## EPA’s Responses to Public Comments on EPA’s National Emission Standards for Hazardous Air Pollutant s from Coal- and Oil-Fired Electric Utility Steam Generating Units December 2011

Volume 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 fr om Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, IndustrialCommercial-Institutional, and Small Industrial-Co mmercial-Institutional Steam Generating Units . The EPA published a Notice of Proposed Ru lemaking 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, Illi nois; Atlanta, Georgia; and Phila delphia, Pennsylvania, in May 2011. Copies of all comments submitted and transcripts fo r the public hearings are available at the EPA Docket Center Public Reading Room. Comments, letter s, and transcripts of the public hearings are also available electronically through http://www.regulations.gov by searching Docket IDs EPA-HQ-OAR2009-0234 (NESHAP action) and EPA-HQ-OAR-2011-0044 (NSPS action)

. This document contains responses to comments on the NESHAP only; responses to comments on the NSPS action are in a separate Response to Comments document. Due to the size and scope of this rulemaking, the EPA summarized a limited amount of ma jor comments in the preamble of the final rule. This document contains a summary of all signifi cant comments provided by each commenter extracted from the original letter orpublic hearing transcript.

Appendix A of this document provides a list of pub lic hearing speakers and th eir affiliation. Appendix B of this document provides a list of commenters and their affiliation along withthe associated document control number (DCN). For each comment, the DCN is provided along with the comment summary. For purposes of this document, the te xt 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 comme nter states” or “The commenters assert”). The comment summaries do not represent the EPA’s opinion unless the response to the comment specifically agrees with all or a portion of the comment. In some cases the same comment was submitted by two or more commenters through submittal of a form letter prepared by an organization, by the commenter incorporating by reference the comments in anothe r comment letter, or by the commenter providing identical or similar language i ndependently. Rather than repeat these comment excerpts for each commenter, the EPA has listed the comment excerpt onl y once and provided a list of all the commenters who submitted the same form letter or otherwise inco rporated the comments by reference in Tables 9A1 through 9A-21 and 9B-1 through 9B-5 of section 9 of this document and Tabl e 10-1 of section 10 of this document, respectively.

Several of the EPA’s responses to comments ar e provided immediately following each comment summary. However, in instances where several commente rs 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 sp ecific comments or groups of similar comments in the preamble to the final rulemaking. Rather than repeating those responses in this document, the EPA has referenced the preamble or the appropriate technical support document for a description of the analysis included in the final rule.

As both the NESHAP and NSPS actions were included in the same proposal package, many commenters submitted comments to this rulemaking docket that we re specific to the NSPS action. Some commenters submitted a single DCN with comments on both rules, while others submitted a separate DCN specific to each action. Many commenters submitted identical comments to both dockets. In order to reduce duplicative comments, we have removed from this document comments associated with the NSPS2 action. For this reason, the EPA encourages the pub lic 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: Emission Impacts 6B – Impacts/Costs: Emission Reductions 6C – Impacts/Costs: Energy Impacts 6D – Secondary Impacts 6E - Impacts/Costs: Compliance Costs 6F – Control Technology Cost Assumptions 6G - Impacts/Costs: Testing a nd Monitoring Cost Assumptions 6H - Impacts/Costs: Pr ojection of New Units 6I - Impacts/Costs: Economic Impacts/Employment Impacts 6J - Impacts/Costs: Social Costs 6K - Impacts/Costs: Health Co-Benefits 6L - Impacts/Costs: Mercury Benefits 6M - Impacts and Costs: Air quality co-benefits modeling 6N - Impacts/Costs: Other/Miscellaneous

CHAPTER 7: STATUTORY AND EXECUTIVE ORDERS 7A - Executive Order 12866, Regulatory Pla nning and Review and Executive Order 13563, Improving Regulation a nd 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 C oordination with Indian Tribal Governments 7G - Executive Order 13045, Protection of Children From Environmental Health Risks and Safety Risks 7H – Executive Order 13211, Actions Concerning Re gulations 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 Ex ecutive Orders: Other

CHAPTER 8: RULE L ANGUAGE CORRECTIONS 8A - Rule: Definitions (existing) 8B - Rule: Definitions (new) 8C - Rule: Corrections to tables 8D - Rule: Language 8E - Rule: Other Language Corrections4 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 COMMENTERS5 CHAPTER 5: COMPLIANCE WITH TES TING/MONITORING/RECORDKEEPING AND REPORTING

5A01 - Testing/Monitoring : Stack Test Methods

Commenters : 17174, 17191, 17402, 17621, 17623, 17675, 17681, 17696, 17716, 17725, 17729, 17730, 17731, 17747, 17754, 17758, 17767, 17770, 17775, 17790, 17795, 17800, 17807, 17808, 17820, 17821, 17868, 17877, 17878, 17880, 17881, 17975, 18014, 18015, 18021, 18025, 18034, 18428, 18498, 18539, 18935, 18963, 19033, 19536, 19537, 19538, 18932, 18023

1. Comments related to alternat ive compliance test methods.

Comment 1 : Commenter 17775 states that the EPA should allow use of Method 5B and 29 to demonstrate compliance with the PM limits under th e stack testing option. Rather, the commenter asserts, the EPA proposes to allow use of Method s 5, 5D (required for positive pressure FFs), or 17 (Proposal Table 5). The commenter states that sources performing calibrations of PM CEMS under Performance Specification (PS) 11, on the other hand, ar e also allowed the option of using Method 5B - Determination of Nonsulfuric Acid Particulate Matter Emissions from Stationary Sources. The commenter states that Method 5B was specifically developed to determine primary filterable PM emissions from sources with wet scrubbers and is routinely allowed for stack testing under federal regulations. (40 CFR part 60, subparts D (section 60.46(b)), Da (section 60.50D a(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 tables).) The commenter asserts that the EPA should allow use of Method 5B or explain why the method is not appropriate for demonstr ating compliance with the proposed limits. The commenter asserts that although the agency’s specifi cation of a filter temperature for Method 5 (320° F + 25) achieves some of Method 5B’s objective, ther e is no basis for not allowing sources to use a promulgated test method specifica lly designed for that purpose. According to the commenter, prohibiting use of Method 5B c ould prevent some sources from using tests under subpart UUUUU to meet other testing requirements without obtaining approval for use of a higher Method 5 filter temperature in lieu of using Method 5B. Moreover, according to the commenter, evaluation of filterable PM data from the agency’s 2010 ICR database rev eal 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 commenters (17681, 17716, 17725, 17767, 17790, 17795, 17800, 18014) request that the final rule include the follo wing reference methods in Table 5:

1. EPA Method 2H, 2. Conditional Test Method 41 (wall effects adjustment for flow), 3. EPA Method 26A (HCl - option for dry stacks), 4. EPA Method 320 (HCl – FTIR option), 5. EPA Method 5B, 6. EPA Method 17 (total, filterable PM), and 7. The table should indicate that Method 2 (or equivalent) need only be used if necessary to calculate output-based emissions.

Response to Comments 1 and 2 : The final rule has been amended to allow the use of EPA Methods 2H, 26A and 320 and clarify the re quirement of Method 2 (or equiva lent) only as necessitated by the6 calculation 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 temper atures up to 220o F for up to 3 hours. While Method 5B also specifies a filt er 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 c ondensed sulfuric acid. This additio nal analytical 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 met hod in the rule but would entert ain a request for site-specific alternative method approval to use Mehtod 17 in lieu of Method 5. A condition of approval is that the stack gas temperature at the samp ling location remains no greater than 320o F during the performance testing.

Comment 3: Several commenters (17767, 17790, 17795, 17800, 17821) state that proposed use of Method 5 rather than Method 5B in wet stacks is incons istent with NSPS (e.g., section 60.46(b), section 60.50Da(e)(1), section 60.46b(d)(2), a nd section 60.45c(a)(2)) and inconsis tent with part 63(e.g., section 63.1450(b) and section 63.1579), and the commenters request that the final rule sp ecify the option to use Method 5B in wet stacks for compliance tests an d 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 desi ccation temperatures per the proposal would occur at M5 temperatures (220 °F). Commenter 17795 states that absence of Method 5B from the proposal creates a problem complying with section 3.20 of PS-11, which defines “reference method” as the method defined in the applicable regulation, but the method listed in proposed Table 5 is a hybrid method. Commenter 17795 states that inclusion of Method 5B is critical to certification of PM CEMS because all wet particulate monitors use some type of heated cyclone to vapo rize water droplets before analyzing the gas sample, and the temperature of these cyclones is set to be consistent with the reference method filter temperature. However, according to this commenter, inorder to obtain a final f ilter weight the reference method filters must be desiccated, to a constant we ight, and proposed Table 5 specifies Method 5, which by default would require filter desiccation at 220 °F. According to this comment er, since the PM CEMS sampling process occurs at temperatures above th e acid dew point, Method 5B should be followed to allow filters to be desiccated at the same temperatur es as sample collection to minimize inaccuracies for wet PM CEMS correlations. Commenters (17795, 17800) also believe that making the MACT standard consistent with the NSPS program and SIP programs w ill allow the use of a single stack test to satisfy multiple regulatory requirements and save time , resources, and costs. Commenter 17725 recommends that the EPA also allow 40 CFR Part 60 Method 2H -Determination of Stack Gas Velocity Taking into Account Velocity Decay Near the Stack Wall as a valid method for all pollutant types listed in Table 5 to subpart UUUUU of part 63 performance stack test ing requirements. The commenter notes that they utilize Methods 2, 2F, 2G, and 2H fo r annual volumetric flow monitori ng as required across the fleet.

Response to Comment 3: The final rule does not re quire 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 th e final rule, the final rule allows for this option. Please see the final rule preamble for further discussion.

Comment 4: Commenter 17775 requests that th e 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 volum etric flow rate of the stack gas when testing for PM, HCl, and Hg, and lists Method 4 to determine moisture content fo r all pollutants, but in some cases, use of these methods may not be necessary, or reasonable, because all of the me thods specified in Table 5 for concentrations of those emissions also provide meas urements of velocity and flow. Likewise, according to the commenter, the methods used to determin e pollutant concentrations (e.g., Methods 5, 23, and7 26A) also determine stack moisture. The commenter st ates that the agency should make use of those methods optional and allow the EGU to determine wh ich method is more appropriate for the specific
test.

Response to Comment 4: The final rule has been amended to clarify that only methodology or equations required for the specific emission limit will be required.

Comment 5 : Commenter 17808 recommends measures be inco rporated in the final rule to avoid running a unit simply to conduct a stack test similar to the approach used in part 75 for defining an operating quarter and a unit operati ng hour. Specifically, the commente r recommends incorporation of the provisions of 40 CFR 72.2 defining a “QA operating quarter” as “a calendar quarter in which there are at least 168 unit operating hours (as defined in th is section) or, for a co mmon stack or bypass stack, a calendar quarter in which there ar e at least 168 stack operating hours (a s 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 en tire hour. The commenter recommends that these definitions apply specifica lly to the regulated fuels under the EGU MACT rule (e.g., coal and liquid oil), because by requiring a minimum level of ope ration to trigger stack testing requirements, no unit will be operated simply for the sake of testing.

Commenter 17808 recommends an additional, alte rnative method for demonstrating continuous compliance for Hg when a unit qualifies for LEE status . As an alternative to conducting monthly fuel tests, the commenter proposes that owners/operators of a LEE unit have the option to conduct an annual Method 30B performance test to demonstrate that its emissions are less than 10 pe rcent 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 test s (e.g., quarterly, as recommended above). Under this commenter’s pr oposal, in the subsequent year, if the unit can, again, demonstrate LEE status through reduced utilization or a lower emi ssion rate, it would return to annual stack tests under the LEE provisions. The commenter recommends th is alternative, annual st ack testing instead of monthly fuel testing, to balance th e need for accurate emissions data with reduced compliance costs for those units emitting at a fraction of the proposed standards. Also, in order to avoid having companies run units simply to conduct stack testing, the commenter proposes that LEE units have the flexibility to schedule their annual performance tests at any time during a 12-month cycle because some of these LEEs may be smaller units with lo w capacity factors and may go seve ral months with out operating. The commenter believes that allowing flexibility in scheduling stack tests wi ll avoid unnecessary HAP emissions and reduce costs for thes e units operating well below the propo sed standard and believes this compliance option would allow companies to align test ing under this rule withexisting state testing requirements.

Response to Comment 5: The EPA agrees with the comments. The final rule has been amended to waive testing requirements in a qu arter when the unit operates for le ss than 168 hours, but the source must under any circumstances te st at least once per year.

Comment 6: Commenter 17747 states that they would also like to see the Method 29 monitoring options (Method 29 testing every 2 months or ever y month depending on PM control) retained. The commenter believes that this gives plant operators a dditional control options and flexibility in achieving emissions limits.

Response to Comment 6: The final rule has been amended to a llow compliance with the non-Hg metals limit with quarterly Method 29 testing.8 2. Comments related to testing period (clarification etc.).

Comment 7: Commenter 17868 states that the final rule shou ld clarify the required testing period in proposed section 63.10005(k) which specifies 28 to 30 days, but proposed Table 5 specifies 30 days.

Response to Comment 7: The EPA has clarified this issue in the final rule. The required testing period is 30 days

.

Comment 8: Commenter 18539 states that it is not clear in the proposal whether the EPA intends to require one performance test every 5 years for all surrogates. For example, asserts the commenter, proposed section 63.10005(d)(4) states that initial compliance for coal-fired units with FGD technology and 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 the 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, section 63.10005(a) states that “[I ]f you use a continuous monitoring syst em 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 conducti ng the initial 30-day perform ance 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 requireme nts 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 emission standard with which the source complies (either the direct emission limit, such as HCl, or the alternate equiva lent standard, such as SO 2 ).

Comment 9: Commenter 17775 requests that the agency cl arify 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 da ys of sorbent trap data(i.e., two 14-day sorbent traps) to determine the “average Hg concentration” for the performance test, the EPA should make clear in Table 5 that the values in Table 5 can be derived from 28 days of data.

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

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

Comment 10 : Commenter 17775 requests clarifications regarding the proposal’s stack testing options for HAP metals because it is not clear to the co mmenter whether the agency intended the operating parameters and fuel input limits in proposed s ection 63.10011(b) to apply, because on its face, the requirements of section 63.10011(b) a ppear to apply to all EGUs, re gardless of the compliance option. However, according to the commenter, that result is not consistent with the agency’s expressed intention. For example, the commen ter asserts, in the preamble the EPA says that such operating parameters do not apply and cites 76 FR 25,029/3 (“ Except for liquid oil-fired units, . . . we are proposing that you monitor during ini tial performance testing specified operating parameters) (emphasis9 added). However, the commenter states, similar to LEEs, the EPA also suggest s 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 thatif the maximum fuel input limits in section 63.10011(b) apply to liquid oil-fired EGUs opting to demonstrate compliance using stack testing, the EPA should make clear that EGUs combusting a si ngle fuel type are not required to make any determination regarding that fuel under section 63.10011(b)(2)( i) and (3)(i) (requiring determination that the fuel type or mixture has the highest content of Hg and of non-Hg HAP meta l) 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 oi l-fired EGUs in secti on 63.10005(c)(4) and section 63.10011(c)(1), those provisions apply only to liquid oi l-fired EGUs complying through fuel analysis.

Comment 11: Commenter 18023 states that the agency must clar ify that operating limits and fuel limits do not apply to sources using CEMS for compliance b ecause the commenter assumes that the purpose of the operating limits is to demonstrate compliance betw een regularly scheduled pe rformance tests at units that are not otherwise continuously monitoring comp liance; however, the proposed rule is not clear on this point. The agency should therefore specify that the operating limits (inc luding the operating load limit) and fuel limits apply only to units using stack tests to comply.

Comment 12: Commenter 17775 states that the final rule must clarify the operating limit requirements for control devices and the single fuel EGU require ments for establishing a maximum fuel input for chlorine under section 63.10011(b)(1)(i).

Comment 13: Commenter 17878 states that for units not equipped with CEMS it is appropriate to have an alternative approach to assure compliance for th e periods between stack te sts. The EPA proposes to set enforceable operating limits based on control device parameters 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 flexibility for the source to account for sma ll variations in control equipment performance and fuel characteristics. The result wi ll be “over-compliance” during a periodi c stack test, and this is normal. If operating conditions reflecting this stack test period are thenused as a measure of ongoing compliance, then those expected variations, whic h do not exceed an emission limit, would become violations.

Comment 14: Commenter 17868 states that the EPA s hould re-evaluate the proposed operating parameter requirements.

Response to Comments 10 - 14: The final rule has removed the requirements for operating and fuellimits, except where a source: (1) opts to use a PM CPMS to monitor compliance; or (2) for a liquid oilfired unit, adopts a source-specific monitoring plan to collect, re cord, and report on appropriate operational parameters in addition to conducting quarterly performance tests. In addition, the EPA notes that the final rule allows a source to monitor fuel moisture data to demonstrate compliance with the HCl and HF standards for liquid oil-fire d units (fuel moisture must be no greater than 1.0%). The details of these options are discussed in the preamble to the fi nal rule and elsewhere in this response to comment document. There are no operating parameter requiremen ts in situations where a source determines compliance with an emission limit using a CEMS.

4. Comment related to use of short term stack test and fuel samples to set 30-day standards.10 Comment 15: Commenter 17402 states that the EPA should not penalize facilities with low emissions by setting both fuel content and operating limits based on average performance during stack tests because this methodology effectively sets lower standards. Instead, according to the commenter, the EPA should set fuel content limits based on the sour ce’s contaminant removal e ffectiveness, so that a source can use a range of fuels as long as the stan dard is met. Commenter 17729 is an affected source operator who discusses stack test results for non-Hg meta ls and total PM at a unit that will be subject to the proposed MACT standards. Commenter 17720 states that the stack test data collected in 2010 in response to the EGU MACT ICR reflected complian ce with the proposed sta ndards during the 4-hour steady state tests, but this source ope rator states that such steady state tests do not indicate if continuous compliance is achievable at this source. Commenter 17623 states that the propos ed 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 eachstack test is time-consuming a nd costly, the EPA cannot expect facilities to feasibly perform numerous stack tests.

Response to Comment 15: The final rule has removed the requirements for operating and fuel limits with the exceptions noted in Response to Comments 10-14, above.

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

Comment 16: Commenter 18014 states that despite Method 202 being revised to include a nitrogen purge and an initial dry impinger (which is quickl y wetted with condensation 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 th e 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 pa rticularly 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 prim ary particulate and certa inly not related to metal HAP in any way.

Comment 17: Commenter 17402 expresses concerns that condensable PM reference Method 202 is unproven and variable and should be improved, becau se 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 th ere are concerns about condensable PM formation and creation of pseudo particulates. The commenter references recently completed Method 202 stacks tests on a number of units using the same coal, and observations that the condensable PM fraction ranged from 7% to 75%. This comment er relays plans to install Tron a FGD controls to reduce HCl and to further reduce condensable PM but expresses concerns that Method 202 may not properly quantify actual reductions. Commenter 17402 also relays plans to commission ni ne 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 mo re reliable standard in time for the initial MACT compliance date; however, the commenter believes th at given the benefits of reduci ng condensable PM, the EPA should not let testing uncertainty preven t the implementation of the total PM standard. Commenter 17402 refers to the EPRI CEMS Users Group inChicago, IL on June 8, 2011 and a presentation given by Clean Air Engineering (“CAE”) entitled “Des cription of a Potential Pseudo CPM Formation Mechanism in New EPA Method 202” for a CFB boiler equipped with an SNCR. The paper conclude d 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 sulfat e or bisulfate. According to11 commenter 17402, CAE recommended that ammonium su lfate or bisulfate fo rmed in the Method 202 dry impingers should be considered an artifact an d 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 quan tification and correction” of this artifact using procedures prescribed by CAE or the EPA should modify Method 202 to reduce or eliminate the bias. Commenter 17402 states that subtracting the inor ganic condensable PM from Method 202 and adding the inorganic condensable PM from CTM-013 (controll ed condensation) was one of the steps included in the proposed procedure.

Comment 18: 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 th e standard. According to the commenters one of the fundamental probl ems with using Method 202 for condensable PM measurements is that the result s are overwhelmingly driven by sulfate and nitrate compounds, which have nothing to do with metal HAP emissions. A ccording to the commenters, Method 202 is also problematic because of its high bias tendencies; the method is intended to provide a measure of condensable “primary particulate,” which is not PM at stack conditions but which condenses upon cooling and dilution in the ambient air to form PM, as opposed to “secondary particulate,” which forms later as different compounds react and combine in the atmosphere over time. The commenters acknowledge that one might argue over the merits of requiring sources to in clude condensable PM as part of a measure to control ambien t particulate/haze but assert that Me thod 202 is prone to biases due to SO 2 artifact formation (again, someth ing that has nothing to do with metal HAP) that make the results especially unreliable in conjunction with the long run times proposed under this rule. According to the commenters, while Method 202 was revised to include a nitrogen purge and an initial dry impinger (which is quickly wetted with condensation from th e flue gas) to reduce these artifacts, the remaining SO 2 related artifacts can be significant at low levels. Also, accordi ng to the commenters , because of the bias, extending the run time does not necessarily impr ove 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 stat e that recent studies have shown the SO 2 -related artifact formation to be particularlyacute 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 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 C onference, Chicago, Illinois (June 8-10, 2011).

Comment 19: Commenter 17821 states that although the re visions of Method 202 finalized in 2010 have been demonstrated in the laboratory to reduce sulfat e and other artifact formation, the EPA’s data show that it does not completely eliminate the high bi as associated with the test method: “EPA reported experimental results that showed the dry impinger modification to Method 202 reduced sulfur dioxide artifact formation by more than 90%.” See Method 202 Assessment and Evaluation for Bias and Other Uses Evaluation of Stakeholder Recommenda tions August 4, 2006 through April 17, 2007.

Comment 20: Commenters 18935 and 18034 note that the ne w version of Method 202 published in December 2010 is substantially different from Method OTM 28, which was used to generate ICR data. The commenters express concern that the proposed ru les have been developed from a dataset derived from slightly different methodology than that which will be used to demonstrate compliance with the proposed rules. Given the different train configura tions and operating temper atures, the commenters suspect that OTM 28 data are not directly comparable to Method 202 and therefore sources may have difficulty planning or demonstrating complian ce without substantial comparative testing.12 Comment 21 : Commenter 17820 states that Method 202, rece ntly 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 resulting PM m easurements questionable.

Response to Comments 16 - 21: The final rule does not require th e measurement of condensable PM as a part of an alternate equivalentstandard for non-Hg metals, so we need not address these comments.

6. Comments related to fre quency of stack testing.

Comment 22: Commenter 17775 states that the EPA must cl arify 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 comment er agrees that Hg testing should not be required any more frequently than annually. However, according to the commenter, there is no reference to this annual tes ting in the proposed rule. Instead, according to the commenter, the rule requires testi ng either monthly, or every other m onth, 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 re duce all stack testing to no more freque ntly than annual. According to the commenter, there is no reason to require Hg testing in addition to “individual or total HAP metals” testing.

