included. The EPA should provide th at 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 ” i s 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

- sp ecific 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 exemp t periods of startup, shutdown, or malfunction.
 In determining whether the recordkeeping requirements in §63.10(b) and (c) appl y, 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 record s for more than 3 ye ars, 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 a gency 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 incorrectl y 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 quarterl y 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 mo nitoring:732

 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 mid

or high

- level gas, ” as daily calibration error tests are generall y conducted using a zero and upscale calibration gas.
 Table A

- 4, Daily

Calibration Error Test for O2 or CO2: The first bul let should read “use zero gas and either a mid

- or high

- level gas, ” as dail y calibration error tests are generall y 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 al so asks if the EPA intends moisture monitoring s ys tems consisting of wet and dry O 2 monitoring systems to be exempt from any sort of daily

calibration error test requirement. For such moisture monitoring sy stems, the commenter states that 40 CFR Part 75 ge nerall y requires those same on - going quality

assurance tests as are required for O 2 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 ty pographical 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 quarterl y 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 decide d against reproducing p art 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 s ys tems 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 b y 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 sy stems consisting of wet and dry O 2 anal yz ers are not exempted from daily calibration error tests. The O 2 monitors in these systems must meet the daily calibration requirements of part 75
.733

**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, 19 120, 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 c ommenters ( 17677, 17730, 17758, 17909 , 1 7912 ) 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 r

ule. 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 area source facilities as the term “major source ” is not used. **Comment 3:** Commenter 17656 urges the EPA to make clear precisel y 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 clearl y presents the compliance options as requested b y 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 appl y to each compliance option. The commenter points out that the EPA has the opportunity to electronicall y publish each of the different subcategories and the different options in a clear, direct, and plain language fashion with a limited amount of referen ces to other subsections, or mentions of “ as applicable. The EPA has substantively failed to provide a clear and readil y understandable set of requirements for sources in this proposed rulemaking. **Response to Comment 4:** The a gency believes that the final r ule provide s a clear and readil y understandable set of requirements, and the rule contains clarifications where appropriate. **2. CEMS c**  **omments .**  **Comment 5:** Multiple c ommenters ( 17623, 17655, 17716, 17681, 17800, 17821 and several others )734

request that the EPA review and update the language regarding CEMS , performance testing and operating limits. **Response to Comment 5 :**  As mentioned earlier, the a genc y has reviewed the commenters ’ concerns and revised the rule where appropriate. **Comment 6:** Commenter 17716 state s 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 onl y 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 a gency agrees with the commenters, and the rule has been revised to not require fuel sampling of pollutants where CEMS are us ed 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 eq uipment based on a performance stack test. The commenter recommends that the EPA require no proof of compliance beyond a properl y calibrated and installed CEMS , and that the EPA revise both the language and tables in the rule to clarify its intent as it re lates to CEMS used for demonstrating compliance. **Comment 9:** Several c ommenters ( 17655, 17696 , 17716 ) state that the language regarding performance testing and compliance is unclear and should be revised so that facilities can clearl y 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 compli ance. 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 specificall y 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 re sult 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 H F and HCl, and is consistent with the commenter’s suggestion. On the other hand, for735

sources who opt to use Hg or SO 2 CEMS in lieu of manual performance testing, the averaging time of the rule is 30 unit operating day s. 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 emplo yed. 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 a gency has reviewed the commenter ’ s conc ern, 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 incons istent 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 anal ys is 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 a gency 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 succinc tly 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 thi s 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 a gency 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 s ys tem is certified. ” The commenter requests that the EPA clarify when the 30

- day

operating period begins if the sy stems are already certified (e.g., current SO 2 or PM CEMS being used for 40 CFR Part 75 and/or 40 CFR Part 60 monitoring programs). **Response to Comment 14 :**  The EPA disagrees that any additional clarification is needed in the rule. O wners or operators of new EGUs have up until 6 0 days after the rule appears in the Federal Register or upon startup, whichever is later; or, for existing units, at least 3 years and 60 days after promulgation to be in compliance with the emissions limits and standards
.736

**Comment 15:** Commenter 17796 requests that the rule clearl y 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 compl iance. 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 a gency 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 value s 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 a gency 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 c ompliance, 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...sy stem ” to indicate that a “ certified CE MS ” 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 a genc y appreciates the commenter ’ s concern, no change was made to the rule, for §63.10010(g) requires Hg CEMS or sorbent trap monitoring s ys tems 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 i n 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 and737

18498 also make the same recommendation.
 For SO 2 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 “ Quarterl y 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 appl y 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 O 2 CEMS while section 63.10010(b) allows installation of CO 2 or O 2 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 s ys tems. 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 a gency 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 CO 2 or O 2 CEMS has been cl arified; the rule now allows either ty pe 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 ty

pes 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 SO 2 , CO 2 , O 2 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 a ssurance 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 require d to install a738

CEMS according to section 63.10010(a), however this contradicts the requirements in section 63.10010(b) which allow the use of O 2 or CO 2 . Also, the commenters note that the majority of Part 75 affected coal

- fired units utilize dilution extractive CEMS which are equipped with CO 2 analy zers and CEMS cannot measure O 2 as a diluent. **Comment 22:** Commenter 17718 states that section 63.10021(a)(10)(i)and(ii)) references continuously monitoring O 2 , but should also reference CO 2 monitoring as a diluent as an alternative. The following specific language changes are suggested:

 Section 63.10021(a)(10)(i): “You must continuously monitor O 2 or CO 2 according to sections 63.10010(a) and 63.10020. ”
 Section 62.10021(a)(10)(ii): “ Keep records of O 2 or CO 2 according to section 63.10032(b). ” **Response to Comments 21 -**  **22 :**  As mentioned elsewhere, the rule now allows O 2 or CO 2 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 b e 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 SO 2 RATAs performed for the combined purposes of 40 CFR Part 75 and this regulation would be reported in ERT. Any annual NO X 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 concurrentl y. **Response to Comment 23:** The a gency 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 NO X CEMS RATA data would ever need to be reported electronically

under this rule, but, as the commenter suggests, SO 2 CEMS RATA data from those EGUs whose owners or operators choose to use SO 2 CEMS as an altern ative means of demonstrating compliance with acid gas emissions limits would need to submit those data electronically
. **3. IGCC c**  **omments .**  **Comment 24:** Commenter 17801 recommends that the EPA provide further definition and clarification regarding air polluti on 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 s ome 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