Response to Comment 22: In the final rule, annual Hg testing is required as part of demonstrating the continued applicability of the LEE provisions for a unit that qualif ies as an LEE for Hg. For units with Hg CEMS or sorbent trap monitoring systems, Hg pe rformance tests are not required on an annual basis, although the monitoring systems will be subj ect to ongoing QA, including RATA tests.

Comment 23: Several commenters (17730, 17775, 17808) express concerns about the number of stack tests required under the proposal’s stack tes ting compliance options. Commenter 17808 expresses concerns about the monthly or bi-monthly stack tes ting requirements in the pr oposed rule for units not measuring emissions continuously. For example, the commenter notes, liquid oi l-fired EGUs would be required to test for all HAP metals on a monthly basis if they do not have a PM control device installed, or once every two months if they do have a PM c ontrol device. Additionally, the commenter notes, they would need to test for HCl and HF on a monthly basi s 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 fre quency of testing will place a significant cost burden on plant operators. According to the commenter, stack testing can also be unsafe for testing personnel during harsh weather conditions, particularly the cold winter months. Finally, according to the commenter, inflexible testing sche dules may induce units to run solely for testing purposes, leading to increased emissions. In additi on to company costs and staff time, the commenter notes that state-level envi ronmental regulators may need to be on si te to witness the tests and expresses concerns that the large number of units affected by the rule and the propose d testing frequency could make staff availability a significant issue. The comme nter is also concerned th at this could result in delayed compliance testing or not being able to disp atch a unit (that has no t been able to schedule required compliance tests). In an e ffort to balance these concerns w ith the need for reliable compliance demonstrations, the commenter recommends that all st ack testing requirements be no more frequent than quarterly under standard operation (i.e., unless boile r operations or characteri stics are substantially altered, in which case ini tial testing should be rep eated). The commenter believes that quarterly stack testing in combination with parame ter monitoring should be enough to ensure that a unit is operating within the required limits because quarterly testing would capture season al variations in operation while not unnecessarily repeating tests at the same c onditions. Commenter 17730 characterizes the proposed13 monitoring option for sources not using CEMS as excessive and overly burdensome because the commenter believes the requirement to conduct stack testing either monthly or bi-monthly is a very expensive and time consuming operation, especially when testing at the very lo w levels necessary to comply with the proposed MACT standards. The comme nter states that the sampling times that will be necessary to collect enough sample volume to reco rd values over the method detection limits will require extended hours of testing operations, and the extended hours of testing further increase compliance costs. Commenter 17730 believes that comp liance with monthly stack testing requirements will put sources in a nearly continuous mode of stack testing. The comment er recommends that the agency consider requiring stack testing on anannual basis combined with an appropriat e level of parametric monitoring and defined operating limits becau se such requirements are adequate to ensure compliance and to protect public health and the e nvironment. Commenter 17775 also expresses concerns with the proposal’s stack testing opt ions 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 te sting in its proposed ICR. The commenter references the EPA’s supporting statement for the February 2011 proposed ICR describi ng the existing source requirement as testing with Method 29 initiall y and every 2 years ther eafter. [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 st ates that the proposed frequency of testing is by defin ition arbitrary and capricious and c ontends that EGUs demonstrating initial compliance through stack testing and confirming compliance by monitoring and responding to appropriate operating parameters should not need to conduct additional stack tests more frequently than annually, unless the EGU’s fuel type or controls ch ange. 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 ac knowledges that the proposal allo ws some provisions for reduced testing, but counters that the 50 percent criteria for qualify for these provisions makes them too restrictive to be useful.

Comment 24: Comment 18498 states that the frequency of the additional performance testing requirements is not consistent with the expected variability in stack emissions. Units without add-on control systems are required to complete stack test s less frequently than uni ts with add-on control systems. According to the commenter, for units wit hout 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 choos es to use the alternat e standards for certain subcategories, the commenter recommends periodic fuel analysis to determine if a signi ficant change has occurred since the previous performance test. Accord ing to the commenter, if there is a significant change of fuel HAP concentrations then additional emi ssions testing might be warranted butthe source’s expected removal efficiency should also be taken into considerat ion to minimize unnecessary testing. The commenter believes that annual performance testing is sufficient to demonstrate proper ope ration of control devices and has historically been sufficient.

Comment 25: Commenter 18498 states that because many liqui d oil-fired sources operate infrequently and only during peak demand periods for liquid oil-fi red sources, the proposed testing magnifies the burden of frequent testing. The commenter notes in the preamble the EPA found that for liquid oil-fired units, no correlation was found between non-Hg meta llic 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 charac teristics and thus it would be more meaningful to assess fuel characteristics and use that information to determine whether addi tional emission testing is needed.14 Comment 26: Commenter 18025 states that they support th e proposal to allow existing sources the option to comply with input- or ou tput-based standards, and recommend that the EPA maintain this flexibility in the final rule. However, the co mmenter believes that the proposed compliance demonstrations are unnecessarily frequent, and reco mmend quarterly testing fo r all HAP. According to the commenter, quarterly testing provides the ne cessary performance guarantee, while balancing the substantial costs of stack testing.

Response to Comments 23 - 26: In response to comments, the final rule has been amended to include quarterly periodic testing and retains the option to comply with input-or output based standards for existing units. For liquid oil-fired units that use th e quarterly performance test option, the source will also need to develop a site-speci fic monitoring plan to ensure thatoperations between tests remain consistent with the operations dur ing the performance test. Please se e the final preamble for further discussion.

Comment 27: Commenter 17880 supports the requiring of coal -fired, IGCC and solid oil-derived fuelfired units to conduct HAP metals and PM testing at least every 5 years, us ing 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 test ing every 2 months to demonstrate continuous compliance.

Comment 28: Commenter 17191 states that for IGCC units, th e 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-combus tion PM controls are not used in IGCC systems. Commenter 17191 states that PM is captured “upstream” of the combus tion turbine in the gasification phase and that such a design confi guration should not be used to re quire monthly stac k testing under the Method 29 compliance option.

Response to Comments 27 - 28: In the final rule, if a PM CPMS is used, the source must reestablish the operating limit by conducting a test every year, not on a 5-year basis. Th is approach recognizes that the operating limit associated with the PM CPMS is a surrogate operational requirement that does not provide the same degree of assurance as a direct measurement of the emissions limit, and needs to be reestablished over time. With respect to the frequency of tests where continuous monitoring is not used to demonstrate compliance, the final rule does not disti nguish between units with or without controls, so the concerns on how to classify IGCC combustion controls are inapplicable.

7. Comments related to derating units.

a. Compliance Plans to temporar ily derate units while air pollution control upgrades are completed.

Comment 29: Commenter 17402 states that the EPA should clarify that stack testing may be performed at loads where facilities can meet all emissions and operating parameters because some upgrades required to meet certain MACT standards may not be fully operational as of the compliance deadline, and the commenter believes that compliance prior to completion of air pollution control upgrade projects can only be achieved by operating su ch units at reduced load. Comm enter 17402 requests that the EPA clarify that “maximum normal operating load” unde r the proposed performance test guidelines can15 include short-term, full-load operating restrictions if such generating load restri ctions are necessary to ensure compliance in advance of completion of air pollution control upgra des. Commenter 17402 notes that in proposed section 63.10007(c) , the EPA specifically allows for the conducting of tests at “differing operating limits,” implyi ng that the EPA expects the operating load to be somewhat flexible, and the commenter states that the EPA should not require operations during a performance test which the operator knows will cause a violation. Instead, th e commenter requests that the final rule allow operators to choose an interim co mpliance operating level for up to 3 years so that the operating limits set based on the most recent performance test well temporarily limit maximum capacity to 110% of the operating load achieved during the most recent performance test.

Commenter 17402 additionally requests provisions in th e final rule that would allow facilities that choose to restrict load (while ai r pollution control upgrades are insta lled) to resume operations at the pre-MACT, full-load capacity upon demonstrating comp liance at the true maximum capacity during a periodic performance test. The commenter notes that the EPA has supported inte rim control strategies previously, including volunt ary capacity reductions.

Response to Comment 29: The EPA believes the proposed and final rules already provide for this type of flexibility. If a source adopts a de rate restriction as a condition of its federally enforceable operating permit for a source, then testing at full load for th at 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 comp liance with this rule would be part of the action that a source would need to take in order to demonstrate compliance.

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

Comment 30: Commenter 17402 requests, regarding temporary measures to administratively derate a unit to a generating capacity that can comply with MACT standards while air pollution contro l upgrades are installed, that the EPA provide clarification on the implications of such a compliance strategy under the NSR program. The commenter believes that once the emissions controls are installed and fully operational and the facility ends th e voluntary capacity reduction, preven tion of significant deterioration (PSD) or NSR should not be triggere d provided that there is no significant increase in emissions from 2 consecutive calendar years of operations prior to the interim control strategy’s implementation. According to the commenter, since “baseline actual emissions” are defined as any consecutive 24-month period from the 5 years prior to the start of constr uction, an operator could reasonably choose 24 months from the period preceding the inte rim control strategy’s voluntary capacity reduction, provided that construction started within 3 years of the interim control strategy im plementation. The commenter states that “increase” is defined as the difference betw een baseline and potential annual emissions, where potential is the maximum projected em issions in any of the next 5 year s. 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 em issions in question would decrease. Given the clear emissions reductions, and conformitywith existing regula tions, the commenter requests that the final rule confirm that the use of an interim control stra tegy 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 im plementing 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 and policy interpretations under the NSR program.

8. Comment related to bypass requirements – CEMS.

Comment 31: Commenter 17675 states that the requirement in section 63.10010(a)(4) for installing, operating, and maintaining a complete CEMS system on a bypass stack is not appropriate for EGUs that only use the bypass stack for a short time during start ups and shutdowns because such a requirement is excessive, unnecessary, and difficult to maintain in a state of readin ess for a few hours of usage on an occasional basis. The commenter believes that altern ative monitoring methods such as data substitution techniques similar to those used in 40 CFR part 75 or fuel sampling for Hg during startups and shutdowns must be allowed rather than requiring installation of a duplicate and seldom utilized CEMS system for a startup bypass stack.

Response to Comment 31: The EPA has modified the bypass st ack monitoring requirements. Under 40 CFR Part 75, the EPA allows the use of a maximu m potential concentration value on a bypass stack. That approach works within the br oad context of an emissions tradi ng 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 th e bypass stack consistent w ith the proposed rule. The other is to treat any hours of bypass stack emissions as periods of monito r downtime. In general, this is consistent with the EPA’s approach to startup and shutdown periods, in that we treat those periods as subject to a work practice standard. That generally obviates the need to monitor the bypass stack as the emission limit does not apply during the periods wh en the source is most likely to operate a bypass stack. Use of a bypass stack at times when the source is operating and the emi ssion limit applies (i.e., other than startup or shutdown pe riods), will mean a failure to m onitor emissions at all times in accordance with the rule.

9. Comments related to duplicative testing.

Comment 32: Several commenters (17820, 17868, 18014) state that the EPA is requiring stack tests for both the pollutant and surrogate and that this requirement is superfluous. The comm enters state that the EPA has established alternative limits for compliance for various HAP groups. For example, state the commenters, coal-fired units may choose to meet eith er 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 wi th section 112 of the CAA, there is no need to test for both the pollutant and surrogate. The commenter s indicate that a performance te st should only be required for the pollutants and surrogates with which the s ource is choosing to show compliance.

Comment 33: Commenter 17775 believes that the EPA’ s proposed compliance demonstration, recordkeeping, and reporting requirements are flawed because the applicability of many provisions is unclear and the EPA fails to provi de any rationale by which the provi sions’ basis and purpose might be discovered. The commenter states th at for the first time in any MA CT, and without explanation, the EPA proposes to require that EGUs exercising the opti on to comply with a surr ogate 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. Accord ing to the commenter, th ese duplicative testing requirements are inconsistent with the agency’s legal and policy justifications for the use of surrogates and are otherwise unsupportable. The commenter states that for EGUs that opt to comply with a chosen17 emission limit using stack testing, the EPA (again without explanation) requi res stack testing no less frequently than every other month, requires compliance with established “ operating limits” on control devices, and requires compliance with fuel input limits. According to the commenter, the agency provides no rationale for the selected frequency of stack testing and fails to include the associated cost in its proposed ICR. According to th e commenter, the requirements are unn ecessary and inconsistent with the EPA’s prior position on use of surrogates, nume rous preamble statements claiming cost savings by use of surrogates, and the proposal to allow EGUs to choose whether to comply with a HAP limit or, where surrogates are proposed, the surrogate limit. The commenter states that where the EPA has demonstrated the appropriateness of use of a surroga te and selected an emission limit for that surrogate that is consistent with what the bestsources achieve, there is no basis fo r 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 (includi ng the following portions and language: the agency summarizes the D.C. Circuit decision in National Lime Ass’n , 233 F.3d 625: If these criteria are satisfied and the PM emission standards refl ect 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 eval uating whether the surrogate standards we propose to establish in this proposed rule are reasonable. 76 FR 25,021/3. The EPA has satisfied the criteria for use of PM, HCl, and 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 emission limit for a HAP that is consistent with what the best sources achieve, there is no basis for also requi ring testing of a surrogate. Comm enter 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 w ould be reached were the metals to be regulated directly,” and that the “u se of a surrogate ‘eliminates the cost of performance testing to comply with numerous standards for individual metals” (citing F.3d at 637 (quoti ng 64 FR 31,916/3)). According to the commenter, the Court found the EP A’s use of the surrogate reasonabl e (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 sugge sted any purpose. The EPA also has not required such duplicative testing in any othe r rule that relies on surrogates.

Commenter 1775 also asserts that requ iring testing for both th e HAP and surrogate is inconsistent with Tables 1 and 2, which, according to the commenter, es tablish surrogate emission li mits 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 completelyunreasonable. The commenter states that the tests have no regulatory purpose under the proposed rule and the EPA’s preamble summary identifies none. The commenter states that the EPA discussed the co st savings associated w ith using surrogates and refers to 76 FR 25,038; at 25,039; at 25,059.

Commenter 17758 also disagrees with th e proposal’s requirement to test for surrogates at units using the stack testing compliance option for non-Hg HAP meta ls and HCl, because according to the commenter, if a utility has chosen to demonstrate ongoing complian ce by directly measuring the regulated HAP, it is superfluous to require any further testing of surrogates, and under the stack testing compliance option the agency should specify that pe rformance tests only for methods ne cessary to measure the regulated HAP are required.

Comment 34: Commenters 17881 and 18428 state that where a surr ogate 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 estab lishing a filterable PM limit and demonstrating compliance with PM CEMS, and similarly, 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 requi re testing for surrogates anyway. For example, notes the commenter, proposed section 63.10006(d) requ ires 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 applicab le 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 preamble, 76 FR 25,051. A ccording to the commenter, where the EPA has demonstrated the appropriateness of use of a surroga te and selected an emission limit for that surrogate that is consistent with what the bestsources achieve, there is no basis fo r also requiring the source to test for the applicable HAP. The commenter asserts that where a source chooses to comply with the HAP limit, testing for surrogates is unnecessary and unreasonable. The comme nter 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 the EPA describes these duplicative testing requirements in the preamble, the EPA provides no rationale to support them.

Comment 35: Commenter 18015 states that section 63.10000(c)(1 ) of the proposed rule provides that for all coal-fired and solid oil-derived fuel-fired un its the initial performance testing is required for all pollutants. According to the commenter, this implie s 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 perfor mance tests for both PM and all individual HAP metals. According to the commenter, this is inconsiste nt with the intent established in the preamble that facilities must conduct performance tests to demonstrate compliance w ith all applicable emissi on 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 em ission limit, and the HAP metals emission limits are no longer applicable. The commenter asserts that this is supported by the fact that continuous compliance is based on PM CEMS or other PM-related complian ce mechanisms. Conducting the additional emission tests for individual HAP increases the cost and labor time for no a dded benefit, ac cording to the commenter, because the facility w ill be complying with the PM emission limit, not the individual HAP metals emission limits. Thus, states the commente r, initial compliance sh ould only apply to the applicable emission limit and result in testing of only the surrogate polluta nt, PM, not HAP metals.

Comment 36: Commenter 18034 states that proposed sect ion 63.10006 requires coal-f ired and solid-oil derived fuel-fired EGUs to perform testing for non-Hg metal HAP even if the source elects to use total PM as a surrogate for the non-Hg metal HAP limits. The commenter states that similarly, the same source categories are required to perform HC l testing even if the source elects to use SO 2 as a surrogate for HCl. Furthermore, the commenter states, on-goi ng compliance for units that are not equipped with CEMS is through monthly or bi-mont hly stack testing for pollutants th at are the primary HAP when the source is using a surrogate limit for the HAP. Acco rding to the commenter, the preamble (76 FR 25029) states that the purpose of the stack testing is demonstrate compliance with all applicable emission limits; however, if a coal-fired EGU is using the PM surrogate option, the unit is not subject to the non-Hg metal HAP limits and a demonstration of compliance is not necessary. The same issue applies to an EGU using SO 2 as a surrogate for HCl, the commenter states. According to the commenter, the EPA provides no explanation for why the pr oposed rule requires sources to te st for pollutants for which there are no applicable emissions limits. The commenter also asserts that section 63.10006 is inconsistent with the EPA statements in the preamble that use of the PM surrogate would eliminat e costs associated with conducting performance testing for non-Hg metals (76 FR 25039). According to the commenter, these19 additional testing requirements pr ovide no added compliance assuranc e 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 overse eing required stack testi ng. The commenter asserts that if these overlapping testing prov isions are inadvertent, then the EP A 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 in tended purpose of the test results.

Comment 37: Commenter 17868 states that the EPA mu st remove the requirement for SO 2 performance testing. According to the commenter, proposed secti on 63.10006(h) and (i) include testing provisions for SO 2 for units without SO 2 CEMS. According to the commenter, th e 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 co mplying with the HCl standard. In addition, according to the commenter, the proposed rule doe s not provide any procedure for SO 2 performance testing or an SO 2 emissions standard other than t hose 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 32 - 37: In response to comments, the fina l rule has removed all requirements for testing of both the individual HAP and the surrogate. Facilities co mplying with a surrogate limit do not have to perform periodic te sting for the corresponding HAP.

10. Comments related to non-Hg metal standards.

Comment 38: Commenter 17775 supports the proposed inclusi on of an option for non-Hg HAP metals stack testing (i.e., Method 29) but contends that the proposed ru le contains duplicative testing requirements under the non-Hg HAP metals stack testi ng option. The commenter beli eves that to make it a reasonable option, the final rule must reflect several adjustments:

1. First, the commenter believes th e 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 opti on of meeting either a PM or non-Hg metals limit. Testing for PM when that option has not been selected and no limit applies is nonsensical. The commenter concludes th at requiring testing for a surrogate in addition to the regulated HAP is beyond the agency’s authority. 2. The commenter believes that the EPA should re -evaluate the proposed operating parameter requirements because the operating parameters specified for non-Hg metal controls are not sufficiently connected to metals rem oval or sufficiently flexible to be used as enforceable limits. The commenter contends that secondary power is not directly related to PM removal and that pressure drop and liquid flow will vary with load. Moreover, according to the commenter, at the level of the proposed standard, metals control may not be very sensitive to liquid flow . The commenter states that the final rule must allow for adjustment of load-dependent operating parameters to account for load changes, and the final rule should use the op erating parameters as indicators, not enforceable limits. 3. The commenter states that the final rule should ma ke clear that EGUs combusting a single fuel type are not required to make any determination regarding that fuel under section 63.10011(b)(3)(i) (requiring determination that the fuel type or mixture has the highest conten t 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 liqui d oil-fired EGUs in section 63.10005(c)(4) and section 63.10011(c)(1), those provisi ons apply only to li quid oil-fired EGUs complying through fuel analysis. 4. Commenters 17775 and 17868 state that the final rule should specify minimum detection limits for laboratory analyses and pr ovide procedures for calc ulating combined concentr ations of single metals and total non-Hg meta ls. According to Commenter 17775 the data collected in the 2010 ICR indicated the reported detection lim its for laboratory analyses were hi ghly variable even for data for the same metal and from the same laboratory. To determine compliance on a consistent basis, the final rule must specify minimum detection limits and a procedure for combining front and back half fractions to report total concentrations.

Response to Comment 38: We agree that maintaining low met hod detection levels is critical in demonstrating compliance with the a pplicable emissions limits for this MACT rule. We disagree that we can provide default values for method detection leve ls to use in determining compliance since there are many site-specific factors that can affect method detection levels for any one set of data. In achieving the most effective tes ting including method detection leve ls commensurate with compliance determinations, the tester must consider multiple technical and procedural choices and analytical laboratories used in any test progra m. There are some testing factors th at we believe ar e appropriate for the rule to address including minimum sample volum e and some specific analytical finishes; however, those required elements do not l ead directly to maximum method de tection levels. The EPA agrees about the need for a procedure to co mbine the front and back half frac tion and has revised the final rule to address this concern. It is di fficult to define maximum acceptable method detection levels that would adequately account for the myriad of test matrices, in terference, various types of analytical finishes, and final analytical volumes that could very well be eff ective for all situations. Instead, the rule includes a requirement that specifies how to use method detection level informa tion in calculating compliance with the emissions limits. The language in the final rule is similar to that found in the Mercury cell Chloralkali 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 detec tion capabilities for fuel sampling and analyses, the removal of the proposed fuel input operating requirements in the fi nal rule renders the concerns about identifying highest fuel mixture and supplem ental fuels no longer relevant.

11. Comments related to HCl standard testing.

Comment 39 : Commenter 17775 expresses the following concer ns with the HCl st ack 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 reasonab le 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 op tion because there is no basis fo r testing of the surrogate SO 2 at a unit that is complying with the HCl standard. In addition, the commenter st ates, 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 speci fied for HCl are not sufficiently connected to21 HCl removal or sufficiently flexible for use as en forceable limits. The commenter states that the EPA also must allow for adjustment of load-dep endent operating parameters to account for load changes and should use the operating paramete rs as indicators not enforceable limits. 3. Third, according to the commenter, the EPA should make clear that EGUs combusting a single fuel type are not required to make any determinati on regarding that fuel under section 63.10011(b)(1)(i) (requiring determination that the fuel type or mixture has the highest chlori ne 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 onl y to liquid oil-fired EGUs complying through fuel analysis. 4. Fourth, the commenter re-iterates previously stated concerns aboutthe frequency of stack testing required under the stack testing compliance option but relates the concerns to the HCl standard rather than HAP metals standard.

Response to Comment 39: The final rule has been amended to re move the requirement for testing of both SO 2 and HCl. Operational parameter requirement s specified for HCl have been removed. The frequency of periodic testing has been reduced to quarterly testing. With the removal of the proposed fuel input operating requirements in the final rule, the concerns about identify ing highest fuel mixture and supplemental fuels ar e 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 concentrati on 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 signi ficant despite sampling on different dates and taking into account variances in chemical composition of coal. According to the commenter, this data supports the high biases of chlorides from FGD systems running wi th high equilibrium chloride concentrations. Furthermore, asserts the commenter, the test result s 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 usi ng Method 320. (See 17807-A1_Table_2_&_3.doc.)