- comb ustion 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 a gency 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 l imits.739

**Comment 25:** Commenter 17191 notes that footnote number 206 appears to preclude the use of the SO 2 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 SO 2 limit may not be used if your EGU does not have some form of pre

- or post - combustion desulfurization system. ” The commenter suggests th at the modification is necessary because IGCC units do not require “ flue gas desulfurization sy stems ” 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 SO 2 monitoring option without inadvertentl y preventing new and reconstructed IGC C units from pursuing the SO 2 alternative. **Response to Comment 25:** We believe that IGCC EGUs qualify for the use of SO 2 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) directl y from the fu el stream of IGC C units. In this respect, IGCC is more akin to a natural gas

- fired combined cycle unit, since it burns a sy ngas, 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 ty pe of electric generating unit b y proposing a separate subcategory for IGCC units. The EPA needs to further acknowledge the process dif ferences between IG CC 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, thereb y 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 a genc y 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 s yn gas - based heat input; and (2) differences between s yn gas - based and natural gas

- based output during co

- firing operations. **Response to Co mment**  **27 :**  The EPA is regulating IGCC units that burn sy nthetic gas derived from coal and/or solid oil

- derived fuel. Natural gas

- fired EGUs are not subject to this final rule. **4. Fuel s**  **am pling and**  **a nalysis**  **. Comment 2**  **8 :**  Commenters 17716 and 17725 request th at the EPA clarify whether units that fire a740

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, “ yo u must also conduct fuel anal ys es according to §63.10008 and establish maximum fuel pollutant input levels ” and includes specifics fo r 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 onl y require fuel sampling when burning a new fuel type. **Comment 2 9**  **:** In addition to the fuel sampling clarification, c ommenter 17716 also recommends that the EPA expand the exemption in section 63.10005(c)(5) to cover units that fire multiple fuel ty pes or blends in the final rule. The section state s that, fuel sampling and analysis are not required for single

fuel 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 anal ys is tests in section 63.10008 and Table 6 to ensure clarity and consistency. Proposed section 63.10008 requires fuel analy sis 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 clearl y st ate 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 M y General Requirements for Complying with this Subpart, ” paragraph (c)(2), clearl y states that liquid oil

- fired EGUs can demonstrate initial and continuous compliance using fuel anal ys is 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 clearl y and cohesivel y. **Comment 3 2**  **:** Commenter 17386 states that the fuel anal ys is 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 anal ys is), “ 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 3 3**  **:** Commenter 17718 requests that the EPA clarify the frequency

of ongoing fuel sampling/anal ys is required for purposes of comparison with “the maximum fuel input values calculated during the la st performance tests (if demonstrating compliance through performance stack testing). ” **Comment 3 4**  **:** Commenter 17718 states that the establishment of fuel limits appears applicable onl y to facilities that choose to comply via fuel anal ys is. If facilities app ly 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 carefull y review this section to properly link references to the appropriate sections and paragraphs. **Response to Comments 2 8**  **- 3**  **4 :**  The comments are moot because rule no longer requires fuel anal ysis for pollutants.741

**5. Subcategory c**  **omments .**  **Comment 3 5**  **:** 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 Anal ys is 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 thi s 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 anal ys is 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 unit s that operate a limited amount of time per ye ar on oil and are inoperative the remainder of the ye ar.  Commenters 17843 and 17796 both note that under section 63.10006 “ When must Iconduct subsequent performance tests, fuel anal ys is or tune

- ups?, ” it is c lear 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 , respectivel y, performance testing (stack testing) based upon Table 5. In the same section 63.10006 subdivision (s), continuous compliance can be based upon fuel anal ys is, which contradicts subdivisions (f) and (g). The general requirements state fuel anal ys is 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 3 5**  **:** The comments concerning fuel anal ys is for pollutants are moot because rule no lo nger 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, o r, in certain circumstances, tune

- ups or fuel moisture anal ys is. **Comment 3 6**  **:** 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 3 7**  **:** Commenter 17718 recommends that the EPA clarify whether the fuel anal ys es and procedures in section 63.10008 are onl y applicable to liquid oil

- fired EGUs that desire to meet their applicable emission limits through fuel sampling. **Comment 3 8**  **:** 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 Analy sis and Initial Compliance Requirements, subdivision (b) is clear that affected EGUs must demonstrate initial compliance with each of the742

applicable emission limits in Tables 1 and Tables 2 by conducting perf

ormance tests according to section 63.10007 and Table 5 and either conduct fuel anal ys is, 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 comp liance with fuel analysis. Subdivision (c) begins with compliance that can be demonstrated b y fuel anal ys is “ 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 n on - mercury HAP metals, HC1, or HF emissions limit based on fuel anal ys is 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 anal ys is compliance mechanism, the EPA should clarify the language. **Comment 3 9**  **:** Commenter 17718 states that section 63.10011(b) makes reference to conducting fuel anal ys es and establishing maximum fuel pollutant input levels . ” .as applicable. ” The commenter requests that the EPA clarify that the fuel sampling, anal ys es, and maximum input levels are onl y applicable to liquid oil

- fired EGUs that choose to meet their emission limits through fuel sampling methodologies. **Comment 40 :**  Comm enter 17881 states that if compliance via fuel sampling and anal ys is 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 reques ts 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 3 6**  **- 40**  **:** As mentioned elsewhere, the comments concerning fuel anal ys is 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 optio n, including quarterly emissions testing, use of CEMS, or, in certain circumstances, tune

- ups or fuel moisture analysis. **Comment 4 1**  **:** 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 clearl y state the typ es of fuel

- fired EGUs which are subject to this subpart. The commenter recommends that should be rewritten for clarity. **Comment 4 2**  **:** Similarl y, Commenter 17881 notes that the preamble discussion is confusing and sheds no light on the purpose of section 63.9983(b). The preamble discuss ion 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
- ye ar period, or more than 85 % of the annual heat input in at least one ye ar, is derived from natural gas). **Comment 4 3**  **:** Commenter 17881 states that the provisions of section 63.9983(b) are confusing because rule only applies to coal

- and oil

- fired EGUs, and th e percentage of heat input supplied by natural gas is743

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 prov isions 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 4 1**  **- 4**  **3 :**  We believe that the definitions in the final rule along with other edits related to s ituations where sources may “ switch ” source categories make the clarifications suggested by the commenter. **Comment 4 4**  **:** Commenter 17758 recommends that the language for coal

- based compliance should be clarified. The commenter states that the most likely co al

- 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 e lect to use already installed SO 2 CEMS; and 3) directly monitor mercury

using either a Hg CEMS or a sorbent trap monitoring sy stem. For the above

- described scenario in which either all of the regulated HAP or their surrogates are continuously monitored, th e 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 4 4**  **:** Although the a genc y 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, no t 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 4**  **5 :**  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 I GCC units. To eliminate any possible confusion, the commenter suggests that the EPA replace the term “ solid oil

- fired and coal

- fir ed 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 4 5**  **:** The a gency 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 l** **imits c**  **omments .**  **Comment 4 6**  **:** Several c ommenters ( 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 hourl y average during the performanc e 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 p rovide a rationale for how a three

- run744

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 day s 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 4 7**  **:** Commenters 17681 and 17800 state that operating limits, in cluding 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 co mmenter 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 4 8**  **:** 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 appl y 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 4 9**  **:** Several c ommenters ( 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 “ one size

- fits all ” operating parameter limit approach should be revised to allow sources greater flexibility in defining representative operating parameters. Commenter 17881 requests th e 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 potential ly

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 proce ss 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 5**  **1 :**  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 4 6**  **- 5**  **1 :**  As mentioned elsewhere, the comments concerning control device operating parameters and fuel anal ys is for pollutants are moot because the rule no longer requires them. In addition, the Agency

agrees that EGU owners or operators who choose to use CEMS as a compliance745

option need n ot 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 o**  **perating l**  **oad .**  **Comment 5 2**  **:** 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 clearl y define in section 63.10042 what constitutes maximum normal operating load or representative operating conditions. **Comment 5 3**  **:** 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 5 2**  **and 5**  **3 :**  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 c onditions. **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 O 2 monitoring system is required for compliance with these regulations. The last sentence of this paragraph references developing 30

- day rolling averages from “hourl y ox ygen emissions data. ” Paragraph (b) of this section references using CO 2 monitoring. The commenter recommends that paragraph (5) of this section be modified to reference averaging either O 2 or CO 2 emissions data, if the EPA believes that O 2 andCO 2 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 ho url y 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 speci fy

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 invali d data should be used to develop long

- term averages. The commenter recommends that paragraph (5) be modified to include language to specify that onl y valid hourly data should be used to develop 30

- day rolling averages.
 Section 63.10010 (e)(5) indicates th at sources should develop 30

- day rolling average for SO 2 but it does not specify

the applicable engineering units. The commenter recommends that the EPA746

specify the engineering units that apply to the 30

- day

rolling average. Furthermore, this paragraph also references using “ all the hourly SO 2 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 ro lling 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 appl y to the 30

- day rolling average. Furthermore, this paragr aph also references using “ all the hourl y 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 hourl y data should be used to develop 30

- day rolling averages. **Comment 5 5**  **:** 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 cal culated 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 “hourl y 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 averag e of all applicable hours in the 30

- day period. **Response to Comments 5 4**  **and 5**  **5 :**  As mentioned elsewhere, the rule now allows CO 2 or O 2 CEMS to be used, clarifies that only valid hours are to be included in the 30 boiler operating day rolling average, identi fies 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 m** **ixtu res and**  **s witches**  **. Comment 5**  **6 :**  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 ty pe ” (section 63.10042) is clear that individual fuel ty pes received from different suppliers are not considered new fuel ty

pes. 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 5 6**  **:** The a gency considered the commenter ’ s concern and disagrees with the commenter ’ s suggestion that the rule need s 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.747

**Comment 5 7**  **:** 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 SO 2 emissions and the commenter recommends that the EPA take into consideration and encourage environmentally beneficial practices such as fuel blending and fuel switching. **Comment 5 8**  **:** Commenter 17781 recommends that the EPA clarify section 63.9982(d) regarding switching coal rank or fuel ty pe b y revising the language as f ollows:

“An existing electric utility steam generating unit that has switched completely to burning a different coal rank or fuel ty pe is considered to be an existing affected source under this subpart. ” **Response to Comments 5 7**  **and 5**  **8 :**  The agency considere d 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 require s 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 5 9**  **:** Commenters 17808 and 178 70 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 s ys tem 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 newl ydesignated 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 newl y meets the definition of an affected fossil fuel

- fired unit subject to the rule. **Response to Comment 5 9**  **:** Although the a genc y has co nsidered the commenter ’ s suggestions, the rule remains unchanged. An EGU owner or operator must remain cognizant of the definitions in the rule, especiall y, 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 appl icability and compliance dates. **10. SO 2**  **c omments**  **. Comment**  **60 :**  Commenter 18498 notes that for SO 2 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 cross

reference to section 63.10010 allowing use of 40 CFR Part 75 certified monitors to conduct SO 2 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 li eu of monitors following 40 CFR Part 60.748

**Comment 6 1**  **:** 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 SO 2 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 6 2**  **:** Commenter 17714 requests that the EPA clarify the language placement of the SO 2 monitor at the outlet of the EGU in section 63.10010(e) to definitivel y state that it refers to placing the monitor in the stack downstream of the SO 2 control device for the EGU. **Comment 6 3**  **:** Commenter 17821 notes an unintended conflict between sections 63.10010 (e) and (e)(1). In paragraph (e), the EPA clearl y states that sources operating an SO 2 monitoring s ys tem 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 SO 2 C EMS under 40 CFR Part 75. The commenter recommends that the EPA modify paragraph (e)(1) of this section to clearl y state the EPA ’ s intended use of 40 CFR Part 75 for applicable sources. **Response to Comments 60** 