Response to Comment 40: The EPA has amended the final rule to include the option for periodic HCl testing by Method 320.

Comment 41 : Commenter 17696 states that coal-fired EGUs without an HCI CEMS should be allowed to reduce the frequency of HCI stack testing or fuel analysis if the E GU’s initial performance test is less than 50% of the standard. Accordi ng to the commenter, for coal-fired EGUs that do not install an HCl CEMS, proposed section 63.10006(k) and (l) require pe rformance 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 than50% 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 suchlow HCl emission levels are able to do so as a result of the chlorine content inhere nt in their fuel. As long as there is no change in fuel, the commenter asserts, there is no expected change in the leve l of HCl emissions. The commenter suggests that an alternative approach for s ources testing at less than 50% of the standard is to require subsequent performance tests less frequently, such as semi annually. Commenter 17696 also states that a 50% threshold would be consistent with the threshol d for reduced frequency of monitoring in proposed section 63.10006(o) and states that operating parameters and fuel an alysis demonstrating no material changes in the fuel supply are sufficient to assure compliance with the app licable HCl emission limit between semi-annual performance tests.22 Response to Comment 41: The final rule has been amended to re quire quarterly 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 ensure compliance. However, the final rule adopts a LEE provision for pollutants other than Hg that enables a s ource to move to annual tes ting if all tests for the applicable pollutant over a 3-year period are less than 50% of the emission limit.

Comment 42 : Commenter 17754 requests that the EPA revise the compliance demonstration requirements applicable to EGUs achieving LEE status for Hg, and th e commenter contends that the final rule should provide an additional compliance option for LEEs with Hg emissions below 50% of the applicable LEE threshold; according to the commenter, such very low emitting EGUs should be allowed to demonstrate continuous comp liance through annual stack testing and should not be required to conduct monthly fuel analyses.

Response to Comment 42: The LEE threshold for Hg remains at the 10% threshold that the EPA proposed (or the total mass limit of <29 pounds per year, as requested by another commenter for consistency with existing state rule s). However, there is no monthly fu el analysis requirement for units that qualify, but rather an annual test, consistent withthe commenter’s recommendation.

12. Comments about concerns with combined stack.

Comment 43: Commenter 18932 states that the use of combined stacks will undermine monitoring and enforceability because the stringency and practicable enforceability of an emission standard depends largely on the precision of its associated monito ring regimen. The commenter asserts that monitoring requirements that do not reflect appr opriate averaging times based on app licable emissions or air quality standards do not assure continuous compliance with those standards. Si milarly, the commenter states, to assure that each EGU meets all ap plicable 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 th at the proposed rule will accurately measure and record emissions from individual sources and believes that the agency must clarify monitoring requirements in cases where multiple individual units co -located at a single facility exhaust through a combined stack. According to the commenter, this problem arises in two ways: (1) when multiple emission sources vent gases through se parate flues that are physically lo cated within the same stack; and (2) when multiple emission sources vent commin gled 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-locat ed within a combined stack. Acco rding to the commenter, the rule should make it clear that, in such cases, individual flues should be m onitored separately, since there is no impediment to doing so. According to the comment er, the combined stack, in these instances, is simply the structural unit that encloses the flues, which are the separate, functional, exhaust gas emission points.

The commenter also asserts that there are many other instances wher e the exhaust gases generated by individual EGUs enter, commingle, and exhaust through a common stack. According to the commenter, to assure that each EGU that vents through a combined stack complies with applicable MACT standards, the EPA should require separate monitoring and re porting of each unit’s HAP and surrogate emissions prior to the exhaust gases commingling in the stack, such as prior to the stack breeching. According to the commenter, a monitoring regime that does not re quire each source to separa tely monitor and report its HAP emissions will not assure that each co vered EGU complies with all applicable MACT23 requirements. The commenter provides an example of monitoring emissions at both types of combined stacks.

Response to Comment 43: A common stack with indi vidual flues (and no co mmingling of emissions from the individual units) will require monitoring and testing on each separate gas stream. Each flue would be the monitored or tested location at any unit that operates in such a manner. For the more typical common stack situation in which emissions fr om multiple units may be released through a single combined stack, the rule allows for either separate monitoring at the unit level or monitoring of the combined emissions. In the latter case, any failure to meet the standard at th e combined location would be deemed a separate compliance issue for each i ndividual unit to which th e standard applies.

13. Comments about using total PM.

Comment 44: Commenter 17621 states that the use of tota l 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 meas ure only the filterable portion of total PM, and the manual stack test methods for both filterable and condensable PM are of uncertain accuracy.

Commenter 17621 also states that the EPA’s rationale for including condensable PM in the MACT limit to represent selenium is not supported.

Comment 45: Commenter 17877 states that the proposed to tal 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 filte rable PM actual levels over a range of unit operating levels as would a less accurate PM CEMS. Optical, light scatte r, 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 e xpensive, but could be used to develop a body of data that is both accurate and inclusive of operatin g variability over long periods. The commenter is not aware that any such data was used to inform the development of the PM standard, but contends that this analysis should be performed on the 12% of existi ng units identified in the development of the PM surrogate for HAP metals.

Response to Comments 44 - 45: As discussed in detail in other sections of this document (see 4F01 responses), the requirement for total PM test ing has been removed from the final rule.

14. Miscellaneous comments regarding testing.

Comment 46: Commenters 17621 and 17758 state there is a need to establish test methods that can measure the HAP or surrogates accurately at th e actual stack gas concentrations. Commenter 17621 refers to an EPRI study that eval uated whether an accurate measurement could be obtained by most of the ICR laboratories at those emission levels usin g the standard methods required by the ICR (Appendix B; Method Sensitivity for ICR Data Usage and Compliance with Proposed MACT Limits). The commenter concludes that the method sensitivity is not adequate to qu antify HAP or surrogates at many of the new unit limits that EPA is proposing. Accordi ng to the commenter, the reason for this is that the EPA’s floor procedure relied on outli ers and did does not take into account method performance with actual stack gas samples.24 Comment 47: Commenter 17725 states that in section 63.752 0(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 fo r each method and/or provide alternative minimum sample volumes for each method, taking into account representative analytical detection limits and emissions standards that are proper ly adjusted for non-detect values.

Response to Comments 46 - 47: The EPA reviewed the minimum sample volumes required for the emissions limits and, based upon the present analytical capabilities, concluded that the sample volumes specified are appropriate. In the future, facilities withthe capabilities to meet the stack detection limits in less than required volume s may request alternative test methods per 63.8(f).

Comment 48: Commenter 17731 states that the proposal to require “total PM and HAP metals testing during the same compliance test period and under th e same process (e.g., fuel) and control device operating conditions at least once ev ery 5 years” (citing 76 FR 25029/2) , has not been justified given that it is highly unlikely an EGU could demonstrat e compliance with the total PM limit while exceeding the individual PM and HAP metals limits.

Response to Comment 48 : The final rule will not require testing of both the filterable PM emission limit and the corresponding HAP metals standard. The s ource will conduct the test th at is applicable to the standard with which the s ource has elected to comply.

Comment 49: Commenter 19033 states that th e Table 8 data recording re quirements 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 record ed at 15 minute intervals during each test run. Three test runs are then require d. According to the commenter, since Table 8 requires that subse quent data is to be maintained in 12-hour block averages, it would seem the EPA wants 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 usi ng Method 26A needs to collect a minimum of 0.75 dscm. The commenter doubts that it will take 4 hours to meet the minimum test run sample volume for either pollutant and therefore they recommend that Table 8 be amended from 12 hours to the time period required to perform three test runs.

Response to Comment 49: For the 12-hour block average limits discussed in this comment, the EPA notes that the final rule does not require data reporti ng of these parametric data. Generally, the only operating data reported under the final rule are PM CPMS data (see the final preamble and other responses pertaining to the potential for liquid oil-fired units to requi re operating parameter data in certain situations). The source will collect hourly data during the perf ormance test, identify the highest hourly average during the test, and th en record data during operations on an hourly basis and develop a rolling 30-day average of the PM CPMS data. There is no intent that the 30-day average represent the length of the Method 5 or 29 stack test.

Comment 50: Commenter 18963 states that if the EPA does notagree to revise the proposed rule to provide that if an owner/operator of an affected EGU elects to de monstrate compliance with total nonHg HAP metals by using the PM surrogate, then su ch owner/operator is not required to conduct performance tests for PM and total non-Hg HAP simu ltaneously, the proposed rule must nonetheless be revised to avoid additional ambigu ities. Specifically, according to the commenter, the proposed rule lacks clarity related to the requirement to conduct periodic emissi ons 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 commen ter, the proposed rule fails to clearly address25 a facility’s compliance status if it simultaneously conducts stack tes ting for HAP metals and PM during the same compliance period, and demonstrates complian ce with the applicable st andards for one of these two pollutants.

Response to Comment 50: The final rule has been amended to re move the requirement for testing total non-Hg HAP metals if the source elects to meet th e filterable PM standa rd (and vice versa).

Comment 51: Commenter 18021 states that any performa nce testing of an EGU needs to be representative of the uni t’s actual operation. According to th e commenter, EGUs ramp up and ramp down based on demand, and the performance testing needs to be based on a test pl an that will, in the end, reflect the unit’s actual operatio n. According to the commenter, that unit’s specific te st plan needs to make it possible to “certify” and have the docum entation demonstrating that the EGU configuration, control devices, and material/fuel have remained constant since the prior performance test was conducted (section 63.10005(d)(1)(i ii)). According to the commenter, th is protocol would be consistent with section 63.1 0007(c). The commen ter asserts that the flexibil ity to address normal operating conditions should be clearer. The co mmenter provides that if an affect ed 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 ope rating load, the affected source w ould be penalized at those units where over-controls were provided to allow for a compliance buffer.

Comment 52: Commenter 18015 opposes the proposed requirem ent for periodic compliance testing for several individual HAP for which the proposed rule designated a single surrogate. The commenter believes that demonstration of continuous compliance for that surrogate based on data collected with CEMS should assure compliance with the requirements for the individual HAP that surrogate represents.

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 sh ort 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 abil ity to conduct performance testing at loads other than maximu m, in case alternate operating limits for those periods are desired. For the 30 day or other longer term performance testing averaging periods, the fina l rule does specify a minimum process operation but expects that measured emissions values to represent normal operations. As noted elsewhere in the responses to comment s, emissions created during process startup and shutdown are not included in the compliance calculations. All othe r periods are considered normal process operations during which the emissions limits apply.

The final rule has been amended to remove the requi rement for testing for both the HAP and a surrogate. for the final rule provides multiple alternative emissions limits and you w ill have to demonstrate compliance only with the limit for which you are demonstrating compliance.

Comment 53: Commenter 18015 states that a testing grace pe riod, similar to the 40 CFR part 75 RATA grace period provisions, should be applied when a sour ce is unable to complete the required testing by the deadline specified. Additionally, the commen ter recommends that a grace period of 720 unit operating hours should apply to sources that are unable to complete perf ormance 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 provis ions should be provided for RATAtesting 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 subpart UUU UU. The part 63 General Provisions section 63.7(a) provide for an exte nsion of the performance testing de adlines 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 54: Commenter 17881 states that clar ification is needed with re spect to what it means to “conduct all applicable perfor mance tests for PM (or SO 2 ) and non-Hg HAP metals (or HCl) during the same compliance test period” (c iting section 63.10006). According to the commenter, while this statement may make limited sense for those units demonstrating compliance via a CEMS, EGUs relying upon manual sampling methods for the surrogate will not likely be able to conduct concurrent tests for the associated HAP(s) due to limitations on sampli ng port availability, possible interferences from multiple probes inserted at a given stack plane, etc.

Comment 55: Commenter 17881 questions how, when CEMS ar e 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 relatively short duration run times associated with manual sampling me thods for non-Hg metals and HCl (citing section 63.10006).

Response to Comments 54 - 55: In response to comments, the fina l 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 tes ting for the corresponding HAP.

Comment 56: Commenter 17881 states that as currently written, section 63.10006(e) requires that the fuel factor methodology and equations in sec tions 12.2 and 12.3 of Method 19 (40 CFR 60, Appendix A-7) be used to convert the results of the perfor mance tests into units of lb/MMBtu of lb/TBtu, as applicable. According to the commenter , this section should recognize that such calculations need not be conducted if an EGU has chosen to demonstrate comp liance with the mass per uni t of electrical output emission limits.

Response to Comment 56: The final rule has been amended to clarify that only the methodology or equations required for the specific emission limit will be required.

Comment 57: Commenter 17881 states under Table 1 - Emi ssion Limits for New and Reconstructed EGUs, that the run times specified for each constituen t should be the lesser of 4 dscm or the duration required to capture a specified amou nt 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.

Response to Comment 57: The EPA does not believe a change is warranted. The run time is that needed to get at least 4 dscm. The commenter’s s uggestion would not change that because, using the commenter’s phrasing the current wording is the same as “the lesser of 4 dscm or the duration required to capture a specified amount of PM [4 dscm].”

Comment 58: Commenter 17881 questions why (under Table 2 - Emission Limits for Existing EGUs, for Coal < 8300 Btu/lb, Total PM) the run time is di fferent than the run time for existing units firing coals > 8300 Btu/lb when the PM emission limit is identical.

Response to Comment 58: The final rule has been amende d to fix the clerical error.27 Comment 59: Commenter 17881 states that (under Table 5- Performance Stack Testing Requirements for Non-Hg HAP Metals) the exhaust flow and moisture should only need to be determined if you are complying with the lb/MWh limit. According to the commenter, the O 2 /CO 2 levels should only need to be determined if complying with the lb/MMBtu standard.

Response to Comment 59: The final rule has been amended to clarify that only the methodology or equations required for the specific emission limit will be required.

Comment 60: Commenter 17881 questions whether (under Ta ble 5, for HCL and HF) 40 CFR part 60, Appendix F, Procedure 1 is really applicable to HCl and HF CEMS.

Response to Comment 60: Based on the comments received that support the use of part 75 reporting for CEMS, we have added an Appendix B to the rule to set the technical requirements for QA applicable to an HCl or HF CEMS if used under this rule. Th e procedures are largely similar to Appendix F as proposed but adapt those requirements to fit more cl osely with approaches ta ken under Part 75 so that the existing reporting infrastructure for Part 75 reporting can be easily adapted to support this rule.

Comment 61: Commenter 17881 states that (under Table 5) 40 CFR part 60, Appendix B, Performance Specification 6 conflicts with th e QA requirements in part 63, subpart UUUUU, Appendix A for auxiliary measurements.

Response to Comment 61: The final rule will be amended to provide consistency with Table 5 and Appendix A.

Comment 62: Commenter 17881 states under Table 5, for Hg, (bullet a.) Method 20B (sic) contains alternate provisions for determining the numbe r of sampling points as compared to Method 1.

Response to Comment 62: The final rule has been amended to allow the alternative provisions for sample point selection contained in Method 30B.

Comment 63: Commenter 17881 states that under Table 5, bu llet 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 complia nce with the lb/GWh limit or calculate annual mass using a flow CEMS, in which case moisture would be needed.

Response to Comment 64: The final rule has been amended to clarify that only the methodology or equations required for the specific emission limit will be required.

Comment 65: Commenter 17681 states that proposed s ection 63.10011(b)(3)(i) appears to require operators to determine the fuel mixture with the highest content of non- Hg HAP metals and asks if this determination requires distinction between types of coals (i.e., an thracite, bituminous, subbituminous, etc.) and between regions (i.e., Illinoi s Basin coal vs. Appalachian coal).

Response to Comment 65 : The final rule no longer includes this provision.28 Comment 66: Several commenters (19536, 19537, 19538) stat e that the EPA s hould strengthen monitoring requirements for acid gases because on e plausible combination of monitoring and FGD controls is omitted from the proposal. Commenters state that no periodic performance testing and operating parameter monitoring are specified for units that use CEMS but have no controls.

Response to Comment 66 : The final rule does not include the control device contin uous parametric monitoring of the proposal and replaced that monito ring 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 th e premise the frequent testing (e.g., quarterly) will ensure that sources must maintain the process an d control technologies in condition consistent with compliance performance on a continuous basis. This in cludes units that comply with emissions limits with no add on control devices. As for augmenting CE MS data with additional performance testing, we believe that CEMS data verified with periodic quality assurance testing and other quality control measures as required by the rule provide means suffi cient to demonstrate comp liance with the emissions limit on a continuous basis and independent of additional performance testing.

Comment 67: Commenter 17174 states that the term “maximum normal operating load,” as used in section 63.10007, is not defined. Accord ing to the commenter, facilities us e different fuels in different proportions, depending on many variable s 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 comme nter, the EPA should also clearly define how a source that utilizes more than one fuel should comply with this requir ement. The commenter states that there appears to be an inconsis tency between the testing conditions specified in section 63.10007(c) and (f). According to the commenter , while section 63.10007(c) requires f acilities to con duct performance tests at the “maximum normal operating load,” section 63.10007(f) require s 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 pe riod being tested. (76 FR 25108)

Comment 68: Commenter 17770 states that there is a proble m with setting an emission limit that must be achieved on a continuous basis using results fro m a periodic performance test. According to the commenter, a performance test is conducted according to prescribed conditions, i.e., steady state, full load conditions and provides a “snap-shot” of unit performance representative of those steady state conditions, and a performance test does not show how that the unit will operate under all conditions and at all levels of unit operation. The commenter states that typically, a unit will ope rate above or below the load conditions during which pe rformance tests are conducted.

Comment 69: Commenter 18935 notes that the proposed minimum sample volumes for metals and HCl will probably not yield the required detection lim its to establish compliance. According to the commenter, while a responsible emission testing firm w ill make source-specific calculations as part of test planning, the proposed sampling volumes may si gnificantly skew the antici pated cost of and time associated with compliance testing. As a responsible emission testing servi ce provider, the commenter encourages the EPA to present realistic sample vol ume and duration information so that sources can properly budget and prepare for compliance testing.

Response to Comments 67 - 69: The EPA reviewed, and adjusted as appropriate, the final emission limits and minimum detection levels so that the ru le contains appropriate sample volumes and run durations.29 Comment 70: Commenter 18021 states that the small de gree of alternative requirements with Administrator’s approval is built into the regulati on but is concisely stated. The commenter requests elaboration in at least the preamble that recognizes the variability in design and operating characteristics of EGUs allowing consideration of alternatives s upported with a demonstration during the performance tests is needed. The commenter requests that the EP A 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 comme nter’s support for rule brevity, the agency does not believe the preamble needs to ela borate on an EGU owner or operator’s ability via the general provisions in §63.8(f) to seek an alternate means of mon itoring. The agency finds the last comment moot, as the rule no longe r 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, 18831, 19032, 19041, 19114, 19121, 18023

1. Commenter supporting current or shorter averaging times.

Comment 1: Commenter 17926 supports and offers prai se for the proposed averaging times in conducting Hg-related testing. Accord ing to the commenter, currentlyMontana 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 allo w for emissions spikes of Hg. According to the commenter, the proposed averaging times by the EPA, which are averaged on a rolling basis of 30 boiler operating days, will assure that facilities are adequately complying with emissions limits. The commenter also contends that a 30-day averaging time will help to assure that facilities are avoiding time periods with periodic spikes in emissions.

Response to Comment 1: The agency appreciates the commenter’s support for the rule’s averaging time for Hg.

Comment 2: Commenter 17929 states that compliance with th e EPA’s standards for PM and Hg are not to be based on a single triplicate “independent sample” at a single “r andomly select[ed] future test condition” where the EPA has claimed it wishes to pr ovide 99 percent confidence , but rather continuous, integrative sampling every minute of every day and then averaging for a long-term, 30-operational-day period. According to the commenter, because the EPA is using a 30-day rolling average rather than a triplicate sample, the various measures that the EPA uses to account for variability in a triplicate sample are irrelevant and unnecessary. The comm enter states that ther e is no rationale for an “n” of 3 test runs in the UPL equation, for an “s2” va lue, the variance in the single-poi nt emissions data from the top units, or for a student’s t-statistic with a 99% confidence level. The commenter asserts that there is no rationale at all for the whole UPL calculation unless compliance is to be determined solely based on a single triplicate sample, which, the commenter asserts, it is not.

Response to Comment 2: The agency uses a number of statistic al tools so that poorly performing or problematic sources can be identifi ed. Basing emissions limits on the av erage result of three test runs and adjusting that result to account for most, if not all, false positive results, then setting a commensurate averaging time that accounts for brief, transient emissions spikes, focuses the agency’s resources on those poorly performing or problema tic sources, instead of penalizing inadvertent

occurrences.

Comment 3: Commenter 18421 states that the proposed proce dures permit averaging of Hg levels on a rolling 30 boiler operating day basis, which could resu lt in days when a given boiler is exceeding the NESHAP limit for Hg emissions. According to the co mmenter, the EPA should adjust the procedures for Hg CEMS to ensure continual compliance with the standards of the proposed rule.

Response to Comment 3: The agency disagrees with the commenter, for the procedures for Hg CEMS as well as Hg sorbent traps are designed to ensure continuous compliance with th e rule. As mentioned in a previous response, establishing an averaging time that accounts for brief, transient emissions spikes31 focuses the agency’s responses on those poorly performing or problema tic 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, sh utdowns 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 Tes ting Guidance,” which applies to both MACT and NSPS, makes clear that stack testing to determine compliance with these short term limits should be conducted under conditions that “are most likely to challenge the emi ssion 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 opera ting at peak capacity, and using the dirtiest fuel that it can legally burn because st ack 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 believes that actual emissions averaged over 30 days during periods when units are operating at lower capacity with cleaner fuels – are likely to be much lower.

Response to Comment 4: The comment is moot, as the rule no longer has numeric emissions limits applicable during periods of startup or shutdown.

2. Commenters supporting annual complianc e periods rather th an 30-day periods.

Comment 5: Numerous commenters (17623, 17627, 17714, 17716, 17736, 17757, 17774, 17800, 17873, 17885, 17902, 17909, 17930, 18018, 18037, 18498, 18831, 19032, 19041, 19114) state that the compliance period should be increased from a 30-day rolling average to a 12-month or 365-day rolling
average.

Commenters 17623 and 17774 state that the EPA has authority under the CAA to us e discretion to shape compliance periods and averaging times for MACT limits and suggest that the EPA use a 12-month rolling average compliance period rather than the proposed 30-day rolling average period, because a 12- month rolling average still requi res compliance reporting every month but helps limit the number of violations resulting from normal seasonal variabilityin electricity use a nd associated emissions. Commenter 17774 notes that the EPA has used 12-mont h rolling averages in a number of other MACTs (e.g., boat manufacturing and magnetic tape).

Response to Comment 5: The agency disagrees with the commenters, noting that for this rule, an averaging period of 30 boiler operating days, as oppos ed to a 12-month or 365-day rolling average, is sufficient to account for normal variability, as we ll as other brief, ina dvertent occurrences.

3. Support annual averaging due to SSM issues.

Comment 6: Multiple commenters (17714, 17627, 17718, 17757, 17800, 17925, 18831) state that the proposed rule requires utilities to m eet emissions limits at all times including periods of startup and shutdown but that the ICR stack te sting data did not include start ups or shutdowns and that it is inappropriate to establ ish limits that include startups and shutdowns. Commenters 17714 and 18831

1 EPA, Clean Air Act National St ack 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 no rmal operations, but commenters do not believe a 30- day period is sufficient to addre ss inclusion of start up and shutdown emissions. Commenter 17714 states that absent sufficient stack testing data from real operations that incl ude several periods of unit startup and shutdown across the range of uni ts included in the affected source category, the averaging period should be increased to 365 days to acco mmodate periods of startup and shutdown.

Comment 7: Several commenters (17718, 17627, 17757, 18037, 18539) note that ICR data did not encompass the full range of operating conditions including changes in operating variables (i.e., pulverizers taken out of service, fu el variability causing changes in control equipment operations, etc.) that a unit experiences in the normal course of operation. According to the commenters, the EPA can alleviate some of the effect of variability on unit emissions that wa s not accounted for in the 2010 ICR testing by allowing annual averaging, while still achieving the same emission reductions.

Comment 8: Commenter 17925 states that while the EPA indi cates the 30-day averaging time addresses concerns with startup, shutdown, and malfunctio n (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. A ccording to the commenter, this is understood by considering the number of hours involved in a startup and the impact of treatm ent equipment coming to equilibrium with the changing temperatures, gas flow rates and pollutant loadings.

Comment 9: Commenter 17800 states that the utility industr y 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. Accordi ng to the commenter, the EPA should allow reasonable exemptions for startup, shutdown and malfunction conditions or lengthen the 30-da y rolling averaging time. The commenter notes that the State of Illinois has adopted a Hg standard that is based on a 12-month rolling
average.

Comment 10: Commenter 17736 states that a 30-day rolling average, especially if SSM periods are included, makes compliance nearly impossible. A ccording to the commenter, a few hours of ESP downtime can destroy a 30-day rolling average. Th e commenter suggests that the use of a 12-month averaging period helps to ensure that compliance results will not be skewed by SSM periods. The commenter states that an annualized averaging period is equally effective in re ducing the total emissions as is a 30-day period.

Comment 11: Commenter 17758 states that the EPA’s assu mption that providing a 30-day averaging period will smooth out any emissions increases associated with infre quent startup and shutdown periods is predicated on infrequent start up and shutdown periods of short dur ation. According to the commenter, the frequency and duration of startup and shutdown periods varies for differe nt 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 ope rations. Accordingly, asserts the commenter, the EPA has not demonstrated that 30-day averaging will enable affected units to comply with a continuously applied MACT standard.

Comment 12: Commenter 17774 notes that the use of a 12-month rolling average also assists regulated facilities in meeting what are extr emely strict standards. For example, the commenter states, one of commenter’s PM CEMS is installed on one of the mo st controlled units in th eir fleet, which utilizes ESP, wet FGD and SCR technology. According to th e commenter, the data from these CEMS (see attachment to EPA-HQ-OAR-2009-0234-17774-A1.pdf) show th at this unit will not consistently meet33 the proposed 30-day rolling average PM limit. The co mmenter states that although this unit typically operates below the proposed limit, there are numerous events (87 exceedances of a 30-day average in a 2-year time period) where unplanned shutdown/startup events and temp orary 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 EP A-HQ-OAR-2009-0234-17774-A1.pdf.) According to the commenter, while these units usually operate below the proposed limit, there are a number of events (93 exceedances of a 30- day average in a 2-year peri od) 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 commen ter can reasonably control. The commenter supports a 12-month rolling average to allow for flexibility in compliance by accommodating unplanned startup/shutdown events and inevitable spikes in emissions while maintaining a high level of environmental integrity. According to the commenter , it also will help to limit noncompliance, and therefore promote overall adhe rence to the rule. The commenter asserts that such flexibility will assist in alleviating the ve ry high burden imposed by the proposed Utility MACT.

Comment 13: Commenter 17873 states that averaging time is important in dealing with non-steady state operations and emissions during these periods should either excluded from the compliance determination, or the averaging period should be lengthened from a 30-da y average to a 12-month rolling average, calculated monthly. The commenter offers an example of the practical importance of a longer averaging period when in 2007, Xcel Energy upgraded the Allen S. Ki ng Generating (“King”) Plant. The commenter states that this upgrade in cluded the installation of new pollution control equipment, modification of the plan t heat rejection system, and improve ments 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 fabric fi lter 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 F GD systems require specific flue gas temperatures and the boiler to be at specific steam pressures in order to operate pr operly. According to the commenter, given this, King cannot ope rate the SCR and FGD during peri ods of startup when flue gas temperatures and steam pressures are lower than requi red. The commenter states that the plant’s current permit limits require complian ce based on lb/MMbtu of SO 2 and NO X using a 30-day rolling average, and the commenter’s experience provides strong ev idence of the difficult many units will have in meeting emission units using that averaging appro ach. At King, the commenter found that permit limits can be met if there is only a single start-up with in a given 30-day period, but additional start-ups significantly jeopardize compliance for both SO 2 and NO X . According to the commenter, it is not uncommon for King and other similar units to experien ce 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 propos ed Hg, HCl, and PM limits on a 30-day rolling average basis.

Comment 14: Commenter 17904 notes that even one of its be st performing units (Oak Grove Unit 1), a well-controlled unit, would likely not be able to achieve 100 percent compliance. According to the commenter, this is because the EPA’s proposed standards have been set too stringently, even for these units that were put into commer cial operation since 2009 and are eq uipped with the most advanced, commercially available controls. According to the commenter, operating conditions and fuel quality can vary over short time periods, and periods of startup and shutdown can also affect emission rates over short time periods. The commenter urges the EPA to establish longer averaging times to smooth out this34 variability. The commenter notes th at the EPA has previously explai ned in response to interagency comments that its concern with a longer averagin g period is that EGU owne rs may overspend on Hg control as the result of over-injection of sorbent or lack of sufficient maintenance. According to the commenter, apparently the EPA believes this would increase owner or operator risk of non-compliance and liability associated with non-compliance, because owners and operators woul d decide to only check control devices once per year. However, the commente r states the length of the compliance period is extremely unlikely to drive behavior that is not op timal 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 comme nter states that the EPA’s argument against an annual averaging period is not persuasive. Accordi ng to the commenter, importantly, longer averaging times would simply help redress th e variability issues. The commenter asserts that the EPA would only create the same variability problems if it promulgate d standards with longer averaging times but at the same time applied its UPL variability analysis to set a lower numeri cal emissions rate.

Comment 15: Commenter 17774 states that despite the EPA’s statements in the preamble that it will provide a measure of leniency with regard to instan ces of malfunction, they have serious concerns about the attendant uncertainty regarding how affected sources may be penalized. According to the commenter, in addition, even with a promise of reas onableness 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 viol ation the commenter asserts that regulated facilities would still be subject to significan t EPA and state discretion concerni ng such occurrences and would be forced to shoulder the burden of proving an affirm ative defense. According to the commenter, these requirements distract from efficien tly reducing emissions consistent with the EPA policy and as such, are not an acceptable approach to periods of malfunction.

Comment 16: Commenter 19121 states that it appears that the compliance averaging time for operational limits is substantially more stringent than for the numeri cal emissions limitations set under the proposed rule. According to the commenter, this wi ll have the effect of further limiting operational flexibility. It will also negate the effect of blending in startup/shutdown events so that MACT limits can be met. The commenter states that although a given numerical limit could be met on a 30 boileroperating day average, operating limits could not be met on 1-hour, 4-hour, or 12-hour periods blending the same events. According to the commenter, continuous compliance should be shown based upon emissions monitoring only.

Comment 17: Commenter 17740 states that the EPA’s conc lusion that EGUs “do not normally startup and shutdown frequently” effectively, and incorrectly, assumes that all units are operated as base load units. As the Seventh Circuit recognized in United States v. Cinergy , “[u]tilities operate power generation equipment in three general ways: ba seload, cycling, and peaking.” 623 F.3d 455, 459 (7th Cir. 2010). According to the commenter, non-baseload units start up and shut dow n frequently, and even supposed “base load units” are often, and unpredictably, shut down for unit “trips” (i.e., unplanned outages). The commenter asserts th at 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 roll ing average will address the substantial operating variations among EGUs or even within an EGU. Wh ile 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, w ill operate as reliably as newer units. According to the commenter, as EGUs age, they tend to experien ce more forced outages than when they were newly35 constructed; thus, an older EGU withhighly efficient controls may not be able to meet a 30-day standard in months in which it experiences a number of forced outages.

Response to Comments 6 - 17: The final rule established work pr actices for periods of startup and shutdown, which addresses this conc ern about the impact of such pe riods on compliance with a 30-day rolling average. See the preamble discussion for furt her detail on EPA’s rationale for excluding startup and shutdown periods from calculating compliance w ith the emission limits in the final rule. For malfunctions, EPA provides an affirmative defense for exceedances that may be caused by such events. With these provisions, EPA believes that the conc erns raised in these co mments are appropriately addressed without modifying the general use of 30-day rolling averages for this rule. See also preamble and response to comments below explaining EPA’s a pproach to malfunctions. With respect to the one comment about the proposed operating parameter lim its being based on a shorter time period, those comments are now moot given the lack of operating parameter limits with 12-hour or similar averaging periods specified inthe final rule.

4. Supporting longer averaging time due to health outcomes.

Comment 18: Several commenters (17716, 17725, 18014, 18498) state that a 30-day rolling average compliance period is inconsistent with health e ffects and that the EPA has presented insufficient findings related to the prerequisi tes for reaching an “appropriate and necessary” determination for regulating EGUs under CAA section 112(n)(1)( A). Several commenter s (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 complia nce 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 emis sions from EGUs. Commen ter 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 s hort-term exposure concerns associated with emissions from EGUs because, according to the commenter, nothing has beenshown to suggest a hazard from 30-day exposure to current EGU HAP emissions, and in these circum stances, the value of monthly testing is neither apparent nor warranted to prot ect against a cognizable risk. Co mmenter 17716 goes on to state that absent a showing of need or benefit for monthly te sting, yearly testing should be applied as providing the requisite level of protection against the inchoate long-term potential risks alle ged to be involved.”

Comment 19: Multiple commenters (17627, 17757, 18498, 18539; 18644, 19032, 19041, 19114) state that the EPA has not demonstrated why a 30-day av eraging period would be mo re protective to human health than an annual period, particularly for Hg emissions, where mass emissions are the key issue. Commenter 17725 states that no short-term exposure concerns associated with the ambient level contributions from EGU. According to the commenter, if any risk exists at all, the EPA can only suggest that they are related to chronic, long-term exposure or related bio accumulation manifesting over years; thus, if the emissions from a source are a little hi gher one month due to a c ontrol upset but are then offset by lower emissions during the next month(s), the health impact would be e ssentially identical to a source with no “ups and downs” in the monthly emissions but with the same annual emissions.

Comment 20: Multiple commenters (17716. 17689, 17702, 17718, 17798, 17885, 18037, 18443) state that the risk and concern e xpressed by the EPA centered around long term emissions (e.g., bioaccumulations) and that therefore the use of a rolli ng average that would need to be calculated every day is unwarranted. Commenters suggest that comp liance 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 stru cture requirements based on whethe r the hazardous pollutant creates36 acute or accumulative impacts. For example, according to the commenter, acid gases are of concern for even very short periods of exposure whereas for meta ls, including Hg, the impacts are more related to the total loading and accumulation in the environment.

Response to Comments 18 - 20: The EPA establishes the limits based on the maximum achievable control technology, not the specific time frame 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 EP A believes that the final rule’s monitoring and testing provisions provid e a cost-effective means of ensuring con tinuous compliance with the standards, and take advantage of a range of options, with si gnificantly reduced monito ring and testing where the margin of compliance indicates a reduced lik elihood for potential noncompliance situations.

Comment 21: Several commenters (17716, 17725, 18014, 18498) suggest the use of block averages for PM, Hg, and HCl CEMS data as performance indicat ors, not as direct meas ures of compliance.

Response to Comment 21: An Hg CEMS and an HCl CEMS are options for use as the performance test method for the applicable Hg and HCl emission limits. If a source is concerned about the use of these methods in such a manner, the rule provides for othe r options (sorbent trap m onitoring for Hg and stack testing for Hg and Cl). There is no use of a PM CE MS 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 expre ssed 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 dem onstrated in a periodic stack test.

Comment 22: Several commenters (17689, 17885, 17930, 18443, 19032) support an annual average because most utilities will be us ing a sorbent trap because Hg CEMS technology is not likely to yield accurate and precise measurements. According to th e commenters, sorbent traps have approximately 2- week collection intervals, so should a problem develop with one sample, 30-day compliance demonstrations would be extremely problematic. Further, asserts the commenter, as the EPA is well aware, a major factor in Hg emissions concentration is the Hg fuel cont ent, so it is quite possible the Hg content variability in coal utili zed 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 shoul d revise the averaging time to annual to account for this variability.

Response to Comment 22: The agency believes a number of Hg CEMS will be able to provide continuous data regarding mercury emissions; should an owner or opera tor choose to use sorbent traps in lieu of Hg CEMS, such an owner or operator w ill be able to use his knowledge regarding process, mercury fuel content, and control device operation to tailor the time th e sorbent traps collect samples. Note that sorbent traps are allowed a maximum sample time of 15, not 30, days.

5. CEMS uncertainty.

Comment 23: Several commenters (17725, 18014, 18498) state th at in reviewing the CEMS data for compliance purposes, the EPA would need to take in to account the uncertainty of the measurements along with the emissions reported for other months.37 Response to Comment 23: The CEMS data will be quality-assured in accordance with the rule requirements. Provided the monitoring systems are producing valid, quality-assured data, EPA will use 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 part60 in the 1980s. The data under this rule will be treated in accordance with thos e longstanding principles and regulatory provisions.

6. 30-day rolling average is inappropriate.

Comment 24: Several commenters (17705, 17716, 17725, 18014) stat e that the 30-day rolling average is also inappropriate because it re peatedly penalizes sources for a sing le emission controls upset because if a source experiences very high emissions one day (startup, shutdown, or malfunc tion) that single day will affect the 30-day average calculated not only for that day, but also the calculated averages for the next 29 days). Several commenters (17725, 18014, 18498) refer to this situation as not only double jeopardy but thirty-fold jeopardy. Commenter 17800 states that due to the stri ngency 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 ta kes immediate corrective action.

Response to Comment 24: The final rule includes a work practic e in lieu of numerical limits to apply during periods of startup and shutdown. The scenario the commenter raises re lative to startup and shutdown emissions inordinately affecting the 30 day average should be moot. The rule also includes provisions for the source owner to apply for an affi rmative defense of excess emissions that occur during malfunctions. We believe that the rule addresses th ese comments such that the source owner has the flexibility to manage process and control device operat ions in a timely fashion relative to the averaging time of the standards. See also response to Comments 6 through 17, above.

7. Support annual fuel variability.

Comment 25: Several commenters (17702, 17725, 17930, 18018, 18644) state that a 30-day rolling average for compliance may be unworkable for so me units and is unnecessarily restrictive. The commenters state that many coal-fired EGUs are designe d to bum a variety of co al types. According to the commenters, trace chemical constituents (metal , sulfur, halogen, Hg, chlorine) of coals from the same source can vary significantly. The commenters asse rt that in certain cases, variations in chlorine content in a coal may mean the difference betw een compliance and noncompliance with the EPA’s proposed air toxics rule.

Response to Comment 25: As the rule no longer contains fuel content metals or acid gas operating limits but maintains the UPL calculati ons to account for variability, as discussed elsewhere, the agency believes a 30 boiler operating day rolling average w ill be sufficient to account for normal variation in fuels for sources that use a CEMS to demonstrate compliance with the standards in the final rule.

Comment 26: Commenter 18443 states that a major factor in Hg emissions concentration is the Hg fuel content. According to the commenter, the curr ently proposed Hg limit does not account for the variability of Hg in the fuel or varied plant operations and draws only on 40 hand-picked best performing units, and it is possible th at the Hg content in a particular coal shipment could be high38 enough over a 30-day period to exceed the Hg limit de spite the best efforts of a utility to limit Hg emissions.

Response to Comment 26: The agency disagrees with the comment er and notes that the Hg emissions limit was established using data from the best perform ing sources that were adjusted statistically using the UPL procedure to account for variability. Properly maintained and operated Hg control devices should enable source owners or operators to meet the rule’s Hg emissions limit.

8. Suggested alternative compliance approaches.

Comment 27: Commenters 17928 and 18644 state that the 30-day aver aging time is too short to account for transient events (startup, shutdow n and upset conditions), and variabi lity of CEMS data. In order to facilitate the practical use of f acility averaging provisions outlined in the proposal, the commenters recommend that a minimum 90-day averaging time be considered, to account for uncontrollable events and emissions variability. Commenter 17928 notes that th ere 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 maintena nce outage of the over-controlled units at a facili ty could force the other units in an averaging plan to be out of compliance.

Response to Comment 27: See response to Comments 6 through 17 and 24, above.

Comment 28: Commenter 19121 encourages the EPA to recons ider increasing either the averaging time for limits or the actual PM or Hg limits. Accord ing to the commenter, based on recent testing, the commenter’s unit is proven to be one of the lowest emitters of Hg in the nation. The commenter notes that the State of Utah has set a Hg limit that is more strict than that the EPA is proposing but that the State rule requires an annual aver aging period. According to the comm enter, this is an example of balance between limits and limits averaging that w ould still be protective of human health and the environment, and meet the requirements of NESHAPS.

Response to Comment 28: As mentioned in earlier responses, the agency believes the rule’s averaging time appropriately accounts for brief, transient emi ssions spikes enabling the agency to focus its response on poor performing or problematic sources, instead of penalizing in advertent occurrences. Given that the commenter’s EGU appears to meet a more stringent state Hg standard, it should have no problem meeting the standard contained in the rule.

9. Requests for clarification/explanation.

Comment 29: Commenter 17638 urges the EPA to clarify that a “30 operating day rolling average” is determined by averaging all applicab le hours in the 30-day period. Accord ing to the commenter, in some cases, the proposed rule appears to indicate that a new daily average w ould be calculated each day and then 30 daily averages would be averaged to de termine the 30-day average, while other language appears to indicate that al l of the hourly emissions for the preced ing 30 boiler operating days would be averaged to determine the 30-day rolling average. According to th e commenter, defining a 30-day period based on daily averages is not fair to units that frequentlycycle on and off and c ould weight a 15-minute period equally to a 24-hour period.39 Response to Comment 29: The final rule clarifies that the averag e is based on all va lid hourly averages during each 30-day rolling average period. Hourly averages are not su mmed to a daily average as an intermediate data value for purposes of determining each 30 boiler operating day average.

Comment 30: Commenter 18034 states that the rule must be revised to provide for proper calculation of emissions during a malfunction. The commenter observes that section 63.10005( l) only applies to startup and shutdown operations. According to the commenter, if power production during a malfunction approaches zero, calculated output- based emissions will spike exponentially. The commenter states that any malfunction causing power production to cease completely for more than an hour while the boiler is in operation will result in th e calculated emissions becoming infinite for that hour as will the calculated rolli ng average that includes that hour and that the 30 boiler operating day average does not address this issue, because Appendix A, Section 6 ( 76 FR 25144), Equation A-4 requires Hg emissions to be calculated on an hourly basis before calculating the 30 boiler operating day average according to Equation A-5. A ccording to the commenter, this issue does not appear limited to Hg emission calculations, as proposed section 63.10010 requires that the 30-boile r-operating-day rolling average for other pollutants be de termined as the average of all the hourly emissions data for the preceding 30 boiler operating days. The commenter indi cates that the proposed ru le does not appear to contemplate malfunctions in the power production side of a facility and under some circumstances require sources to divide by zer o when calculating emissions.

The commenter suggests that the ca lculation for compliance with the 30 boiler operating day average for the proposed NESHAP rule could be revised to be consistent with how the EPA has proposed demonstrating compliance with proposed revision to 40 CFR 60 subpart Da, i.e., the sum total emissions for the 30 boiler operating days divided by the su m total output over the 30 boiler operating days. According to the commenter, as the EPA has proposed the rule, sources would be automatically in violation of the rule for even mi niscule emission rates during a ma lfunction in which power production ceased for more than an hour.

Commenter 17755 states that a boile r is a separate unit from the generator and can be operated independently, and the boiler units can and do combus t 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 produci ng electricity (MWh), that if notproducing electric ity 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 generato r is not operating, and the commen ter questions whether emissions that occur when the generator is not producing electricity would be unr egulated 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 experi ences a malfunction that causes the boiler to shut down, the emissions during that period must be in cluded in the 30-day averaging period and, if the malfunction causes the source to exc eed the limit for the applicable 30-day averaging period, the source is in noncompliance and subject to penalties unless the source demonstr ates 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 scen ario outlined above. We do not agre e, however, that a source would automatically be in violation of the standards b ecause 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 complying with the output-based lim its during periods of normal operation would have to demonstrate that it complied with the applicable input-based standards dur ing the malfunction event.40 The source will need to include in its malfunction re port the additional calculations and an explanation to demonstrate that the source complied with the standard notwithstanding the malfunction event. Sources complying with the input-based limit would not have to take additional steps to demonstrate compliance during the malfunction event. For these reas ons, we are not amending the final rule in the manner suggested by the commenter.

Comment 31: Commenter 17705 recommends that the final ru le define “boiler operating day” as a 24- hour period during which fossil fuel is combusted in a steam-generating unit for the entire 24 hours to ensure that compliance is always based on at least 720 hours of operation. Commenter 17705 contends that the EPA should specify a minimum number of operating hours necessary to calculate a 30-day rolling average; if the requisite number of hours is not obtained, the EGU should have the option of combining data from that period with the data fr om the next 30 boiler ope rating day period until the requisite number of hours is ob tained. According to the commenter, the EPA specified a similar procedure in the 40 CFR Part 60, subpart Da provisi ons for calculation of a 24-hour average in section 60.48Da(g)(3), which requires a minimum number of valid hours to calculate an average.

Response to Comment 31: The EPA disagrees. See responses to comments under Comment Code 5A12 of this document for further discussion on data availability.

Comment 32: Commenters 17740 and 17767 request the EPA to provide clarification to address the following factors: 1) the nu mber of valid data points or minutes required for a valid operating hour, 2) the number of valid data points or minutes required for a valid operating day, and 3) the number of valid data points required for a valid 30-day average.

Response to Comment 32: Section 63.8(g)(2) provides the genera l 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 m onitoring data in that day. There is no minimum number of data points for a 30-day average. See responses to comments under Comment Code 5A12 of this document for further disc ussion on data availability.