**– 6**  **3 :**  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. **Comme nt 6**  **4 :**  Commenter17881 states that none of the definitions for the term Er (regarding rolling emission averages in Equations 1 through 5) mention SO 2 , but there do not seem to be any prohibitions from averaging SO 2 emission rates (assuming that all units in cluded in the averaging plan would need to be eligible to use the SO 2 surrogate). The commenter suggests that SO 2 be added to the list of pollutants included in the term Er. **Comment 6 5**  **:** 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 SO 2 emission rate. Although this is discussed in appendix A to subpart UUUUU for Hg CEMS (Reference a ppendix A sections 1.4 and 4.1.2.4), this data exclusion is not clearly

stated for SO 2 CEMS. **Response to Comments 6 4**  **and 6**  **5 :**  The agency agrees with the commenter that SO 2 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 SO 2 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 actio n. **11. Testing g**  **uidelines and t** **imeline c**  **omments .**  **Comment 6 6**  **:** 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 se ction 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.749

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 submi ssion 60 day s before the test, the EPA must remove the redundant requirement in section 63.10030(d). **Response to Comment 6 6**  **:** The a gency 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 6 7**  **:** 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 rec ommends that the preferred option should be in terms of operating day s 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 te sts. **Response to Comment 6 7**  **:** The time ranges in the rule refer to calendar, not operating, days. **Comment 6 8**  **:** 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 m ake 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 6 8**  **:** The a gency 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 6 9**  **:** Commenter 17821 requests that the EPA issue a rule that clearl y 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 analy sis; 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 anal ys is and to set operational limits. **Response to Comment 6 9**  **:** 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. **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

- affected750

units do not have any

applicable emis sion 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 clearl y reflect this intent. **Response to Comment 70**  **:** The a gency disagrees with the commenter ’ s concern that the language regarding appropriate emissions limits from differing units sharing a common s tack 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 emissio ns averaging. **Comment 7 1**  **:** 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) specifi ed in the paragraph. **Response to Comment 7 1**  **:** 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 7 2**  **:** 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 successfull y 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) r equires 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 “ty

pe of fuel ” simply

means that if bituminous coal is ty pical ly 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 7 2**  **:** The a gency disagrees with the commenter ’ s suggestion that specific criteria be enumerated concerning possible impacts of EGU operation on emissions for those EGU owners or 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;751

should an EGU owner or operator be uncomfortable meeting the LEE eli gi bility requirements, he or she need not appl y. As mentioned elsewhere, the comment concerning highest pollutant content in fuel is moot, as fuel anal ys is for pollutants is no longer required. Finall y, as mentioned elsewhere, the rule now requires emissio ns testing be performed at normal operating conditions. **Comment 7 3**  **:** 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 7 3**  **:** 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 30 (or 90) boiler operating day rolling average basis, which means that those owners or operators will need to ens ure their existing units have at least one set of 30 (or 90) 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 c**  **omments .**  **Comment 7 4**  **:** 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 clearl y 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) reasonabl y 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 appl ication 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 7 4:**  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 onl y to that one instance. **Comment 7 5**  **:** Commenter 18034 s upports 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 NESHAP rule. The commenter states that it i s unnecessary for the EPA to use a separate term within the752

emissions averaging section. If a state accepts delegation of the final version of the proposed new subpart UUUUU, using the term “ administrator” would apply equall y 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 p lans 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 7 5**  **:** The a gency agrees with the commenter ’ s suggestion and has revised the rule. **Comment 7 6**  **:** Commenter 17174 suggests the following areas which would benefit from additional review and clarity.

 Section 63.10009(a) states “ you may demonstrate compliance b y emission averaging among the existing EGUs in the same subcatego ry , 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, SO 2 , HCl, non

- Hg HAP metals, or Hg emissi ons 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, SO 2 , 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 reque sts 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 sub mittal 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 clarificati on 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) b y 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 a genc y notes that the applicable emissions limit is the limit obtained from Table 2 (or in the case of Hg from the EGUs designed for coal ≥ 8,300 Btu/lb subcate gory, the limit given in §63.1009(a)(2)) , the rule has been revised to be consistent. The a gency 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 te st, and the rule already requires performance test results to be submitted electronically using the CDX, no753

additional clarification language is needed. **Comment 7 7**  **:** Commenter 17716 requests the following corrections and clarifications:

 The rule does not in clude 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 introduce d 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 CO 2 . 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 7 7**  **:** 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 CO 2 as well as O 2 measurements. **Comment 7 8**  **:** 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 by

pass stacks. **Response to Comment 7 8**  **:** The a gency agrees with the commenter, and the rule has been revised to clarify installation requirements. **Comment 7 9**  **:** 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 7 9**  **:** As m entioned 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 N O X lacks definition and needs explanation prior to the rule being finalized in order to comment. **Response to Comment 80**  **:** Although the a genc y 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 8 1**  **:** Commenter 17756 requests that the EPA clarify the language regarding “ dry flue gas technology
. ” The commenter states that the rule does not clearl y 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 8 1**  **:** We believe that the definition in the final rule clearl y indicates that both “ dry scrubbers ” and “ dry sorbent injection ” are included in “ Dry flue gas desulfurization technology. ” **Comment 8 2**  **:** Commenter 18023 states that to provide efficient application of the proposed rule, 4.1.3 Diluent Gas, Flow Rate, and/or Moisture Monitoring S ys tems should state that “ Monitors that have been754

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 8 2**  **:** In the final rule, section 4.1.3 of Appendix A states that the flow rate, diluent gas, and moisture monitoring sy stems 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 sy stem. Section 63.10005(d) specifies that if a continuous monitoring sy stem 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 8 3**  **:** 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 tracea ble calibrator. **Response to Comment 8 3**  **:** 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/m 3 or; or (c) the next highest multiple of 10 μg/m 3