Comment 33: Commenter 18023 requests clarification with respect to the method to calculate the 30 operating day rolling average. According to the commen ter, in some cases, the proposed rule appears to indicate that a new daily average would be calculat ed each day and then 30 daily averages would be averaged to determine the 30-day av erage, 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 exampl es of their confusion, and asserts that:

 Table 8 in the proposed rule sugge sts that the 30-day rolling averag e is calculated as the average of 30 individual boiler operating day values (Pro posed Table 8 (7.b) (con vert “hourly emissions concentrations to 30 boiler operating mg/dscm values”).

 Proposed section 63.10010(g)(5), ho wever, 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 ina 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 inthe 30-day period. Accord ing to the commenter,41 finalizing the rule based on the aver age of 30 daily averages would be challenging if the unit frequently cycles on and off, and further, the daily averaging approach would not be fair because it would weight a 15-minute period ( i.e. , one boiler operating day) as be ing equal to a 24-hour period ( i.e. , also one boiler operating day).

Response to Comment 33: The final rule clarifies that the aver age is based on all va lid hourly averages during each 30-day rolling average period. Hourly averages are not su mmed to a daily average as an intermediate data value for purposes of determining each 30 boiler operating day average.

Comment 34: Commenter 17927 requests clarification of the averaging periods which will be used to demonstrate continuous compliance with the app licable emission limits in the proposed rule.

Response to Comment 34: Averaging periods apply for emission limits where a CEMS is used to determine compliance and for the sole remaining ope rating limit where a PM CPMS is used. In these situations, the final rule uses a consistent 30 boiler operating day ro lling average, based on all valid hourly averages during each successive rolling 30 operating day period.

Comment 35: Commenter 17681 states that section 63.10031(d )(2) of the proposed rule appears to require a description of the deviation in the comp liance report. Commenter 17681 asks for clarification of when compliance is determined within the pr oposed 30-day compliance period; the commenter asks “If an event occurred on December 31 and the 30-d ay average starting on December 31 and ending on January 30, would that deviation be required to be reported in the January 31 compliance report? And if so, how would a facility know that such an event would deviate from the 30-day average until the end of that 30-day averaging period un less 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 hist orical use of the 30-day rolling average and requests that the EPA provide an explanation of why the EP A is seeking to change the manner in which the averaging times for emissi on standards have histor ically been calculated at EGUs. Commenter 17730 believes th at the EPA should not impose a more restrictive averaging time for the proposed emission standards.

Response to Comment 35: The rolling average uses a 30-day rolling period as calculated at the end of each successive operating day, based on all valid hour ly averages in the preceding 30 boiler operating days. In terms of reporting, a deviation that occurs in January would not be incl uded in the report that must be submitted by the end of January, as that re port 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 th is 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 ro lling emissions averaging period.

Comment 36: Commenter 17775 states that once the operatin g limit is established, proposed section 63.10010(g)(5) specifies that a 30 boiler operating day rolling average is ca lculated as “the average of all of the hourly particulate emissions data for the preceding 30 boiler operat ing days” (citing 76 FR 25,112/2). According to the commenter, proposed Table 8, on the other hand, suggests that the 30-day rolling average is calculated as the average of 30 individual boiler ope rating day values (citing proposed Table 8 (7.b) (convert “hourly emissions concentr ations to 30 boiler opera ting mg/dscm values”)). According to the commenter, calculating and averag ing 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 36: The final rule clarifies that the 30-d ay average is based on all valid hourly averages from the PM CPMS in the preceding 30 boiler operating days, with no intermediate daily values used to determine the 30-day average. The agency disagrees with the commenter’s suggestion that the 30-boiler operating day ro lling average period lacks suffici ent support; use of a 30-boiler operating day rolling average period data manage ment during startup and shutdown periods are discussed elsewhere in this document.

Comment 37: Commenter 17796 suggests that the Hg compliance metric be st ated succinctly in section 63.10010(f). According to the commenter, it is clearly stated in section 63.10010( g)(5) that compliance is based upon a 30-day rolling average emissions rate on a daily basis. However, the commenter was unable to find this language for the Hg compliance limit for CEMS. The commenter asserts that Section 63.10010(f) refers the reader to Appendix A, but Appendix A does not state the compliance metric.

Response to Comment 37: See Section 6 of Appendix A to the fi nal rule for the cal culation procedures.

Comment 38: Commenter 17807 states that the rule propos es to use heat-input-weighted emission limits based a 30-day rolling averag e. According to the commenter, th e rule is not clear on how to calculate the 30-day rolling aver ages. The commenter proposes calculating a daily total for each constituent, summing the mass and heat input and then calculating the rolling average.

Response to Comment 38: The final rule clarifies that the aver age is based on all va lid hourly averages during each 30-day rolling average period. Hourly averages are not su mmed to a daily average as an intermediate data value for purpos es of determining each 30 boiler operating day average. See also Section 6 of Appendix A to the final rule for Hg calculation procedures.

Comment 39: Commenter 17820 states that the 30-day rollin g average limits should contain at least 30 full days of operation.

Response to Comment 39: The EPA disagrees. A boiler operating day is a day in which any fuel is combusted, and each such day is a day for purposes of calculating the average.

Comment 40: Commenter 18014 states that Table 8 requires th e source is to convert “hourly emissions concentrations to 30 boiler operating mg/dscm values ,” which suggests that compliance is assess based on the average of 30 individual daily values. Ho wever, according to the commenter, section 63.10010(g)(5) states that 30-day rolli ng average is calculated as “the average of all of the hourly particulate emissions data for the preceding 30 boiler operating days.”

Response to Comment 40: See response to Comment 33, above.

Comment 41: Commenter 18023 requests clarification on the averaging times for operational parameters. According to the commenter, the EPA has pr ovided four inconsistent descriptions as to how the operational parameter limits would be set ( i.e. , 90 percent of the test av erage, the lowest 1-hour average, the 12-hour block average, and the averag e of three minimum valu es). According to the commenter, the electric utility and industry has no way of knowing wh ich 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 comme nter states that the average of43 three runs and the lowest 1-hour av erage are clearly unreasonable because, by definition, there will be values during the testing that are above and below th e average and, on a longer te rm basis, these values
may vary even more.

Response to Comment 41: See response to Comment 36 above for the only remaining operational parameter that applies under the final rule.

10. Rule language corrections.

Comment 42: Commenter 17775 believes that the reference to the 30 boiler operating day compliance period for PM in proposed Table 8 (7.b) is incons istent with the reference in proposed section 63.10010(g)(5) because proposed Table 8 (7.b) suggests that only 30 daily values are averaged while section 63.10010(g)(5) indicates that up to 720 hourly values are averaged. Commenter 17775 believes that calculating and averaging separate boiler ope rating day values would make the limit much more stringent for any period that include s a startup or shutdown and concl udes that “[R]egardless of which EPA intended to propose, neither ha s been sufficiently supported. “

Response to Comment 42: The final rule clarifies this issu e; see response to Comment 33, above.

Comment 43: Commenter 17638 requests a mass-based altern ative compliance option by converting the existing rate-limit (pounds per million Btu) to a mass-limit (pounds per hour with an annual average), based on the unit’s permitted heat input. The commenter notes that Florida has recent positive experience in utilizing mass-based limits in permits, achieving substantial envi ronmental benefits while lessening the burden on the source. According to the commenter, the EPA also has extensive experience developing NESHAP compliance requi rements on a mass basis, having promulgated at least six such regulations (40 CFR part 63, subparts MMM, XXX, GGGGG, GGGGGG, LLLLLL, and NNNNNN). The commenter further notes that ma ss rate were used in the modeling supporting the rule and well as in setting the standards (usi ng stack tests date).

Response to Comment 43: While the EPA appreciates the sugge sted alternative, we have not conducted analyses to assess what specific limits would be necessary to meet MACT statutory requirements under this alternative s cenario and believe that the propos ed format provides an adequate means of limiting emissions in accordance with the st atutory provisions and in such a way as can be monitored and tested for compliance. Thus, the EP A does not believe this type of alternative is necessary or supported at this time.

Comment 44: Commenter 17881 believes that Equation 5 may not always yield an accurate 12-month rolling average emission rate when there is a large disparity in the total monthly heat input (or steam output) across all units included in the averaging plan. According to the commenter, specifically, Equation 5 gives each monthly average emission rate used to calculate the 12-month rolling total an equal weighting (i.e., 1/12, or 8.33 percent). The comme nter suggests that it would be more accurate if the 12-month rolling average emissionrate was calculated as follows:

Where, Eavg = 12-month rolling average emissions rate (lb/MMBtu heat input; lb/TBtu for Hg).

Er i = 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 44: The rule replaces a 12-month rolling average with a quarterly weighted average. As the monthly weighted average (ER i ) already makes the adjustment suggested by the commenter, per Equation 3 or Equation 4, the agency sees no reason for keep ing Equation 5, so it has been removed from the rule.

Comment 45: Commenter 17881 requests clarification, with resp ect to Equations 1-5, as to the value of “Er” in those cases where the “performance test” cons ists of the use of a CEMS to determine a 30-day rolling average emission rate. According to the comme nter, as 30-day rolling av erages at the end of a given month could include several days worth of data from prior months (assuming that operation is not continuous), there is a high degree of likelihood that the 30-day rolling average emission rate at the end of a month will not line up with the associated calendar month, thereby introducing a disconnect between the average emission rate and heat input value used for weighting purposes. The commenter states that Equations 1 – 4 should specify procedures for reducing CEMS data into average values for purposes of the “Er” term. The commenter suggests a simplistic approach would be to average all valid 1-hour emission rates determined during each cale ndar month for purposes of Equations 3 and 4.

Response to Comment 45: The final rule includes clarification of the emissions av eraging procedures and calculations to be consistentwith calculating compliance with the 30 boiler operating day average for emissions rates elsewhere in the rule. The revise d procedure also allows for using CEMS data in combination or in lieu of performance testing datafor determining compliance with the emissions limits.

Comment 46: Commenter 17621 states that individual measur ements that comprise the baseline data pool are incompatible with antic ipated compliance measurements. According to the commenter, the EPA approach (as stated on FR 25041) to calcula tion of a UPL is based on an average of three compliance test runs, each of which follows the unde rlying measurement protocol that was used for the component baseline data. According to the commenter , compliance options in the proposal typically are at variance with this requirement. The commenter asse rts that most require comp liance 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 appro aches are different. (See st atistical study provided in Appendix D.)

Response to Comment 46: The commenter appears to confuse the agency’s standard setting activities (that include UPL calculations) with collection of CEMS data. The co mpliance options that rely on use of a 30 boiler operating day rolling av erage are not at odds with the stat istical approach for determining the emissions limit. Use of the statistical approach provides a tangible measure of variability that is a component of the emissions limit, while use of CEMS supplies data that for well-operated EGUs are expected to be equivalent or less than the emissions limit 99 of 100 times. As mentioned in earlier responses, establishing an emissions limit in this fashion allows the agency to focus on the poorly operated or problematic EGUs.45 5A03 - Testing/Monitoring: Fuel analysis methods

Commenters : 17316, 17386, 17402, 17621, 17715, 17718, 17722, 17725, 17730, 17731, 17754, 17758, 17760, 17775, 17781, 17796, 17800, 17801, 17807, 17808, 17816, 17820, 17821, 17881, 17902, 18014, 18015, 18025, 18428, 18447, 18483, 18498, 19033, 19114, 19121, 19536, 19537, 19538

1. Exempt natural gas.

Comment 1: Commenters 17316 and 17386 request th at the EPA exempt the fuel analysis of natural gas for dual fuel-fired units that fire gas. According to the commenter s, in particular, in sections 63.10005(c)(1) and (2), and 63.10006(s), the pr ovisions requiring a fuel anal ysis for “each type of fuel burned” should explicitly exclude pipeline natural ga s. The commenters state that the exemption should be based on natural-gas-fired units being both insignifican t source of HAP and otherwise being exempt from the rule. The commenters also suggest that section 63.10005(c)(4), whic h provides an exemption from the performance of an initial fuel analyses if a unit burns a single fu el type, be extended to exemption any unit which burns only one fuel type, as ide from pipeline natural gas (i.e., burns 2 fuel types, but one is pipeline natural gas).

2. Initial complian ce fuel analysis.

Comment 2: Commenter 17316 states that that it is unclear why units that burn a single fuel type are exempt from conducting an initial compliance fuel anal ysis, which appears to be the intent of section 63.10005(c)(4). The commenter believes the rule s eems to be saying that units which intend to demonstrate compliance by fuel analysis are not required to conduct an initial compliance demonstration.

Comment 3: Commenter 17775 requests the EPA clarify th e requirements for EGUs combusting single fuels. Although proposed section 63.10005(c)(4) suggest s that such EGUs are exempt from any initial fuel analysis, proposed section 63.10 011(c)(1) only appears to exempt such EGUs from the requirement to determine the fuel “mixture” that would resu lt in the maximum emission rates. The commenter assumes the EPA intended liquid oil-fired EGUs de monstrating compliance through fuel analysis to conduct an initial demonstra tion using fuel analysis, but that such EGUs that combust only a single fuel type are not required to make any other demonstrations regarding th at sample. The commenter believes the EPA should confirm that understanding in the final rule and provide consiste nt language in the two provisions.

Comment 4: Commenter 17722 notes that section 63.10005 exempt s units firing “a single type of fuel” from the fuel sampling and analysis requirements. A ccording to the commenter, the rule does not define what constitutes a single fuel. The co mmenter questions if the definition is as broad as coal, natural gas, and fuel oil, or more narrowly defined by ranks (e.g., bituminous, subbituminous, lignite) or even more narrowly ranked by mine loca tion or even coal seam.

Comment 5: Commenter 17775 suggests for EGUs opting to demonstrate compliance using fuel analysis (as opposed to performance testing), the EPA should clarify or remove the reference to operating limits. The commenter believes propose d section 63.10005(c) inexplicably refers to requirements to establish operating limits unde r section 63.10011 and Tabl e 8. According to the commenter, the only sections of section 63.10011 or Tabl e 8 that could have any applicability to EGUs complying through fuel analysis are the fuel input emission rate calculatio ns in proposed section 63.10011(c) and the fuel pollutant cont ent restrictions in Table 8 (6). The commenter suggests the EPA46 make clear in the rule that the other operating limits in those provision s do not apply to units complying through fuel analysis.

Comment 6: Commenter 17881 notes that 63.10011(c) is uncl ear how fuels not covered by the rule (i.e., natural gas) factor in when co-fired with fuels wh ich 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) coul d show a value much greater than the arithmetic average. The commenter believes if this potential HCl content is gr eater than the limit, the facility should have the option of periodically colle cting fuel samples and showing that the actual results meet the limit.

Comment 8: Commenters 18014 and 18498 suggest EPA clarify fuel sampling provisions for multiple fuels. According to the commenters, for units firing a single fuel type, fuel sampling and analysis is not required for supplemental fuels used only for start up, shutdown or for maintaining flame stability per §63.10005(c)(5)). The commenters believe this exemption does not appear to apply to units that fire multiple fuel types or blends and suggest EPA clarify this exemption in the final rule.

3. Fuel sampling procedures.

Comment 9: Several commenters (17316, 17386, 17881) state the fu el sampling procedures specified in section 63.10008(c) and (d) appe ar to be applicable only to solid fuel s and that this s ection should clarify that these procedures are not appl icable to oil (liquid) fuel samp ling. Commenter 17881 requests that the EPA clarify if there are any requirements for non-solid fuels; for example, it is not clear for a unit cofiring natural gas if fuel sampli ng of the natura l gas required.

Comment 10: Commenters 17316 and 17386 suggest that fuel sampling for oil-fired EGUs follow 40 CFR 75 Appendix D provisions, which refe rence ASTM D4057 sampling procedures.

Comment 11: Commenter 17402 suggests the EPA clarify that fuel contaminant levels calculated during performance tests will be used to calculate maximum contaminant levels for fuel content, including allowance for some fuel variability, and not dictate the fu el operating limit directly as an average. According to the commenter, fuel sampli ng is necessarily a point-in-time sample, while fuel content varies. As a result, asserts the commenter, by setting a standard based on a simple average, the EPA could unnecessarily subjec t roughly half of all facilities to co mpliance penalties for using fuel with the identical variability present during the performan ce tests – i.e., those for which the fuel sample was taken from an above-average portion of the fuel. A ccording to the commenter, instead of effectively encouraging facilities to burn the mo st contaminated fuel they can during performance testing, the EPA should grant facilities with low emi ssions a safety margin to reflect variability in fu el and operations. The commenter suggests that the EPA specify that faci lities may use fuel contaminants to set a percent reduction for the system, and thus establish a fuel contaminant level (with adequate safety margin) which facilities may use to comply without condu cting periodic performance tests as frequently.

Comment 12: Commenters 17730 and 17800 believe the EPA should revise section 63.10008 to make clear that the sampling and compositing procedures in Table 6 may be used. According to the commenters, proposed section 63.10008 requires fuel an alysis 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 thos e in paragraph (c) and some of those procedures address compositing. For example, state the comm enters, 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 Consi gnment-Size) Quantities of Coal.” The commenters state the EPA should make clear that any procedure identified in Table 6 can be used in lieu of procedures in paragraphs (c) and (d).

Comment 13: Commenter 17722 notes that section 63.10011 require s fuel samples to be collected and analyzed during initial performance testing that “establishes maximum fu el 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 th at could be expected while combusting coal – even if that coal is from the same mine. Acco rdingly, the commenter beli eves it is impossible to demonstrate compliance with section 63.10011. Acco rding to the commenter, a typical coal specification sheet will provide the range, average, and standard deviation of the metals in the coal, and it is not unusual for the standard deviati on to be 10 to 15% of the average value.

Comment 14: Commenter 17881 notes that section 63.10008 re quires the collection of three fuel samples, which seems to be a one-time requireme nt, 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 s ection 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 repr esentative indicator of fuel content that will impact PM emissions is ash content. In the event the EPA does not accept its recommendation that fuel sampling only be required in the absence of CE MS, the commenter recommends that Table 6 be amended to include an option to sample for ash conten t, if the EGU operator elects to comply using the PM emission limit.

Comment 16: Commenter 19033 notes that proposed regulati on 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 CE MS, the commenter believes the regulation should allow establishment of maximum ash content, if the EGU operator elects to comply with the PM emission limits. The commenter recommends that section 63.10011(b)(3) be amended as follows:

“ lf you elect to comply with the non-Hg HAP metal emission limits, y ou must establish the maximum non-Hg HAP metals fuel input level ( HAP metal input) during th e initial performance testing using the procedures in paragraphs (c)(3)(i) through (iii ) of this section. lf you elect to comply with the PM emission limits and do not operate a PM-CEMS, you must establish the maximum ash content fuel input level during the initial performance testing using the procedures in paragraphs (c)(3)(i) and (iii) of this section .”

In this same connection, the commenter recomm ends 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 de monstrate that all fuel types and mixtures of fuels burned would either result in lower em issions 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 in put 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 comp ly with the PM emission limit ), or Hg than the maximum values calculated during the last performance tests (i f you demonstrate compliance through performance stack testing).

Comment 17: Commenter 19121 believes the EPA is overly pr escriptive concerning performance test fuel sampling. Specifically, at section 63.10008(c) a nd (d), the commenter believes the EPA is not recognizing other methods for coll ecting and preparing representative fuel samples. The commenter states that ASTM has developed methods that uti lize automated and continuous sampling systems, and such equipment is present at many coal plants, and th e systems are bias tested against ASTM standards. The commenter also notes there are also ASTM appr oved sample preparation st andards utilizing riffle, grinding, and drying equipment designed to meet applicable ASTM methods.

4. Fuel sampling requirements for sources with CEMS.

Comment 18: Multiple commenters (17402, 17725, 17800, 17820 18014, 18498) believe that the EPA did not intend to require sources using a CEMS to also conduct fuel sampling, but the EPA should clarify this issue in the final rule.

Comment 19: Commenter 17402 requests that the EPA revise section 63.10007 to indicate that fuel sampling is not required when th e applicable HAP (or surrogates) are monitored using a CEMS. The commenter requests that the EPA mo dify the rule to explicitly st ate 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 a ppears to indicate that fuel sampling requirements apply only to those units that demonstrate complian ce through “performance testing” for a particular pollutant. The commenter states that as each unit mu st 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 re quire 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 demonstr ate compliance are unclear because of conflicting language in the proposed rule. According to the comme nters, the rule does not explicitly state that sources using a CEMS for compliance for a particul ar pollutant are exempt from all fuel sampling requirements for that pollutant. However, the co mmenters do not believe that the EPA intended to require sources that demonstrate compliance via CE MS to also have to pe rform fuel sampling and analysis. The commenters note that fuel sampling is certainly required for oil-fired sources that demonstrate compliance through fuel analysis, and section 63.10011(b) specifie s that sources that demonstrate compliance through “performance testing” fo r a particular pollutant must also perform fuel sampling to “establish maximum fuel pollutant input levels.” According to the commenters, while not formally defined, the rule generally implies that “p erformance testing” refers to emissions (stack) testing. However, note the commenters, in sect ion 63.10005(a) the EPA states that “performance testing” may also consist of CEMS operating data, thereby creating ambiguity inwhether other parts of the rule that pertain to units using stack test data to comply also apply to those units using a CEMS for compliance.

Comment 21: Commenter 17800 believes it is unclear from th e way the regulation is written if EGUs complying with CEMS systems must meet fuel i nput 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 CE MS data, the proposal appears to require that EGUs meet fuel input limits regardless of the “performance testing” option they choose. According to the commenter, the proposal appears to require that EGUs meet operating limits for all relevant control devices and load regardless of the “performance testing” option they choose.

Comment 22: Commenter 17758 notes that proposed sectio n 63.10008 lays out in detail a fuel sampling and analysis regimen; however, none of the fuel information is meaningful or rele vant when either all of the regulated HAP or their surrogates are continuously monitored. Th e 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 maxi mum Hg fuel input level in the fu el prior to testing is not a good indication of what will actually be emitted when u tilizing the equations. According to the commenter, for example, the form of the Hg emissions from co al combustion (i.e., elemental, oxidized and particle bound) can have a major impact upon Hg emissions, as these forms are controlled to varying degrees by prevalent control technologies. The co mmenter states that certain coals tend to favor elemental forms of Hg emissions as opposed to oxidized forms of emi ssions. 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 pe rcentage of elemental Hg emissions (as this form of Hg is not as read ily removed in prevalent control technologies).

Comment 24: Commenter 18015 requests that the EPA clarify the applicability of the fuel analysis requirements; specifically, the comme nter recommends that the EPA state in the preamble and the final rule that fuel analysis is not re quired for units that use CEMS to continuously comply with emission standards. According to the commen ter, should the EPA agree with th e commenter’s request to allow a percent removal MACT standard approach (discussed se parately), 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 whic h are demonstrating co mpliance with the PM surrogate. The commenter believes that is should not apply, as a CEMS is installed to verify continuous compliance, and that this paragraph makes little sense for units without PM CEMS that are required to test monthly or bi-monthly; thus, the tests would already be conducte d within the frequency (60 days) specified in the paragraph.

5. Fuel sampling requirements for si ngle-fuel units that comply with one or more standards based on stack testing.

Comment 26: Commenters 17402 and 18498 believe that the EPA should allow facilities to conduct more frequent fuel sampling to show continuing co mpliance based on their performance tests instead of using CEMS.

Comment 27: Several commenters (17402, 17820, 18498) believe the rule is unclear as to whether units that fire a single type of fuel ar e exempt from all fuel sampling and analysis requirements. According to the commenters, the EPA appears to exempt units th at fire a single fuel ty pe from conducting fuel50 analysis as part of th e initial compliance requirements in s ection 63.10005(c)(4). However, state the commenters, in section 63.10011, the procedures used to establish the fuel ope rating limits include a directive for handling single-fuel un its. Despite these inconsistencies, the commenters believe that it was probably the EPA’s intention not to require single-fuel sources to conduct ongoing fuel sampling, and thus the commenters propose fuel testing only be required every six months, unless a facility changes fuel type. According to the commenters, this approach is consistent with the approach taken in the final Industrial Boiler MACT rule, which did not require any ongoing fuel testing. The commenters note that the EPA explicitly states in the definition of “fuel type” in sect ion 63.10042 that changes in vendors for a particular fuel type are not consid ered a change in fuel type, and asse rt that this indicates a belief that fuel sampling is not required within fuel types. A ccording to the commenters, the EPA should clarify the fuel sampling requirements for single-fuel units that comply with one or more standards based on stack testing.

Comment 28: Commenters 17725 and 17820 note that for units firing a single fuel type, fuel sampling and analysis is not required for supplemental fuels used only for startup, shutdown or for maintaining flame stability (section 63.1 0005(c)(5 )) According to the commenters, this exemption does not appear to apply to units that fire multiple fuel types or blends, and they request that the EPA clarify this exemption in the final rule.

Comment 29: Commenter 17722 requests that EPA clarify that fuel testing is not required for sources that combust a single fuel, excluding limited se condary fuel use for startup, shutdown or flame stabilization. The commenter believes single-fuel pl ants should be exempt from the requirements under section 63.10007(c) which states “you must conduc t the performance tests at the maximum normal operating load while burning the type of fuel or mixtur e 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 analysis requirem ents for single fuel EGUs and supplemental fuels.

6. Low emitting EGUs.

Comment 31: Several commenters (17402, 17754, 17808) believe the LEE monitoring requirements are overly burdensome. Commenter 17808 believes in many cas es, monthly fuel testi ng 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 un its). 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 addr essed in the preamble, they are notdirectly addressed with regard to LEEs in the rule itself. For LEE single fuel fa cilities, 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 inconcentration are small enough that based on the facility’s demonstrated contaminant reduction performance on the prior stack te st they would not cause the LEE limit to be met, then retesting of performa nce should not be required.

Comment 32: Commenter 17775 states that if EPA intended to require that LEEs pe rform monthly fuel analysis under section 63.10006(c), the EPA needs to make clear th at compliance with the maximum fuel input levels is not requi red and explain why it chose monthly testing. According to the commenter, analyzing fuel monthly when the fuel supply or mixture has not changed seems unnecessary. The commenter states that if the EPA intended to requ ire that LEEs establish and comply with maximum51 fuel input levels as an “opera ting limit” under section 63.10011(b), rather than perform monthly fuel analysis, the EPA needs to explain that the fuel anal ysis 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 requirem ent in section 63.10006(c). If the EPA intended to require that LEEs establish and comply with operating limits other than maximum fuel input levels, the commenter states, the EPA needs to issue a proposal that explains the purpose of those limits and how they apply.

Comment 33: Several commenters (17725, 17820, 18498) believe the fuel sampling requirements for LEE units are ambiguous and provide no compliance value since the rule does not require the establishment of a fuel input ope rating limit. According to the commenters,, the requirements do not address single-fuel units, changes in fuel type, or units that burn or co-fire multiple fuels. The commenters assert that presumably, LEE units w ould follow an analogous procedure as non-LEE units and reassess the ability to meet LEE status based on the new fuel type /blend; this would require sources that burn multiple fuel types or blends to esta blish a fuel-input operating limit during the initial compliance demonstration. Consistent with the n on-LEE requirements, the commenter suggests the EPA remove the arbitrary monthly sampling requirementand allow sources to conduct fuel sampling only when there is a change in the fuel type. For singl e-fuel units, the commenters suggest the EPA specify that these units are not require d to comply with any of the fuel sampling requirements.

Comment 34: Commenter 17754 suggests that to the extent that the EPA doe s not revise the proposed rule to allow LEE units to demonstrate continuou s compliance through annual performance testing only, rather than monthly fuel evaluations, and instead insists upon requiring that all LEEs demonstrate continuous compliance using a fuel factor based approach, the EP A should nonetheless revise the specific fuel factor based approach currently requi red under the proposed rule. The commenter believes the requirement to use the 90 thpercentile confidence level to determine the operating limit for Hg is improper, because the use of such value could cause a LEE to lose its LEE status, even though the unit’s actual Hg emissions remain substantially below the LEE thresholds.

Comment 35: Several commenters (19536, 19537, 19538) believe the EPA should discard its “Low Emitting Units” monitoring protocols. The unavoidabl e variability claimed by the EPA, moreover, indicates that plant emissions range as much as 50 tim es higher than the results of a three-r un test. As a result a plant with test data at 50% of the proposed standard will likely – i ndeed, 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 performa nce tests every 5 years, coupled with monthly fuel sampling. That monitoring provi des no assurance of con tinuous low-HAP emissions. Fuel sampling would reveal no information about HC N, which is a byproduct of combustion and cannot be inferred from fuel sampling. Further, fuel samp ling 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 wa ter used in scrubbers. Metals are also released from the boiler, duct work, and control systems. These would not be detected by fuel sampling.

Comment 36: Commenter 17808 recommends that for non-Hg HAP as well, owners/operators of a LEE unit have the option to conduct an annual performance test to demonstrat e that emissions are less than 50 percent of the relevant emissions standard. The commenter notes that the EPA proposes that for all other HAP, LEEs would demonstrate continuous comp liance and maintain LEE status through monthly fuel analysis as well as performance (stack) testing every 5 years. However, in many cases, according to52 the commenter, monthly fuel testing would be re dundant as this requirem ent would result in the repetitive testing of the same fuel shipment.

Comment 37: Commenter 17807 suggests the EPA reconsider th e use of fuel samples as the method of compliance for the maintenance of LEE status and a lternatively 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. Accordi ng to the commenter, if the 12-month rolling average of fuel samples shows a monitored parameter over the threshold then a stack test would be triggered. This procedure would ensure that only an actual emissions exceedance could cause a unit’s LEE status to be lost.

7. Liquid oil-based EGUs.

Comment 38: Several commenters (17758, 17775, 18428) suggest the alternative fuel analysis provisions should apply to all aff ected liquid oil-based EGUs. One co mmenter cites the summary of the rule proposal 76 FR 25031, in which the EPA states th at this provision applies only to limited-use oil units and not other affected oil un its. The commenter explains that th e provisions of the proposed rule itself (sections 63.10005(c) and 63.10006(s )) appear to indicate that owne rs/operators of all affected liquid oil-fired units may perform fu el analyses to demonstrate ini tial and continuous compliance with applicable emission limitations, as an alternative to performance stack testing. The commenter requests that the final rule clarify that th e alternative to use fuel testing to demonstrate init ial and continuous compliance applies to all affected liquid oil-fi red EGUs, not only limited-use units. Commenter 17775 also requests that the EPA further explain its preamb le statements in order to allow meaningful comment on that procedure.

Comment 39: Commenters 17386 and 17621 believe the fuel oil metals analysis methods are not sensitive enough to support comp liance monitoring for limited use oil EGUs. Commenter 17386 states that based on contacts with a number U.S. laborator ies, standard available an alytic techniques are not capable of achieving the detection limits require d to demonstrate compliance with proposed MACT emission limits for certain HAP Metals (such as cad mium, beryllium and antimony) in liquid fuel oils. The commenter states the fuel oil concentration fo r cadmium, beryllium and antimony would have to be < 5 ppb to demonstrate compliance with MACT limits , and none of the laborat ories contacted could achieve this detection level.

Comment 40: Commenter 17386 notes the detection limits of the analytical methods for non-Hg metals in oil are too high to support co mpliance verification. According to the commenter, in the ICR Part III database, most of the fuel oil metal concentrations are non-detect values, with detection limits ranging from 0.25 to 10 parts per million by weight (ppmw). The commenter states that this range is equivalent to approximately 10-6 to 10-4 lb /MMBtu, while the proposed MACT metal emission limits for existing oil-fired units range from 10-7 to 10-6 lb/MMBtu. The commenter states that fuel samples from several oil-fired EGUs were analyzed with ASTM D6357, the method specified in the ICR for coal, not oil, and that this method gave lower de tection limits, on the order of 0.01 ppmw, or approximately 10-7 lb/MMBtu. According to the comment er, the use of ASTM D6357 for o il samples may give inaccurate results for metals because the ashing step that work s well for coal can cause the loss of metals in oil samples, resulting in erroneously low metal concentra tions. The commenter assert s that fuel oil metals concentrations would need to be quantifiable below 0.01 ppmw to demonstrate compliance. According to the commenter, the analytical techniques currently used for fuel oil samples by most laboratories cannot measure accurately at those levels. The comme nter suggests allowing 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 clar ify whether the fuel analyses and procedures in the proposed regulat ory language (40 CFR section 63.10008) are only applicable to liquid oil-fired EGUs that desire to meet their ap plicable emission limits through fuel sampling.

Comment 42: Commenter 17760 suggests the EPA should clarif y that all liquid oil-fired units may demonstrate compliance through fuel analysis. The comm enter believes the language in the preamble to the proposed rule and the proposed regulatory language ar e inconsistent regarding the availability of the fuel analysis option. The commenter believes the preamble seems to limit the option to limited-use liquid oil-fired units, citing 76 FR 25031, while the regulatory language seems to allow all affected liquid oil-fired units to utilize the fu el analysis option, citing 40 CFR 63.10000.

Comment 43: Commenter 17796 suggests the requirements for liquid oil-fired units are confusing and should be rewritten for clarity. The commenter cites “What Are My General Requirements/or Complying with this Subpart”, para graph (c)(2), which states that liquid oil-fired EGUs can demonstrate initial and continuous compliance using fuel analys is, noting that these ge neral requirements are contradicted in section 63.10006, wh ich specifies different continuous compliance methods for liquid oil-fired units.

Comment 44: Commenter 17718 suggests that within the proposed regu latory 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 th at the fuel sampling, analyses, and maximum input levels are only applicable to liquid oil-fired EGUs that choose to meet their emission limits through fuel sampling methodologies. The commen ter believes the establis hment of fuel limits appears applicable only to facilitie s that choose to comply via fuel analysis. The commenter believes if facilities apply CEMS, accurate comp liance can be determined at the emission point and, therefore, the fuel input becomes irrelevant. The commenter al so states that there are numerous inaccurate section/paragraph references w ithin the proposed regulatory language of 40 CFR section 63.10011(b). The commenter suggests the EPA caref ully review this section to properly link references to the appropriate sections and paragraphs.

8. Monthly fuel analysis.

Comment 45: Several commenters (17386, 17758, 17760, 17902) be lieve the monthly fuel analysis contained in section 63.10006(s) would be unnecessarily burdensome, costly and impractical. One commenter suggests requiring fuel an alysis to be performed on each ship ment of oil received should be adequate to demonstrate complian ce. Commenter 17760 notes that oil-fi red plants require verification that fuel oil meets certain specification prior to a ccepting a delivery and after a plant accepts a shipment of fuel oil and places it in a storage tank and that it is highly unlikely that the composition of the fuel oil will change. Commenter 17386 notes that for large fuel oil storage tanks whic h receive oil deliveries less frequently than monthly the requirement is unjus tified and proposes fuel sampling for oil-fired units shall be performed quarterly only during periods when fuel oil replenishment has been made to the fuel oil storage tank. Commenter 17902 reco mmends that this requirement be revised to require sampling only when there is a fuel switch, new fuel, fuel ship ment, 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 test ing 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 e xplained by fuel sources. The commenter suggests a better alternative would be yearly stack testing with a monthly fuel sampling.

Comment 47: Commenter 17807 notes that although they prefer that SO 2 be used as a surrogate, they do not object to allowing utilities to opt to perform routin e HCl testing or continuous emission monitoring. The commenter requests th at the EPA allow utilities to choose to demonstrate compliance for HCl through routine fuel sampli ng. According to the commenter, mostfacilities currently utilize some type of fuel sampling methodology to test thei r fuels burned, and the chloride content can be analyzed using ASTM 4208/300 along with existing fuel test methods. The commenter notes that facilities will need to establish an upper chloride threshold in the fuel as demonstrated by HCl stack testing and that once the limit is established, the dailyor weekly chloride analyses on a 30-day rolling average will demonstrate compliance provided the threshold is not exceeded. The commenter believes this will provide an established procedure to ensure compliance.

9. Site-specific fuel analysis plans.

Comment 48: Commenters 17775 and 17800 state that althou gh the commenters do not object to a requirement to submit a plan or to use standa rdized procedures, as required by section 63.10008; however, because there is so much di versity in how fuel is received, stored, and processed at individual facilities, the commenters assert that the EPA needs to allow more flexible procedures to accomplish the primary objective.

Comment 49: Commenters 17775 and 17800 discuss that und er proposed section 63.10008(b)(1), the proposed plan must be submitted to the Administrator at least 60 days before the fuel analysis. Because some of the information required to be included may change from analysis to analysis, the commenter assumes the EPA intends sources to submit a new plan or update the existing approved plan if information changes. For example, the commenter notes , the plan must include id entification of all fuel types anticipated to be combusted and whether th e source or fuel supplier will conduct the analysis. Proposed section 63.10008(b)(2). Acco rding to the commenter, although it might be possible to submit that information 60 days in advan ce of the initial demonstration and receive approval before conducting the analysis, it may not be possible for subsequent anal ysis in response to changes in fuel type or fuel mixtures (since those might occur with less notice or planning). According to the commenter, the requirement to submit a new or revised plan also ma kes little sense if monthly analysis is required. The commenter requests that the EPA either remove the requirement for advance submittal and approval of a plan after the initia l compliance demonstration, or remove the requirement to include in the plan information that might change.

Comment 50: Commenter 17821 does not object to the require ment to develop a site-specific fuel analysis plan and does not object to submitting it to the EPA; however, the co mmenter sees little value in the requirement that the EPA must approve the plan before it can be implemented. The commenter believes that the requirements for development of the plan are specified in the proposed rules and sources are fully capable of following and implemen ting those requirements. The commenter notes there will be hundreds of fuel analysis plans submitted to permitting agencies and the EPA in a very short period of time which can result in a backlog of plan s 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 co mmenter 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 commen ter therefore urges the EPA to modi fy this section of the proposed rule to eliminate the requirement for the EPA to appr ove fuel analysis plans pr ior to conducting testing.

Comment 51: Commenter 17881 notes that section 63.1008, requi ring development of a site specific fuel analysis plan, as applicable, is very unclear how to determine if you need a fuel analysis plan as section 63.10005 does not stipulate wh ich units are required to conduc t fuel analysis on an on-going basis. Provision (b)(2)(iv) requires that the minimum expected detecti on level for chlorine, fluorine, Hg, and metals be included in the plan. The commenter notes that the EPA should clarify that fluorine is only applicable for oils. The commenter advocates that the EPA provide guidance on required minimum detection levels for these parameters.

10. Performance testing and fuel analysis.

Comment 52: Commenter 17775 cites proposed section 63.10011(b) that “if you demonstrate compliance through performance testing, . . . [y]ou must also conduct fuel analysis according to § 63.10008 and establish maximum fuel pollutant input leve ls according to paragraphs (c)(1) through (5).” (The commenter notes that Table 8 actually refers to section 63.10011(c) and (d ), but the EPA probably intended to reference (b) and (c).) According to the commenter, table 8 also requires EGUs to continue combusting only the fuel types and mixtures used to demonstrate compliance with fuel input levels under section 63.10011(b) and (c). The commenter states that accordingly, any unit that demonstrates compliance using “performance testing” would, under Table 8, be limited to combusting only those fuels or mixtures used during in itial performance testing.

Comment 53: Commenter 19033 suggests the EPA clarify the m eaning of “highest content” contained in 63.10007(c). The commenter cites an EGU operated whic h is a coal-fired unit with natural gas firing capability during periods of start-up; however, the co al 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 conten t may not be the coal that also has the maximum mercury content.

Comment 54: Commenter 18447 questions the EPA statement in the preamble of the proposed rule that “For units without wet or dry FGD scrubbers that must comply with an HCl emission limit, you must measure the average chlorine conten t level in the input fuel(s) during the HCl performance test. This is your maximum chlorine input operating limit.” The comm enter believes that th is means that once the HCl performance test has been completed and the ch lorine results are known, the fuel that was used during the test cannot be used again. According to th e commenter, this is because the fuel’s measured average chlorine value now becomes the maximum ch lorine limit; the fuel that created the maximum chlorine limit (by virtue of its average) will nowexceed the maximum limit 50% of the time (by virtue of the normal distribution curve) and therefore cannot be used ag ain. The commenter believes as written, it creates a possible incentive to test with a fuel with a high chlorine content, and then switch back to a fuel with a lower chlorine content, whose maximum chlorine content is less than test fuel’s average chlorine content.

Comment 55: Commenter 19033 suggests that th e EPA clarify section 63.10007( c) with respect to the requirement that coal which has the highest non-Hg metals must be tested, especially if the EGU56 operator elects to comply using the PM emissions limit, which is a surrogate for non-Hg metals. The commenter suggests that the phrase inquestion be amended, as follows:

“You must conduct performance tests at the ma ximum normal operating load while burning the type of fuel or mixture of fuels that has the highest content-of chlorine, . fluorine, non-Hg HAP metals ( if you elect to comply with the no n-HG metals HAP emission limitation ), and Hg, and you must demonstrate initial comp liance and establish your operati ng limits based on these tests.”

11. Continuous compliance.

Comment 56: Commenter 17881 suggests the provisions of section 63.10021(a)(2) should state that fuels used for start-up/shutdown and flame stabiliza tion are exempted from this requirement. Also, according to the commenter, it is the fraction of heat input which is relevant to meeting the emission limit, not the overall fuel mass (based on the HAP i nput calculations at sec tion 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 requiremen t in the rule, and the utility indus try already reports fuel usage to the Department of Energy, Energy Information Admi nistration in various repor ts. The commenter notes that this information is available for the EPA to access.

Comment 57: Commenter 17881 suggests that w ith respect to section 63.10021( a)(5), if the EPA allows actual sampling vs. theoretical results, then these provisions would not apply as direct sampling would be used to demonstrate compliance. The comment er believes the monthly compliance demonstration through fuel analysis is all that is required to comply with the Hg emission limit instead of trying to theoretically pre- qualify a fuel.

Comment 58: Commenter 17781 suggests that with respect to 63.10021(a)(3), if the EPA allows actual sampling versus theoretical calculated results, then the provisions of this paragraph would not apply as direct sampling would be used to demonstrate compliance. The commenter believes the EPA should leave it up to the facility to demons trate compliance, as it does not make sense to try and pre-qualify emissions. According to the commenter, the logistics of trying to pre-qualify a fuel does not work in the real world, as what is sampled for the pre-qualification analysis is most likely not what is really burned, as oil is blended in a storage tank prior to burning ; the onus of proof of co mpliance is on the facility.

12. Chloride concentration variability.

Comment 59: Commenters 17816 and 19114 note HCl CEMS curre ntly are not commercially available or adequate for in-stack measuremen ts at coal-based EGU’s, and are not anticipated to be available by the compliance date of the rule. As a result, accordi ng to the commenters, sources will be forced to either take a fuel limit or an operating parameter limit. The commenters believe the fuel analysis limit is impractical because of the inherent variability of ch loride concentrations in coal, both between various ranks of coal and within the same coal category. According to the co mmenters, it will be impossible to control fuel deliveries in such a manner as to negate the possibility of burning co al with chlorine content above that which was used during compliance testing.

13. Stop belt sampling (section 63.10008(c)(1)(i)).

Comment 60: Commenters 17715 and 19114 suggest the EPA remove the provisions for affected sources to conduct stop belt sampling or to pull sa mples 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 th e 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 ha ve coal piles that are gr eater than 15 acres in area and gathering five samples uniformly spaced at a depth of 18 inches will not adequately represent what is being burned during the test period.

Comment 61: Commenter 17722 notes that stopping and starting a coal belt that is moving tons of coal is problematic and labor intensive. According to th e commenter, the sampling procedures are applied to screw conveyors, and the commenter believes it is impo ssible to withdraw a six- inch wide cross section from a screw conveyor because of the auger system.

Comment 62: Commenters 17722 and 19114 suggest the EP A should allow the EGU operator to determine the best available met hod to collect a representative sample. Commenter 19114 suggests that the EPA specify a number of representa tive fuel samples during the testing.

Comment 63: Commenter 17800 believes the proposed stop belt sampling requirements for collecting composite fuel samples is not reasonable and appare ntly would not allow for the use of continuous belt samplers. According to the commenter, in additio n, many belts cannot be restarted with coal on them because the belt is too heavy for th e motor to start. The commenter a sserts that for sampling piles or trucks, the rule requires (among ot her things) use of a “square shovel, ” collection of samples at a depth of exactly “18 inches,” colle ction at five locations “uniformly spac ed over the surface of the pile,” and breaking of pieces larger that ex actly 3 inches (citing proposed s ection 63.10008(c)(2)(ii) and (d)). The commenter believes representative samples can be take n with shovels of other shapes, at depths greater or less than 18 inches, and without measuring the actual size of indivi dual coal pieces. The commenter requests that the EPA remove the prohibition on movi ng belt samplers and reexamine and moderate the pile sampling requirements to provide more realistic criteria (e.g., use the same shovel for all samples, collect samples at a uniform depth of approximately 18 inches, and break apart large pieces (e.g., pieces greater than 3 inches).

Comment 64: Commenter 17881 expresses concern over sampling from a belt, as th ere 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 a nd tagged out in order to cross the ve rtical plane of a belt. According to the commenter, plant personnel curre ntly collect coal samples from a feeder chute just prior to the coal mill, and the commenter suggests the EPA should consider other sampling alternatives to those currently presented insection 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 opera ting problems. According to the commenter, every time a coal belt is stopped, a risk is incurred, however sli ght, of having difficulty restarting the belt, and it is possi ble to get good representative samp les without stopping the coal belt. According to the commenter, EGUs have been follo wing such practices succe ssfully for many years. The commenter believes the EPA should eliminate the re quirement to stop the coal belt to take samples.