. **Comment 8 4**  **:** 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 8 4**  **:** As mentioned elsewhere, this comment is moot for the rule no longer requires fuel anal ys is of pollutants. **Comment 8 5**  **:** 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 % O 2 or the corresponding fuel

- specific CO 2 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 cl arify how to calculate the “ corresponding fuel

- specific CO 2 concentration. ” **Response to Comment 8 5**  **:** As mentioned elsewhere, this comment is moot for the rule no longer requires emissions limits during periods of startup or shutdown. **Comment 8 6**  **:** 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 sy stems 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 CO 2/O 2 requirements of this regulation.
 In section 63.10010 (e)(6)(iii), the commenter requests that the reference to a f ourth level needs755

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 s ys tem any more accurate. **Response to Comment 86:** As mentioned elsewhere, the comment s are moot, for the rule no longer requires numerical 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 s ys tem malfunction in the definitions section of the rule. That definition will mirror the de finition for monitoring s ys tem malfunctions found in the proposed rule. **Comment 88:** Commenter 17881 requests the following clarifications and revisions:

 In formation regarding the unit or stack operating time [7.1.2.2] is not needed in order to calculate th e 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 l oad [7.1.2.3] is only needed for those units which are attempting to demonstrate compliance with a lb/GWh Hg emission limit.
 In formation regarding the hourly heat input rate [7.1.2.4] is not needed to support the lb/GWh Hg emission rate calculations. The u se 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) rel y on volumetric fl ow rate; rather, these equations rel y 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 onl y required for those units relying on sorb ent trap monitoring s ys tems and/or conducting lb/GWh mercury emission rate calculations.
 Section 7.1.5.2.5 requires the reporting of hourl y P MA, 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 currentl y states that CO 2 or O 2 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 similar756

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 carefull y review the two sets of reporting provisions and clearl y reconcile any differences between the provisions. **Response to Comment 88:** The a gency 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 t ext has been revised to remove hourl y 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 a genc y believes the reporting time lines are now consistent. **Comment 89:** Commenter 18034 states that section 63.10005(l) addresses the use of default O 2 and CO 2 concentrations for input

- based emissions calculations and the default power production rate for output

based 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 a

ppear to be contradictory :

 Section 63.10001(a)(4) unnecessarily requires additional conditions to meet an affirmative defense to b yp ass a control device. In some circumstances, the b ypass 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 sufficientl y 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 properl y documented b y properl y signed contemporaneous operating logs, ” but does not define or accuratel y describe what would fulfill that require ment.
 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 (b y 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 s ystematic 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. (S ee, e.g., State Implementation Plans: Policy Regarding Excessive Emissions During Malfunctions, Startup, and757

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 b y 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 anal ys is 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 deter mined, corrected or eliminated. However, in most cases, the EPA believes that a properl y conducted root cause analysis will have such results. **Comment 91:** Commenter 18498 states that section 63.10010(b)(5) should be revised to include CO 2 . 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) doe s not include a reference to CO 2 records. **Response to Comments 91 and**  **92:** As mentioned elsewhere, the rule now includes carbon dioxide as well as ox ygen, where oxygen is referenced. **Comment 93:** Several c ommenters ( 17730, 17758 , 17800 ) state that several provisions indicate that the requirements appl y “ as applicable, ” but few provisions clearl y 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, o r 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 a gency 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 unchang ed. 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 quarterl y, 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:** Similarl y, c ommenter 17800 states that due to the incorrect references to sections, incorrect citations and many other inconsistencies and misstatements within the proposed rule, it is di fficult 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 i nconsistencies 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.758

**Response to Comment 94:** As mentioned elsewhere, the rule has been revised to remove inconsistencies based on the Agency ’ s review and commenter ’ s s uggestions. **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 discus sions 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 a genc y 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, b y 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 pro vide 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 establish e d by s tates and tribes as part of their strategies to attain the NAAQS, these are not “requir ements of the act. ” Similarly , requirements established as a result of specific new source permitting are in compliance with CAA

- mandated p rograms but are not requirements of the act. The EPA did not state that the only requirement of the CAA contemplated in section 112(n)(1)(A) was the Title IV A cid Rain P ro gram . **13. Reference and n**  **umerical c**  **orrections .**  **Comment 98**  **:** Commenter17796 notes that the Hg limit in the preamble is a ty po and should read 0.0007 lb/GWh. **Response to Comment 98**  **:** The limits in the final rule have been reanal yz ed and corrected. **Comment 99**  **:** Commenter17848 notes that the preamble contains an error in the output

- based limit fo r 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].759

**Response to Comment 99**  **:** The limits in the final rule have been reanal yz ed and corrected. **Comment 10 0**  **:** 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 10 0**  **:** The comment is moot because the rule now requires work practice standards, not emissions limitations. **Com ment 10**  **1 :**  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 10 1**  **:** The rule has been revised to consolidate the LEE requirements. **Comment 10 2**  **:** Several c ommenters ( 17696, 17718, 18037 , 17821 ) note incorrect cross references in the text of the proposed rule. For example, section 63.10006(r) states “ If yo u are required to meet an applicable tune

- up work practice standard, you must conduct a performance tune

- up according to §63.10007. Each performance t une - up specified in § 63.10007 must be no more than 18 months after the previous performance tune

- up. ” Section 63.10007 addresses onl y performance testing. Commenter 17718 states that if “performance tune

- ups ” is the correct term, it appears that section 6 3.10021(a)(16) would be the more accurate section reference. **Response to Comment 10 2**  **:** Although the a gency 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 perf ormance tune - up. **Comment 10 3**  **:** 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 10 3**  **:** As mentioned elsewhere, the comments are moot because rule no longer requires emissions limitati ons during periods of startup or shutdown, monitoring of control device operational parameters, or fuel analysis for pollutants. **Comment 10 4**  **:** Commenter17718 states that the reference in section 63.10010(b) to appendix A . ” ..in lieu of procedures in paragra phs (a)(1) through (a)(3) below.... ” is inaccurate because they do not pertain to O 2 and CO 2 monitors. The EPA likely needs to correct this reference to (b)(1) through (b)(5). **Response to Comment 10 4**  **:** The cross

- reference to paragraphs (a)(1) through (a)(3 ) was clearl y incorrect, and should have been (b)(1) through (b)(5), as noted b y 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 sy stem. Section 63.10010(b) of760

the final rule specifies that the CO 2 or O 2 monitors must be certified and quality

- assured according to Part 75. **Comment 10 5**  **:** 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 inconsisten cy.  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. **Respons e to Comment 10**  **5 :**  The a gency appreciates the comments, and the rule has been revised to remove these inconsistencies. **Comment 10 6**  **:** Several c ommenter s ( 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 b e 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 10 6**  **:** As mentioned earlier, these comments are moot, for the rule no longer requires emissions limitations during periods of startup or shutdown. **Comment 10 7**  **:** 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) refer s to “maximum Hg input using Equation 9 of § 63.10011. ” The761

section and Equation 9 address non

- Hg metals. Commenter 17752 also notes this incorrect reference.
 Table 4 states “ If you demonstrate compliance using ... Fuel Anal ys is, you must “ [m]aintain the f uel ty pe or fuel mixture such that the applicable emission rate calculated according to §63.10011(d)(3), (4) and/or (5). **Response to Comment 10 7**  **:** The comments are moot, as described elsewhere the rule no longer requires operating parameter monitoring along with sorbent tube monitoring s ys tem 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 anal ys is of pollutants. **Comment 10 8**  **:** Commenter 17752 notes an incorrect reference in section 63.10031 (c). **Response to Comment 10 8**  **:** Although the comment lacks specificity , the agency has reviewed the section and revised the rule to correct references. **Comment 1 09**  **:** 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. **Respons e to Comment 1**  **09 :**  The reference to section 7.1.19 was a ty pographical error, which has been corrected in the final rule. **Comment 11 0**  **:** Commenters 17881 and 17718 note that paragraph (a)(4) of section 63.10010 references “ systems described in paragraph 2.1 o f 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 11 0**  **:** The reference in §63.10010(a)(4) to “paragraph 2.1 of this section ” was clearl y an error and has been removed from the rule. **Comment 11 1**  **:** Commenter 17881 notes that in paragraph 63.10021(a)(14)(ii), the reference should likely be “Appendix A of this part. ” **Response to Comment 11 1**  **:** The ref erence 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 11 2**  **:** 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 11 2**  **:** The a gency has revised the rule so that the performance tune

- up testing frequency is consistent. **Comment 11 3**  **:** Commenter 18498 suggests that se ction 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,762

section 63.10021 (h)(ii) states the “ Quarterl y 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 11 3**  **:** 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 11 4**  **:** Commenter 17881 notes that the following references and sections are wrong:

 reference to section 63.1 0021(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 11 4**  **:** The rule has been revised to correct the cross references. **Comment 11 5**  **:** 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 11 5**  **:** The comment is moot, for the rule no longer requires fuel anal ys is of pollutants. **Comment 11 6**  **:** Commenter 17881 notes ty pographical 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 11 6**  **:** As mentioned elsewhere, the rule has been revised to clarif y the language. **Comment 11 7**  **:** 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 in put levels. **Comment 118:** Commenter 17691 states that the rule refers back to a site

- specific monitoring plan required b y 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 si te - specific monitoring plan (i.e., facilities with763

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 co nfusion, 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 1**  **18 :**  Although the a gency 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.764

**8E -**  **Rule: Other Language Corrections Com**  **menter** : 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 a gency 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 a gency 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 a gency 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 instructi ons 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.765 **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 l isted 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 N ational 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 subcategorie s 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.766 **Section 9A Tables Mass Mail** **ings -**  **General Support for the Proposed Rule Table 9A** **- 1. Mass mail comments identified by the U.S. Docket Office**  **DCN Docket Entry**  **Count** 3084 Earl y Mass Comment Campaign sponsored b y National Wildlife Federation (NWF) 10,845 3085 Earl y Mass Comment Campaign sponsored b y Environmental Defense Fund (EDF) 66,532 3086 Earl y Mass Comment Campaign sponsored b y League Of Conservation Voters 65,149 3087 Earl y Mass Comment Campaign sponsored b y Sierra Club 27,019 3088 Earl y Mass Comment Campaign sponsored by Union of Concerned Scientists 10,872 3089 Earl y Mass Comment Campaign sponsored b y American Lung Association Action Network 2,116 3090 Earl y Mass Comment Campaign sponsoring organization unknown 3,053 3091 Earl y Mass Comment Campaign sponsored by Union of Concerned Scientists 47 6638 Mass Comment Campaign sponsored b y Greenpeace 4,685 11053 Mass Comment Campaign sponsored b y Earthjustice 8,704 12055 Mass Comment Campaign sponsored b y Earthjustice (Part 1 of 2) 3,112 12056 Mass Comment Campaign sponsored by Earthjustice (Part 2 of 2) 13059 Mass Comment Campaign sponsored b y the League of Conservation Voters 593 13060 Mass Comment Campaign sponsoring organization unknown 78 13061 Mass Comment Campaign sponsored b y Citizens for Pennsylvania ’ s Future (PennFuture) 172 13062 Mass Comment Campaign sponsoring organization unknown 202 13063 Mass Comment Campaign sponsored b y 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 b y Environment Florida 43 16546 Mass Comment Campaign sponsored b y 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 b y Physicians for Social Responsibility 2,607 16566 Mass Comment Campaign sponsoring organization unknown 42 16567 Mass Comment Campaign sponsored b y National Audubon Society 5,279 17007 Mass Mail Campaign sponsored b y Alliance for Climate Protection 47,525 17030 Mass Mail campaign sponsored b y First Congregational Church of Sonoma 28 17058 Mass Comment campaign sponsored b y Environmental Defense Fund (EDF) 18,425767