Comment 66: Commenter 19121 believes requiring belt stop and starts during pl ant operation is dangerous, logistically and operati onally intrusive, and unnecessary.

14. Coal sampling methods.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 comm enter notes they utilize automated mechanical coal sampling systems that are ope rated under procedures such as those described in ASTM D2013. According to the commenter, these automated methods are widely accepted and do not require the laborintensive and time-consuming proce dures described in the above refe renced 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 ru lemakings, the EPA has referenced ASTM standard practices. The commenter suggests these rules should allow the use of those standards and should not require a manual method of sampling.

Comment 68: Commenter 17821 strongly urges the EPA to avoi d writing detailed sample preparation procedures as specified in section 63.10008 (d), (d)(1 )-(7). In lieu of the ag ency writing their own procedures, the commenter believes the proposal should reference approp riate ASTM standards that are widely used by the utility industry, and others and such sample prepar ation methods that are written by experts in their fields and are pe er reviewed. The commenter notes th at in other rule makings, 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 th e challenge of writing special procedures that are unique to this rulemaking.

15. Other comments.

Comment 69: Commenter 17725 notes that the EPA defines the two coal-fired unit subcategories as based on 1) the calorific value of th e coal the boiler is designed to co mbust and 2) the boiler dimensions in terms of height-to-depth ratio. According to the commenter, the larg er boiler dimensions are a result of the inherently higher mineral matte r of these fuels. The commenter states that there are two issues that warrant clarification so th at compliance requirements are easily determined and understood: First, many, if not most lignite units burn a bl end of coals, e.g., lignite and P RB; and second, the industry standard for determining heating value of as -received coal is based on an ultima te/proximate analysis. According to the commenter, clarification is needed from th e EPA regarding their reliance on the moist mineral matter free heating value (ASTM D388) of coal. The commenter states that this method is typically relied upon to classify distinct coal regions and individual seams don’t varysignificantly within a region. According to the commenter, the ASTM D 388 method specifically ex cludes 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 re dundant stack test requirements. The commenter notes that the EPA has established alte rnative limits for compliance for various HAP groups and these options provide the sour ces with a measure of flexibility. However, the commenter believes the EPA is requiring stack tests for both the pollutan t and surrogate. According to the commenter, since limits for each pollutant (or surr ogate) have been independently es tablished 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 wi th 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 Meth od 19 fuel factor (F-factor) methodology to convert emission concentrations into units of lb/MMBt u. 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 th e commenter, it is wholly unclear how one would convent a fuel cons tituent 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 heatrate of the unit in which the fuel is to be combusted. The commenter suggests the EPA should either remove the referen ce to converting the con centration 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 per cent water content lim it for oil, rather than setting HCl and HF emissions limits for liqui d oil-fired EGUs. The comme nter notes ASTM test methods are available for measuring the percent water content of fuel oil (D95 and D473). The commenter suggests that plant operators would test each shipment received to ensure compliance with the proposed limit.

Comment 73: Commenter 18483 suggests that should such IGCC or other generating units remain subject to the rule, fuel sampling should be allowed as a sole compliance demonstration option in lieu of a Hg CEMS or sorbent trap methodology due to Hg being removed from the fuel prior to combustion and the lack of post-combustion controls.

Comment 74: Commenter 19114 notes that IGCC processes are inherently different from other methods of coal-based electric generation and more similar to natural gas combined cycl e units in te rms of design and emissions. According to the commenter, if IGCC un its are not exempted in the final rule, then the standards should be revised to a ddress the unique charac teristics of IGCC pro cesses. The commenter believes that issues that would need to be addr essed include: the applicab ility of fuel sampling requirements, gasifier feedstock sampling, raw s yngas sampling, clean syngas sampling, syngas fired in the combustion turbines, syngas fired in a flare, processed syngas fired inthermal oxidizer, etc.

Comment 75: Commenter 17775 notes concerns with applicabili ty 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. Accordi ng to the commenter, with the exception of the filterable PM limit applicable to units using PM CEMS, Table 7 also does not distinguish between compliance options. Instead, states the commenter, Table 7 refers to various parameters depending on which control device “your operating limits ar e based on” (citing section 63.10011(b)(6)). (The commenter notes that although the ru le actually cites section 63.10011(c) (6), that provision addresses fuel sampling, not operating limits. As a result, the EPA probably intended to reference (b)(6).) According to the commenter, Table 7 also refers only to specific control de vices and not compliance options. With respect to fuel input levels, the co mmenter asserts that para graphs (c)(1) through (5) specify how fuel input levels are established but do not id entify which EGUs must establish them. The commenter notes that proposed section 63.10008 requi res “performance fuel analysis tests” “as applicable”; Table 6 requires fuel analysis “as stated in section 63.10008”; and proposed section 63.10031 requires compliance reports to address compliance with fuel in put limits “for sources that demonstrate compliance through performance testing.”

Comment 76: Commenter 17801 notes on page 25037 of the proposal the EPA provides an option to monitor inlet chlorine , fluorine, non-Hg metals and Hg in liquid oil to meet outlet emission rate limits, noting that it is reasonable to do so because oil-fire d units remove these fuel-borne HAP from the oil60 before combustion in lieu of inst alling air pollution contro l devices (APCD). In response to the EPA’s request for comment on the viabilit y of this approach for IGCC, the commenter agrees that fuel monitoring (of the syngas) should be an option for IG CC as well based on the same reasoning as to that fuel “clean-up” vs. APCD. The commenter believes fuel sampling should be allowed as a sole compliance demonstration option for IGCC in lieu of a Hg CEMS due to Hg being removed from the fuel prior to combustion and the absence of post-combus tion controls in lieu of pre-combustion control.

Response to Comments 1-76: Based on the comments received and a further review of the technical challenges associated with the proposed fuel anal ysis requirements, the EPA has not finalized the proposed fuel analysis requirements. Fuel analysis of moisture for certa in liquid oil-fired units remains a compliance assurance option. As the rule no longer re quires operating limits for pollutants based on fuel content or fuel analysis, the comments summarized above are largely moot. For low emitting EGUs, the agency agrees that the proposed LEE ongoing eligibility requirements were overly burdensome and restrictive. As a result, existing solid- or liquid-fired units that qua lify for LEE status for Hg will be required to conduct a 30-day test for Hg using Me thod 30B each year. Neith er fuel analysis nor adherence to an operating limit will be required. Should an annual test show ineligibility for LEE status, the unit would revert to the requirements for Hg m onitoring using CEMS or sorbent traps or quarterly emissions testing. For other pollutants, a unit can qualify for LEE for an applicable pollutant if all performance tests over a 3-year period demonstrat e that the unit remains below 50% of the emission limit for the applicable pollutant. Under those ci rcumstances, the unit would qualify for emissions testing of that pollutant every 3 years to demonstrate ongoin g 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 wi sh to demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel moisture conten t, and if your fuel moistu re content is no greater than 1.0 percent, you must measure fuel moisture content of each shipment of fuel if your fuel arrives on a batch basis; or measure fuel moisture content daily if your fuel arrives on a c ontinuous basis; or obtain and maintain a fuel moisture certification from y our fuel supplier. Should the moisture in your liquid fuel be more than 1.0 percent, you must either: (1 ) conduct HCl and HF emissions testing quarterly and develop a site-specific monitoring plan to monitor appropriate operating parame ters to ensure that operations remain consistent with those present dur ing performance testing; or (2) use an HCl CEMS and/or HF CEMS.61 5A04 - Testing/Monitori ng: Detection levels

Commenters : 17316, 17386, 17621, 17622, 17711, 17715, 17725, 17730, 17775, 17790, 17800, 17821, 17873, 17902, 17914, 18034, 18429, 18443, 18498, 18023

1. Analytical techniques and detection levels.

Comment 1: Commenters 17316 and 17386 state that based on c ontacts with a number of laboratories, it appears that standard available analytic techniques are not capabl e of achieving the detection limits required to demonstrate compliance with proposed MA CT emission limits for certain metals, such as cadmium, beryllium and antimony, at least in oil. Comm enter 17316 refers to a Table (note: this table is not attached to the comment), that allegedly addre sses the concentration in oil for each regulated HAP metal corresponding to proposed MACT emission lim its for oil fired EGUs. According to the commenter, for cadmium, beryllium and antimony, the con centration in oil would have to be < 5 ppb to demonstrate compliance with MACT limits, and according to the commenter, none of the laboratories contacted could achieve this detection level. Mo reover, the commenter ques tions the accuracy of analysis results determined by the specialized methods used to reach the detec tion levels required for such a compliance demonstration on fuel oil.

Response to Comment 1: The requirements for fuel sampling and analysis for the listed metals have been removed from the final rule.

Comment 2: Commenter 17622 states that based on informat ion provided in the proposed rule, they cannot validate that technology exist to accurately measure the proposed emission limits for new units. The commenter states monitoring systems have to be capable of accurately measuring emissions below the limits established by the EPA and in practice emi ssion control technologies must be able to provide long term control at emission levels below the pro posed 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 operationa l variability, fuel changes, and st artup and shut down times that occur during normal plant operations, and in order to remain in compliance ove r the averaging period. Therefore, according to the commen ter, emission limits need to be established within the capabilities and accuracy of monitoring systems, and when owners /operators purchase control equipment, they may add an operational margin in thei r specification and request for performance guarantees. The commenter believes compliance monitoring and measurement for the proposed new unit emission limits are of concern, and vendor guarantees may be problematic without the ability to consistently measure remaining pollutants at the low emission levels proposed.

Response to Comment 2: As more thoroughly discussed in 4A03 of this document, the new source limits have been revised in order to represent the representative detection le vel (RDL) instead of the MDL determined by a single source.

Comment 3: Commenter 18429 believes the EPA’s proposed te st methods are not adequate for the excessively low limits for new sources, including both Hg and HCl CEMS. The commenter references EPRI analyses. The commenter suggests the EPA comple te a re-review of the limits and test methods for new units to provide a meaningful MACT w ith 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 mana ged BDL data in analyzi ng the floor and developing emissions limits for this rule.

Comment 4: Commenter 17914 is concerned that available CEMS equipment is not accurate enough in commercial field applications to re liably report total PM at the propos ed 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 fo r them to provide performance guarantees in light of the inaccuracies of the refere nce methods for PM. The commenter notes that the proposed rule indicates no allowance was made for data collected at or below the MDL and in stead 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 coul d result in errors as hi gh as 50%. The commenter references U.S. EPA “Review of National Primary Drinking Water Regulations: Analytical Methods - Reassessment of Practical Quantitation Limits, noti ng that the EPA guidance suggests a multiplier of 5- 10 times the MDL for determining the PQL (in abse nce of sufficient inter- laboratory study data).

Response to Comment 4: In response to comments, the final ru le does not have a total PM limit. The facilities also have the option of pe riodic 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 met hod sensitivity to evaluate the ability of test methods to measure HAP and surrogate paramete rs at the MACT limits, and includes a summary table to the test method adequacy in their commen ts (Table 2-1). The commenter notes that as the proposal also requires facilities to establish opera ting limits for some HAP based on initial performance tests, which would then become the effective emi ssions 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 requir ements for operating and fuel limits with the exception of a PM CPMS and provides th e option for periodic tes ting for non-Hg HAPs. Hg sorbent monitoring allows for sensitivities below the emission standards.

Comment 6: Commenter 18034 states the proposed emission lim its for some of the pollutants are very near and in some cases significantly less than th e documented MDL of the re quired emissions testing and monitoring methods and even contradict ce rtain recordkeeping prov isions, which makes it impossible for companies to demonstrate compliance with the emission limits. The commenter recommends the EPA bring the emissions limits into harmony with the capabiliti es of the prescribed methods and procedures for demonstrating complian ce. 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-fir ed EGUs was measured within the calibration range of the analytical technique and met all QA/QC criteria of Method 30B in a 4-hour run.

Comment 7: Commenter 17715 notes that NIST traceable standards, gaseous oxidized standards traceable to NIST and agreed to standard Hg vapor curves are not available, and without them there will be non-uniform reporting of emissions.63 Response to Comment 7: It is the EPA’s position that the Interim EPA Traceability Protocol for Qualification and Certification of Elemental Merc ury 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 th e NIST-traceability necessary for mercury monitoring programs at this time. The major vendors of mercury CEMS have, for some time, been marketing elemental mercury calibration gas generators that are directly traceable to NIST elemental mercury reference standards. We agree with the commenters’ point that NIST does not currently directly certify oxidized mercury gas generators. However, oxidized gas ge nerator NIST traceability is establ ished through the assessment of the individual components of the calibrator. The inte rim protocols for certifying mercury gas generators allow sufficient flexibility to certify the gas generators in an appropriate range from existing NIST traceable gas standards. The EPA does not believe it necessary to make available standard mercury vapor pressure curves in order to implement the mercury monitoring program set forth in this rule as the EPA’s primary approach to NIST traceability for calib ration gases is based on di rect comparisons with NIST reference materials and standards.

Comment 8: Commenter 17790 believes the EPA should speci fy specific guidelines for analytical detection limits stack testing for non-Hg HAP metals and how to handle results that are below the detection limit.

Comment 9: Commenter 17800 believes the non-Hg metals da ta collected during the 2010 ICR showed reported detection limits for laborator y analysis that were highly variable even for data for the same metal and from the same laboratory. The comment er suggests the EPA specify minimum detection limits and procedures for combining front and back half fractions to report tota l concentrations in order to determine compliance on a consistent basis.

Response to Comments 8 - 9: The MDL for non-Hg metals will depend on volumes samples and the analytical finish used. Table 5 will be revised to specify the proce dures for handling MDL results while adding up multiple fractions.

Comment 10: Commenter 17902 believes the EPA must allow fo r 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 potentia l for error.

Response to Comment 10: As more thoroughly discussed in Sec tion 4A03, the emission limits for new and existing sources were set at a minimum of th ree times the RDL to provide for measurement and process variability at low levels when the UPL base d on the data was not greater than three times the RDL.

Comment 11: Commenter 17775 agrees that performance testing for units using CEMS should not be required any more frequently than every 5 years. The commenter also supports inclusion of a reduced testing provision for tests conducted more frequently. However, the commenter does not believe that the EPA has provided sufficient support for many of the tes ting requirements in this proposal. Moreover, the commenter does not believe that the 50 percent criterion is reasonable gi ven the extremely low levels of the EPA’s proposed limits. The commenter request s that the EPA remove this restriction. The commenter states the EPA has provided no reason for th is restriction, or data s uggesting that any source could achieve 50% of the proposed emission limits, some of which are establ ished 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 operati on remain consistent with prior successful testing should be sufficient to ensure re presentativeness of th e prior test(s).64 Response to Comment 11: In the final rule, there is no requirem ent 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 va lid for purposes of determ ining compliance with the emission limits under this rule. The EPA disagrees and will retain the 50% crit erion for reduced testing. Sources operating at low levels can show comp liance with the 50% limit by increased sampling volumes. Also, the sources may opt to use CEMS or CPMS in lieu of the rep eated periodic testing.

Comment 12: Commenter 17730 suggests the EPA specify mi nimum detection limits for laboratory analysis for all pollutants and provide procedures fo r calculating total PM combined concentrations of single metals and total non-Hg metals. The commenter notes that based on data co llected in the ICR, the reported detection limits for laborator y analysis were highly variable ev en for data for the same analyte from the same laboratory. The commenter suggests that to determine compliance on a consistent basis, the EPA needs to specify minimum detection limits a nd 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 spec ify a prescriptive minimum detection limit for laboratory analysis of all pollutants. Minimum detection limits will improve with future technology and analytical te chniques. Since total PM has been rem oved 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 comment er notes that the precision and accuracy of the current continuous HAP emission monito ring is not field proven to reliabl e reflect actual emissions data. The commenter believes very low HCl, Hg and PM c oncentrations are difficult enough to measure using stack tests (as evidenced by the numerous values at orbelow detection levels inthe ICR data set), and accurately measuring these concentrations with CEMS is nearly impossible. According to the commenter, to date Hg, PM and particularly HCl CEMs have not been designed to measure very low pollutant concentrations. The comm enter believes that the EPA s hould recognize the limitations that these CEMS have and use them only as an indi cator of compliance, not as a compliance method. According to the commenter, these shortcomings, when used in series to determine emission rates, will result in substantial monitor downtime and the potential for numerous non-compliance events.

Response to Comment 13: An Hg CEMS or an HCl CEMS are opti ons for use as the performance test method for the applicable Hg and HCl emission limits. If a source is concerned about the use of these methods in such a manner, the rule provides for othe r options (sorbent trap m onitoring 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-sp ecific operating limit expresse d in terms of the raw output of the PM CPMS. The operating limit aids in en suring that the source is operated and maintained in accordance with good air pollution control practic es to minimize emissions so that the source can continue to operate in compliance with the emission li mit as demonstrated in a periodic stack test. The final rule does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this appr oach (see the final preamble for further discussion).

Comment 14: Commenters 17316 and 17386 state that establishing HAP emission limits at the boundary of what can be detected by available analytic techniques does not seem reasonable and that the incremental benefits (HAP reductions) to be achiev ed by extending emission limits to such low levels, lying at the edge of detestab ility, do not seem justified.65 Response to Comment 14: As further discussed in Section 4A, the emission limits are set at levels which EPA believes are consistent w ith 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 thatdespite not being able to “meaningfully quantify the concentration(s),” the EPA used data that was id entified as being “below detection limit” (BDL) or “detection level limited” (DLL) wh en establishing the MACT floors. The commenter suggests this means that many of the new and existing source MACT limits are based on data that is unquantifiable. The commenter references the comments submitted by EPRI that discusses that using BDL and DLL data also caused several of the new source limits to be so stringent that they are actually below the applicable method sensitivity. The commenter recomm ends 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 greatly complicated by the fact that a numb er 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 quantifica tion level of the method chosen for dem onstrating compliance, and that if an emission limit is set below the quantification level, then as the court in Amoco Oil cautioned, the limit would be unenforceable. The commenter also cites a January 2011 memo in which the EPA acknowledged that measurements at levels below analytical detection and quantitation levels are associated with increased measurement uncertainty. The commenter provides additional discussion on quantitation limits and recommends that the EPA us e 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 estab lishing the floor values and setting emissions limit and we have discussed this procedure in detail el sewhere in this document. The EPA is not setting standards below the detection lim it so those comments are moot.

Comment 17: Commenter 17873 believes that th e 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 implicati ons for the long-term ener gy security of the nation. The commenter believes the EPA should not be setting national energy policy through a CAA rulemaking.

Response to Comment 17: The Hg limit for new coal-fired EGUs was measured within the calibration range of the analytical technique and met all QA/QC criteria of Method 30B in a 4-hour run, meaning that current instruments can measure mercury emissi ons 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 ne w 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 specific test methods.

Comment 18: Commenter 17711 notes several potential i ssues with the EPA Methods 5, 23, 26/26A and 29 as reference methods for measuring source em issions of PM, dioxins/fur ans, HCl, and Hg. The commenter notes that the extraction, processing, and analysis of sample s 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 commente r’s view that potential issues with the listed EPA Methods renders them less than usef ul for this rule. The rule identifies potential problematic areas for the Methods, and provides alternatives, both w ithin the Methods 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 compliance. The EPA Method 23 is not requir ed for the final rule. The EPA agrees that “extraction, pr ocessing and analysis” can lead to random error and variability that would not be seen due to the truncation of the data set at the MDL. This is the basis for the emission standards being set at no less than 3 times the RDL as discussed in the preamble and 4A03 of this document.

Comment 19: Commenter 17711 states that aside from a 1996 study by R. Shigehara, the commenter is not aware that the EPA has published any results from studies necessary to de termine 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 utili zed to collect data fo r setting the proposed MACT standards and would be used to demonstrate compliance with the propos ed standards, the EPA has provided the detection limits for only Method 29, and even in those cases no EPA reports are available to assess the validities of the detection limits specified w ith the test methods. According to the commenter, even in the absence of such reports, if one assumes that these valu es are correct and then applies the 3.18 Student-t multiplier for three samples to th e detection limits, the estimated quantitation limit of Method 29 would be 1.8 μ g/m3. An examination of the data in the EP A’s MACT database shows that it includes measurements below these values. The commenter s uggests 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 comme nt. The Method 29 detection limits published in the method only represent approximate estim ates for each analytical technique to provide a guideline on choosing the appropriate analytic al technique. The EPA Method 5 MDL was published with the promulgation of Method 5I. The Method 26 and 26A typical method detection limits were also published. As more thoroughly discussed in 4A03 of this document, the EPA disagrees that only values above the method’s quantitation limit should be used.

Comment 20: Commenter 17725 provides a discussion regard ing a caveat of Method 30B that allows for an alternative approach for quantifying low masses. The commen ter 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 calibration curve; all points used in the generation of the calibra tion curve must be within ±10% of the expected value. Furthermore, according to the commenter, continuous calibration verification standards (CCV S) must be performed no more than every 10 field sample analysis and also be within ±10% of the expected value for the field samples to be considered valid. The commenter asserts that therefore, any masses and ultimately effluent concentrations that are determined using the respons e factor approach are not of the same quality or uncertainty a those determined by the calibration cu rve (i.e., masses above the LOQ). According to the commenter, all masses determined above the LOQ are of acceptable quality and a known uncertainty of ±10 percent, and conversely, masses determined us ing the response factor approach are of unknown quality and uncertainty, theyare merely estimates.

Response to Comment 20: The agency agrees with the commenter that this could be a concern, especially in light of the low Hg concentration levels that may be m easured under this rule. Therefore, we are proposing in a separate rulemaking an ame ndment to Method 30B that would lower the specified Hg concentration for which the tester must have hi s sample results within th e calibration curve from 0.5 μg/dscm (current specification) to 0.01 μg/dscm. This will mean that in the future, concentrations down at least to 0.01 μg/dscm will be of known quality as described by the commenter.

Comment 21: Commenters 17725 and 18498 disagree with the EPA simply stating a generic MDL/LOQ for the entire Method 30B, as MDL and L OQ data collected vary among labs, analyzers and analysts. One commenter suggests that although the theoretically calculated MDL and LOQ has been shown to be as low as 2ng, in practice the QA/QC at that level is not obtainable. The commenters believe that in practice 10ng is a re asonable range for the LOQ to collect data of acceptable quality and known uncertainty (i.e., ±10 percent) and 5ng is pushing the envelope on the lowest LOQ that should be used when evaluating low level e ffluent concentration data (i.e., ≤ 0.1 μ g/m3). The commenters suggest the response factor approach is used for merely estimating masses below the LOQ, but above the MDL and should not be used when establishing an emission limit as the data of are of unknown quality and uncertainty. According to the commenters, it then fo llows for a typical ICR te st (i.e., 2hr test run collecting 120l of volume) that efflue nt concentrations ranging between 0.04 μ g/m3 and 0.08 μ g/m3 are the lowest that can be reasonably be determin ed with acceptable quality and uncertainty.