17059 Mass Comment campaign sponsored b y Natural Resources Council of Maine 123 17060 Mass Comment campaign sponsored b y National Wildlife Federation Action Fund 9,106 17802 Mass comment Campaign sponsored b y Kentucky Environmental Foundation 12 18190 Mass comment campaign sponsored b y Sierra Club 9,440 18490 Mass Comment Campaign sponsored b y Ohio Citizen Action 1,405 18491 Mass Comment Campaign sponsored b y Fair Climate Project 52 18492 Mass Comment Campaign sponsored b y 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 b y Restoring Eden 11,819 18546 Mass Comment Campaign sponsored b y National Wildlife Federation (NWF) 433 18638 Mass Comment Campaign sponsoring organization unknown 58 18639 Mass Comment Campaign sponsored b y 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 b y CREDO Action 136,779 18979 Mass Comment Campaign sponsored b y GASP (formerl y Alabama First) 94 18986 Mass Comment Campaign sponsored b y NC Conservation Network 904 18988 Mass Comment Campaign sponsored b y One Million Calls For Clean Energy 4,481 19112 Mass Comment Campaign sponsored b y Greenpeace 77,844 19113 Mass Comment Campaign sponsoring organization unknown 20 19125 Mass Comment Campaign sponsored b y Respiratory Health Association of Metropolitan Chicago 94 19150 Mass comment campaign sponsored b y Earthjustice 37,286 19550 Mass Comment Campaign sponsored b y Fall

- line Alliance for a Clean Environment (FACE) 130 19573 Mass Comment Campaign sponsoring organization unknown 23 19615 Mass Comment Campaign sponsored b y GreenFaith, Interfaith Partners in Action for the Earth 13,074 19632 Mass Comment Campaign sponsoring organization unknown 25 19643 Mass Comment Campaign sponsored b y 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 b y Environmental Defense Fund (EDF) 269 Total: 664,695768769

In addition to the mass mailings identified b y 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 18086770

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 4783771

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 3306772

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 4224773

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 6155774

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 6735775

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 9580776

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 16377777

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 18793778

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 11054779

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 18913780 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 19526781

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 15349782

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 15283783

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 4770784

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 5493785

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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 3546794

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.795 **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 13120796

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 14578797

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 15427798

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 16292799

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 16494800

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: 3,050801

**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 , employ ment, 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, 17 749, 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.802 **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 b y 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: 219803 **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: 35804 **CHAPTER 10**  **: INCORPORATION BY REFERENCE**  **10 -**  **Incorporat ion**  **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 b y the commenters who asked to incorporate the referenced commenters ’ remarks. Specificall y, 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 anal ys is 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, 17870 a , 17902, 17909, 17920, 18018, 18020, 18831 17808 Clean Energy

Group 17870 a , 18025 18500 CPG 18437 17758 EEI 17627, 17770, 17772, 17776, 17790, 17800, 17805 b , 17807, 17820, 17870 a , 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 GCL C 17813, 17904, 18785 17698 GPA 17710 19506 ID EM 19212 19122 LADWP 19121 17724 LEC 17722, 17805, 18031805

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, 17909 c , 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, 17868 d , 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 bel ow. ” b Montana
- Dakota Utilities Company (DCN 17805) incorporated by reference the majority of EE I ’ 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 b y reference UARG ’ s comments in regard to data availability , data anal ys is, conversion errors, and MACT monitoring.806 **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 Mellinger

Birdsong Georgia 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 Whyt e Individual 11:00 Mike Kennedy Progress Energy 11:05 By

ron T. Burrows Tampa Electric Company 11:10 Alison Amy

x 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 12:25 Alan O. Toney Individual807

**Time Name**  **Affiliation** 12:30 James Capp Georgia Air Protection Branch 12:35 Joy

Kramer GA Solar Energy Association 12:40 Thelma Hey

wood 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 L aushkin 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 Muhl y Sierra Club 3:00 Eddie Ehlert Individual 3:05 Lyn dsay

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

L ittle 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 4:30 Elizabeth Lopez Global Warming and Energy Team808

**Time Name**  **Affiliation** 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 Gly

nn (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 Individual809 **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 Lym an 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 Py

tel 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 UI C/LVESO810

**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 NEI S 3:10 Jerry

B. Cain Judson University 3:15 Rebecca Rossof Climate and Energy Program 3:20 Michelle Martinez Sierra Club 3:25 In grid 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 Center811

**Time Name**  **Affiliation** 4:55 Amanda Kaley Individual 5:00 Susan Williams Sierra Club 5:05 David A. Creech EL CA 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 Jocely

n 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 C oalition 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

L eonard Individual 7:35 Marianne Flanagan Individual 7:40 Jessica Brackett Individual 7:45 Paul Kim University of Chicago 7:50 Joyce Blumenshine Heart of Il linois Sierra Club 7:55 Dr. Maureen McCue Io wa Phys icians for Social Responsibility 8:00 Susan L annin In dividual 8:05 Tim Sutherlin Individual 8:10 Kristen Vy

hnal Individual 8:15 Melissa Mullarkey 8:20 Alexandra Sipiora Individual 8:25 Kevin Carol Individual 8:30 Adam Burke Individual 8:35 Mary

beth 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 Muscatine812 **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 P yrch Summit Presby terian Church 10:05 Eileen O ’ Bo yl e 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 b y 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 Is aac 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 Individual813

**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 Ty

ra Bryant - Stephens The Community Asthma Prevention Program 2:35 Candance Cheatham Individual 2:40 Mark Schmerling Individual 2:45 Dr. Rima Sy

nnestivedt 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 Dahlkemper

Alfonso Individual 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 Bo ye r 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 McNell y 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 Club814

**Time Name**  **Affiliation** 5:20 James Kelley Individual 5:25 Fre yd a 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 My

riam Fallon Greenpeace 7:35 Christina Marie Glessner Individual 7:40 Rosa Michmya Individual 7:30 Dr. Gwen DuBois Chesapeake Phy sicians for Social Responsibility 7:35 Dr. Cindy

Parker Chesapeake Phy sicians for Social Responsibility 7:40 Jeff Player Individual 7:45 Lisa Hastings Individual 7:50 Stephen Shapiro Chesapeake Phy sicians 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 Individual12/0 8 /11 DRAFT

815 **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. Mellinger

Birdsong None 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 (GCL C) 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 Anony mous public comment None12/0 8 /11 DRAFT

816 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 By ron 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
- A 1 David R. Tripp and Dennis Lane Stinson Morrison Hecker LLP on

behalf of Westar Energy , Inc. EPA
- HQ
- OAR
- 2009
- 0234
- 14069
- A1 Ray mond 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 Ray mond 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 Cy nthia Bearer, Board Chair Children ’ s Environmental Health

Network (CEHN) EPA
- HQ
- OAR
- 2009
- 0234
- 16122
- A1 Harold “ Gus ” Frank Forest County Potawatomi

Community

(FCPC)12/0 8 /11 DRAFT

817 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 Uni ted 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 Commissioners12/0 8 /11 DRAFT

818 (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 Evely n Fang Leadership Council Alaska,

American Lung Association EPA
- HQ
- OAR
- 2009
- 0234
- 17174
- A2 My ra 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,

In c.12/0 8 /11 DRAFT

819 EPA
- HQ
- OAR
- 2009
- 0234
- 17283
- A1 Carli Smith et al. Cooper Environmental Services, LLC (CES) EPA
- HQ
- OAR
- 2009
- 0234
- 17291 Anony mous 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, In c. EPA
- HQ
- OAR
- 2009
- 0234
- 17306
- A2 Glenn W. Miller Holmes

- Way ne 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

- CI O (Boilermakers Union) EPA
- HQ
- OAR
- 2009
- 0234
- 17405
- A1 Jennifer Lust Brainerd Lakes Area Audubon Society EPA
- HQ
- OAR
- 2009
- 0234
- 17406
- A1 Ray mond Burns Rogers
- Lowell Area Chamber of

Commerce12/0 8 /11 DRAFT

820 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 (I CAC) 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 Ray mond L. Evans FirstEnergy Corp. (FE) EPA
- HQ
- OAR
- 2009
- 0234
- 17628
- A1 Les Oakes King & Spalding LLP on behalf of Power4Georgians, LL C (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 North east 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 Lyn da Munkres, Morris County , TX12/0 8 /11 DRAFT

821 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 Bobb y 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

(LAB I) EPA
- HQ
- OAR
- 2009
- 0234
- 17693
- A1 Stephen J. Metcalf and Susan Longview Economic Development

Corporation12/0 8 /11 DRAFT

822 Mazarakes

- Gill EPA
- HQ
- OAR
- 2009
- 0234
- 17694
- A1 Lyn da 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 Dy negy , 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 Kentucky12/0 8 /11 DRAFT

823 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 PPLCorporation 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 Li gnite 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 Way ne 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 LL C (IPA) EPA
- HQ
- OAR
- 2009
- 0234
- 17739
- A1 Neal J. Cabral McguireWoods LLP on behalf of CONSOLEnergy , Inc.12/0 8 /11 DRAFT

824 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 L ewis 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 & Li ght 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 Pay ne, Mayor Thomasville, GA EPA
- HQ
- OAR
- 2009
- 0234
- 17765
- A1 John T. Heard The Virginia Coal Association, In c. (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, In c.12/0 8 /11 DRAFT

825 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 Day ton 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)12/0 8 /11 DRAFT

826 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, In c. 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, In c. EPA
- HQ
- OAR
- 2009
- 0234
- 17814
- A1 James O. Vick Gulf Power Company12/0 8 /11 DRAFT

827 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 Way ne 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

Gy psum 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 (SEL C) EPA
- HQ
- OAR
- 2009
- 0234
- 17836
- A1 John T. Suttles, Jr., Southern Environmental Law

Center (SEL C) and Southeast12/0 8 /11 DRAFT

828 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. McNell y ARIPPA EPA
- HQ
- OAR
- 2009
- 0234
- 17851
- A2 Melvin E. Keener Coalition for Responsible Waste

In cineration (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, Georgia12/0 8 /11 DRAFT

829 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, LL C (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, In c. EPA
- HQ
- OAR
- 2009
- 0234
- 17877
- A2 Todd A. Tolbert Associated Electric Cooperative, In c. 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 District12/0 8 /11 DRAFT

830 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, In c. EPA
- HQ
- OAR
- 2009
- 0234
- 17903
- A2 Leland M. Searles Io wa 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 Cy nthia 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 C ompany , 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 LLC12/0 8 /11 DRAFT

831 EPA
- HQ
- OAR
- 2009
- 0234
- 17926
- A2 Derf Johnson Montana Environmental In formation 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 (GCL C) 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 Day

ton, 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)12/0 8 /11 DRAFT

832 EPA
- HQ
- OAR
- 2009
- 0234
- 180 29
- 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 Fly nn, 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 L ouisiana 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 Shelb y 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 Fund12/0 8 /11 DRAFT

833 (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 Reill y Hoosier Energy Rural Electric12/0 8 /11 DRAFT

834 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, Mayo r City

of South Sioux City, Nebraska EPA
- HQ
- OAR
- 2009
- 0234
- 18482
- A1 Ann H. Campbell, Mayor Mayor ’ s Office, City of Ames,

Io wa 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 Masl yn 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,

In c. (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 None12/0 8 /11 DRAFT

835 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 Id aho 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 L awson 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 Blakel y, 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,

Nevada12/0 8 /11 DRAFT

836 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 Tray nor Northampton Generating Company , L.P EPA
- HQ
- OAR
- 2009
- 0234
- 18964
- A2 CONSOL Energy Inc. CONSOLEnergy 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 Water12/0 8 /11 DRAFT

837 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
- 192 14
- 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. Easterl y 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 of12/0 8 /11 DRAFT

838 Manufacturers (NAM) EPA
- HQ
- OAR
- 2009
- 0234
- 19581
- A1 Kent Greenwalt, Mayor City

of Terry town EPA
- HQ
- OAR
- 2009
- 0234
- 19595 N.A. Bishop City of Terry town 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, In c) 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 Io wa 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