Response to Comment 21: The EPA agrees that, in general, th e response factor approach in Method 30B should not be used for estimating masses be low the LOQ, but above the MDL when reporting emissions data for compliance determination as thes e data of are of unknown qua lity and uncertainty. It is the EPA’s intent to ensure that reported Hg emissions data are of known and acceptable quality. In response, the EPA is about to propose an amendmen t 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 μ g/m 3 and 0.08 μ g/m 3 are the lowest that can be reasonably be determined with acceptable quality and uncertainty. In fact, recent testing c onducted as part of the Utility MACT ICR demonstrated that anaverage stack Hg concentration of 0.01 μ g/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, ther e are limitations with each method with regards to detection limits. The commenter ques tions if either method can consistently provide reliable data for compliance determ ination for the proposed limit as factors such as blank contamination,68 positive and negative biases due to flue gas interferences, and analytical 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 ar ea of 0.000050 lb/MMBtu, and the ICR required very long run times of 180 minutes for incr eased detection. According to the commenter, even with the long run times, the proposed emission lim it 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 reli able, repeatable, high quality results this close to the detection limit.

Response to Comment 22: We agree that there are method de tection level capability differences between Methods 26 and 26A and both are allowed by th e rule. The source has the option to choose the method and the required sampling periods consistent w ith expected emissions le vels and the procedures for managing method detection leve ls 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 limits for existing units. The commenter provides a table (Table B- 1) which shows that at the individual metals MACT limits for new coal EGUs, most metals would not be measured accurately. The commenter notes that ASTM D6764-02 states a lower limit of quantitation for Hg of 0.5 μ g/m3, which corresponds to a stack emission for coalfired units of approximately 0.45 lb/Tbtu and this leve l of sensitivity is adequate to measure Hg at the MACT limit for existing coal units, but not at the lim it for new units. The commenter also discusses that analytical detection limits do not consider the many sampling- and matrix-related factors that can raise detection limits at the stack. However, the commenter believes method sensitivity could also be better in practice than indicated in Table B- 1 due to improvements in instrume ntation and collection of larger sample volumes than required by the ICR. According to the commenter, therefore, this comparison was not given as much weight as the ICR results in the determination of method adequacy.

Response to Comment 23: The individual metal MACT limits have be en reassessed to ensure that they are no less than three times the RDL including the data collected with Me thod 29. ASTM 6674-02 has been removed from Table 5 for use with compliance determination to ensure adequate sensitivity for compliance due to the sample volum e restrictions of the method. The EPA agrees that method sensitivity will be improved in the future with improvements in instrumentation and the allowance to run higher sample volume than required minimums listed in Tables 1 and 2.69 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, 17928, 18014, 18015, 18021, 18025, 18037, 18426, 18428, 18429, 18437, 18498, 18539, 19033, 19114, 19120, 19121, 19536, 19537, 19538, 18023

1. Objections to parametric operating lim its for units with CEMS (section 63.10007(c)).

Comment 1: Numerous commenters (17383, 17402, 17622, 17627, 17638, 17675, 17677, 17681, 17689, 17696, 17705, 17715, 17716, 17718, 17728, 17730, 17736, 17740, 17758, 17761, 17767, 17772, 17775, 17798, 17807, 17808, 17813, 17856, 17868, 17873, 17876, 17886, 17902, 17914, 17923, 17925, 18015, 18025, 18037, 18428, 18429, 18437, 18539, 19114 19120, 19121, 18023) oppose the proposed control-device-specific operating limits for de monstrating ongoing compliance on units that are equipped with CEMS because these commenters believe such parametric limits are duplicative to the MACT floor emissions limits that EGUs must meet, unduly burdensome, decrease operational flexibility, make it difficult to operate control equipment at optimum effi ciency, and/or inconsistent with longstanding EPA policies under 40 CFR part 64.

Comment 2: Several commenters (17775, 17868, 18539, 19120) state that proposed section 63.10007(c) is unclear because it does not indicate whether every affected facility is subject to the requirements to establish parametric operating limits, and recommends that the final rule should make it clear that units with CEMS are not required to perform parametric m onitoring or take operating limits. Commenters believe that the purpose of operating limits is to determine compliance between performance tests and that units w ith CEMS or sorbent traps would not require such limits. Commenters 17758 and 17868 state that the EPA has not provided justif ication for requiring units with CEMS to also perform parametric monitoring for the same HAP or surrogate.

Comment 3: Commenter 17868 states that section 63.10022( b) provides that if you demonstrate compliance through performance testing you must establis h operating limits in Table 4. According to the commenter, since all EGUs must demonstrate initi al compliance with each emission limit “through performance testing,” and the proposed rule define s “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 th e “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 obser ves that the other provi sions cited in section 63.10011(b) provide little clarifica tion, that proposed section 63.10007 doe s not discuss applicability, and that with the exception of the filterable PM li mit applicable to units using PM CEMS, Table 7 does not distinguish between compliance options; instead, Table 7 refers to various parameters depending on which control device “your operatin g limits are based on.” The commen ter also states that section 63.10011(c)(6) addresses fuel sampling, not operati ng limits and that section 63.10011(b)(6), the provision the EPA likely meant to cite, refers onlyto control devices and not compliance options. Commenter 17868 concludes that the preamble discussi on contains numerous inconsistent statements and no rationale by which one could determine the EP A’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 shoul d require no proof of compliance beyond a properly calibrated and installed CEMS and that the EPA should revise both the language and tables in the rule to clarify its intent as it relates to CEMS used for demonstrating compliance. According to the commenter, HCl CEMS are not commercially availabl e or adequate for in-stack measurements from electric utility units and likely will not be available by the compliance date of the rule. The commenter asserts that sources will be forced to either take a fuel limit or an operating parameter limit and that the fuel analysis limit is impractical as it relates to a coal -fired facility because of chlorine variability that is inherent in coal. that it will be impossible to control fuel deliveries in such a manner as to eliminate the possibility of burning coal with chlorine content a bove that which was used during compliance testing.

Comment 5: Commenter 18428 states that the preamble di scussion contains numerous inconsistent statements and no rationale by which one could dete rmine the EPA’s intent with respect to these operating limits for units using CEMS and sorbent trap monitoring systems. For example, according to the commenter, the EPA suggests in the following statements that operating limits apply only to units without CEMS:

 IGCC units or units combusting coal or solid oil-derived fuel with PM controls but not using PM CEMS to demonstrate continuous compliance w ould also be required to conduct parameter monitoring and meeting operating limits es tablished during performance testing.

 The second option that we are propos ing 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 cont inuously, along with the already-mentioned frequent (every 2 months) HCl emissions testing.

 When a performance test is conducted, we are pr oposing that parameter operating limitations be determined during the test. Performance tests to demonstrate compliance with any applicable emission limitations are either stack tests or fu el analysis or a combination of both, “ ... units equipped with devices that control PM and HCl emissions but do not elect to use CEMS, would determine suitable parameter operating limits ...”

The commenter notes that in another statement, the EPA suggests that all EGUs with PM controls must establish operating parameters, wh ether or not they have CEMS:

 “ those EGUs with PM emissions controls, withou t HCl CEMS but with HCI control devices, or for LEE, we are proposing that you monitor dur ing 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 mon itoring, initial stack test ing, or periodic fuel analysis that it presumably believes are consistent with that assessment.

Comment 7: Several commenters (17775, 17902, 17925, 18539) st ate that as long as an EGU is complying with one of the options for demonstrati ng “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 th e proposed requirements will duplicate existing requirements in title V CAM conditions.

Comment 9: Commenters 17873 and 17886 express concern th at 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 em ission standard (and therefore protecting the environment) but find itself out of co mpliance with a related operating limit.

Comment 10: Several commenters (17775, 17808, 17813) believe th at it is inappropri ate to hold EGUs to limitations on the operations of its controls set during brief performa nce testing periods that may not reflect the full range of operating co nditions that can comply with the emissions limits. The commenters express the need to be able to make adjustments ba sed 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 st eady state associated with normal performance tests. Commenter 17716 contends that such normal load variations are inconsistent with the proposed requirement to establish a minimum pre ssure drop and liquid inj ection rate on a wet PM scrubber because normal pressure drops at low load w ill result in the reporting of deviations compared to pressure drop limitations set at high load. Thes e commenters advise that when variable load operations are combined with variable coal propertie s, operating parameters can differ significantly from steady state performance test c onditions. These commenters conte nd that based on their operating experience, as long as the unit is in compliance as measured with the CEMS, there is no need to track or limit operating parameters because they vary by design. Commenter 17705 notes that the EPA has recognized many times that CEMS represent the best available me thod 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 CE MS is specified by the applicable standard, the requirements of part 64 do not apply to that emission standard. The comme nter cites the following reference to CEMS from the preamble to the CAM rule: “The EPA believes thatthese types of monitori ng are preferable from a technical and policy perspective as a means of assuring compliance with applicable requirements because they can provide data directly in terms of the applicable emission limitation or standard.”

Comment 11: Commenter 19121 states that th ey support the use of parametr ic 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 se t, other secondary opera ting restrictions should not apply. According to the commenter, such an approach would severely cu rtail 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 comp liance could not be met during the compliance stack test. According to the commenter, the proposed rule makes no menti on of the tolerance of operating parameter limits set during initial compliance tes ting for any pollutant or surrogate. The commenter asserts that if an average of the tests runs is used to set a limit, then even th e initial passing compliance test would have periods of noncomp liance during the runs with parame ters outside the final averaged target parameters.

Comment 13: Commenter 18021 states that one set of operating conditions do not produce operating limits that are properly reflective of systems’ capab ilities. The commenter notes that current operation must be flexible enough to meet not only lo ad swings but also future regulations.72 Response to Comments 1 - 13: The rule does not require monitori ng operating limits where a CEMS is used for the applicable standar d. If a source has PM control equi pment 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. Th e only additional operating parameter requirement will be for liquid oil-fired EGUs whose owners or oper ators choose to use quarterly acid gas emissions testing. The appropriate parameters, monitori ng 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 vari ability in establishing para meter limits because of load changes or changes in fuel, the rule provid es for establishing differe nt operating limits based on different loads. Also, see the response to the foll owing comments about establishing “deviations” from operating limits.

2. Duplication of pollutant testing.

Comment 14: Commenter 17716 states that the EPA has es tablished alternative compliance limits for various HAP groups, providing sources with flexibilityto measure the PM limit, limits for individual metals, or a total non-Hg metals limit to esta blish compliance for metal HAP and to monitor SO 2 or HCl for acid gas HAP. The commenter states that the pr oposed rule requires stack tests not only for the pollutant but also for the surrogate. According to th e commenter, performance tests should be matched to either the pollutants or the surr ogates chosen by the source to s how 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 alte rnative equivalent total or individual non-Hg HAP metals, then the only performance test to be performed is the test to show compliance with the emission standard that applies (in this exam ple, the filterable PM limit). The fi nal rule clarifies this position.

3. General objections to enforceable para metric operating lim its (section 63.10007(c)).

Comment 15: Multiple commenters (17402, 17622, 17675, 17677, 17681, 17696, 17705, 17715, 17716, 17728, 17730, 17775, 17800, 17808, 17873, 17912, 18023) find that the proposed requirements for operating parameters at section 63.99 91(a)(2) particularly problematic because the proposed definition of “deviation” includes operating limits, but the commenters feel operating limits should not be a reportable deviation since they are indicators of compliance and not emission limitations.

Comment 16: Multiple commenters (17730, 17775, 17800, 17820, 17868, 17912, 17914, 18428) believe that the proposed usage of parametric operati ng limits deprives sources of the use of any control device margin, and allows enforcement for events be yond 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 emissi ons, and that exceedances of those limits therefore indicate an exceed ance of the emission limit. The commenters’ view of operating parameters is that to the extent possible, operato rs 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 conduc t 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 suchsources could avoid73 surrendering whatever margin of co mpliance they have would be to de liberately reduce performance of their controls to attempt to genera te the least stringent operating limits consistent with achievement of the applicable emission standard. The commenters c onclude that the proposal encourages sources to focus their attention on learning how to manipulate ope rations to allow testing as close as possible to their emission limit by reducing performance of their co ntrols. These commenters generally believe that the parameter ranges in Table 4 must be establ ished 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 w ith the MACT standards rather than the proposed provision s for parametric monitoring. Commenter 17775 refers the EPA to an attached report by McRanie Consulting entitled “C omments on the Proposed Utility MACT Rule - Operating Parameters” (July 2011). Commenter 17675 stat es that other MACT standards like subparts LL and MM take the right approach to parametric m onitoring. The commenter states that these standards require that corrective actions are ta ken to respond to parameter excursi ons and that the failure to take corrective action is a violation.

Comment 17: Several commenters (17675, 18037, 18429) genera lly believe that the CAM approach (that allows operators to propose ex cursion levels and response require ments for approval by the title V permitting authority) is a proven method of obtai ning reasonable assurance of compliance while recognizing the wide variations in parametric ranges that can occur during opera ting periods that are in compliance with the underlying emissions limit.

Comment 18 : Commenter 17912 states the operating paramete rs 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 em ission limit for new and reconstructed EGUs, the proposed emission limit is 0.050 lb/MWh as measured by a manual stack test. However, the commenter asserts, if a CEMS for filterable particulates is used to demonstrate compliance, then, to be in compliance on a continuous basis, the owner or op erator must “[m]aintain the PM concentration (mg/dscm) at or below the highest1-hour average measured during th e most recent performance test demonstrating compliance with the total PM emissi ons limitation.” The comm enter states that to demonstrate continuous compliance, the EPA proposes to average the emissions measured by the CEMS over 30 days for reporting purposes. Nowhere, howev er, according to the commenter, does the agency explain how an emission limit derived from a single, one-hour measurement can reasonably be expected to account for the all of the variab le conditions that may occur during any given day, let alone a month or a year. The commenter states th at federal courts have explaine d that an emission standard is “‘achieved in practice’ [when it] is interprete d 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 oper ating limits the EPA unreasonably extends its authority beyond establishing the appropriate emission standard to governing the way a company operates a unit to meet a standard. According to th e commenter, the prescribed operating parameters (scrubber pH, etc.) and averaging method used to demonstrate compliance with those limits create a secondary and overlapping regulatory obligation likely to result in exces sive control process cost and material waste.

Comment 20: Commenters 17873 and 17740 state that operat ing 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 equipm ent at different loads is difficult. The commenter notes that the ability of its coal generating units to change load quick ly and efficiently is critical in accommodating variable wind energy. The commenter is concerned about the adverse effect on grid74 integration due to such additional plant operating cons traints at the same time the company is supporting significant renewable energy pe netration 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 ba ghouse 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 be low optimal levels or in a manner that would jeopardize compliance. The commenter recommends th at the operating limits should only be applied in this rule as a work practice standard with deviat ions requiring investigati on and corrective action as appropriate or necessary, but shoul d not be considered non-complianc e. The commenter further notes that this approach should be appl ied along with revising th e 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 eff ectively setting enforc eable 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 alterna tive compliance demonstrati on options, including less frequent periodic stack tests – no more often than annually – and l onger averaging times. According to the commenter, it may be difficult to meet these site-specific limits at a ll times under all operating conditions.

Comment 23: Several commenters (18023, 1775, 17800, 17821, 17868) state that a CAM approach has already been upheld as sufficient to satisfy th e 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. Comme nter 17705 adds that the EPA should not consider enforceable limits on control device operations unless th e agency clearly demonstrates this is the only means of assuring compliant emissions. Commente r 17705 states that establishing the appropriate parametric limits must be done on a case- by-case basis as allowe d under CAM rules.

Comment 25 : Several commenters (17725, 17808, 18025) state that the proposed ru le 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 facili ty must initiate a corr ective action to address the excursion similar to what is re quired in 40 CFR part 64 for CAM.

Comment 26: Commenter 17716 recommends an alternative approach to establishing representative control device operating ranges based on a statistical analysis of historical operating data during periods when the control device was operating properly.

Comment 27: Commenter 18023 takes exception to the stated assumption in the preamble that a baghouse or ESP can meet the proposed PM limits and the associated site-sp ecific 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 contro l technologies will be necessary to meet the sitespecific limit continuously. Commen ter 18023 states that the site-s pecific limit is completely unworkable and must be removed and that even if th e EPA refuses to remove the site-specific limit, the EPA must account for the added costs and burdens sour ces will inevitably encount er trying to meet sitespecific 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 lim its in the proposed rule effectively lowers the numerical MACT floor. According to the commenter, it makes little sense to set a MACT floor then establish a mechanism to tight en the limit. Likewise, asserts the commenter, with a mandated monitor in place giving continuous, real-tim e readings in the units of the standard, the collection of control parameters for the purpose of compliance determinations is burdensome, but more importantly, completely unnecessary. The commenter states that in contrast, if the agency has confidence in the operating limits as a mechanism of compliance, then the mandated PM monitors are not necessary. According to the commenter, it should be noted that Hg and SO 2 CEMS data was deemed sufficient by the rule to assure compliance without the use of operating parameter limits.

Response to Comments 15 - 29: The EPA believes that continuous m onitoring in the form of CEMS, sorbent traps, or CPMS is needed or that fre quent emissions testing is needed to ensure ongoing compliance with this rule. In order to minimize co sts and reduce burden, the rule has removed most operating parameters except for: (1) the owner-defin ed 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 anHCl or HF CEMS, but instead rely on quarterly emissions testing. See the final preamble for further discussion. We have not re quired 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 ru les that apply to these units - including but not limited to the operating permits rule, the co mpliance assurance monitoring rule, and the new source performance standards – alrea dy require ongoing parameter monitoring. Those rules will remain in effect, so additional imposition of op erating limits on those units would be redundant. The limited operating limit requirements in the final rule ad dress options (such as th e PM CPMS in lieu of quarterly testing) or the potential gaps for liquid oil-fired units.

4. Requests to make parametric monitoring requirements more like Compliance Assurance Monitoring (CAM) Program.

Comment 30: Numerous commenters (17402, 17622, 17638, 17715, 17716, 17718, 17725, 17736, 17757, 17775, 17804, 17808, 17816, 17820, 17821, 17856, 18014, 18025, 18037, 18428, 18429, 18498, 18023) generally suggest that the final rule should in corporate more flexibilityin setting parametric monitoring ranges similar to th e existing CAM program. These commenters suggest the following specific revisions to proposed pa rametric monitoring provisions:

1. Several commenters (17716, 17725, 18498) state that so me of the proposed parameters are either unnecessary, inappropriate, or coul d otherwise be substituted withparameters that are already monitored; for instance, wet scr ubber parameters could be simplif ied based on scrubber pH and a calculated liquid-to-gas ratio, wher e gas flow is measured using an existing stack flow monitor and liquid injection rate is estimated based on the number of recycle pumps in service. According to the commenters, for ESP-equipped units, the use of total power may not be represen tative of PM emissions since removal efficiency is dependent on where th e power is applied in the control device. The commenters suggest that other alte rnatives might include the use of an ESP model for predicting performance or specifying a minimum power level within each gas path. The commenters state that these examples demonstrate other monitoring altern atives that provide a reasonable assurance of compliance while allowing operators to implement more cost effective monitoring programs.76 2. Multiple commenters (17402, 17715, 17689, 17808, 18037, 18539, 19114) believe that the EPA should revisit the way operating parameters are set dur ing performance tests that are typically completed during high-load, steady-state condi tions because the operating parameters captured during these tests may not represent the variability of day-to-day op erations across the full range of operating loads. Commenter 17808 recommends that units with appropriate CAM plans s hould not be required to have additional monitoring requirements. Commenters (17715, 17718, 17736, 17757, 17816, 17856, 18037, 18539, 19114) express concerns with operating limits ch anging every 2 months based on the most recent performance test and the challenges of continuously revising operating procedur es and alarm points. The commenters are concerned that sources will have no c onfidence 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 diffe rent sets of operating limits for each unit in their jurisdiction.

3. Multiple commenters (17402, 17718, 17627, 17736, 17757, 17816, 18037, 18539, 19114) believe that as currently proposed, units would be constrained by unachievable operational parameters because the set of operating limits that a unit measures during its first perform ance test would be its maximum operating limits. According to the commenters, subs equent performance test s would further ratchet down operating parameters until they are no longer achievable during a 30-day or annual averaging period. The commenters state that co ntrol equipment operating characte ristics 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 devi ce during performance tests will not ensure associated operating limits are necessary for compliance with the underlying emissions limit. Several commenters ( 17775, 17800, 17820, 17821, 17868, 18428) add that the EPA has previously recognized in the contex t 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 “possi ble or wise.” 62 FR 54,900, 54,907, 54,926-27.

Multiple commenters (17718, 17775, 17800, 17820, 17821, 17816, 17868, 18428) state that the proposed control device parameters do not necessarily ha ve a direct relationship to emissions but instead are interrelated with various parameters so that a si ngle parameter may vary widely with little effect on emissions. The commenters acknowledge that the proposed provision of a 10% difference from the average tested value recognizes so me of the normal operational vari ability of control devices, but believes the 10% margin will not be sufficient in so me cases. The commenters conclude that without a clear correlation between the pr oposed operating parameters and emission limits, imposition of those values as enforceable limits unreasonably restrict s operations and subjects operators to potential enforcement without any reliable ev idence 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 averag e 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 complia nce because this testing certifies that when those (least stringent) operating parameters are met, the facility s till meets the MACT limits. Moreover, the commenter believes, as long as the facili ty is in compliance via a certified CEMS or stack testing, there is no need to track the instan taneous values of operating parameters.

5. Commenter 17402 states that the normal variabilityof operating conditions further suggests that greater flexibility is needed for operators to subs titute the EPA’s proposed parameters, some of which77 are unnecessary or inappropriate, with parameters that are either already monito red by the facility or parameters that would allow the EGU to implemen t more efficient monitoring. The commenter suggests that the required parameters propos ed for wet scrubbers could be simp lified to simply scrubber pH and a calculated liquid-to-gas ratio, wher e gas flow is measured using an existing stack flow monitor and liquid injection rate is estimate d based on the number of recycle pumps in service. The commenter advises that FGD pressure drop vari es 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 parametr ic requirements for ESPs (to establish minimum hourly average secondary voltage and secondary ampera ge and calculate the tota l 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 commenters (17402, 17627, 17757, 17821, 18023, 18037, 18539, 19114) refer to existing requirements under 40 CFR part 64 comm only known as CAM plans in title V permits and state that the final rule should use the CAM program as the basi s for parametric monitoring plans. The commenters suggest that source operato rs should be able to rely on this existing framework, and to work with permitting authorities to develop a set of parameters that make sense for the facility and its control configuration. Commenters (17402, 17627, 17757, 18539, 19114) state that CAM plans were specifically developed to assure PM limit complian ce through the measuremen t of opacity even though opacity is not a direct measurement of PM, but pe rmitting authorities recognize opacity as an indicator of control device performance, and there are ap proved plans that have formally documented the appropriate use of this indicatorin an ongoing monitoring program.

7. Several commenters (17402, 17725, 18014, 18498) state that normal variability of operational parameters should be taken into consideration in the EPA’s proposed procedur es for establishing the compliance ranges. According to the commenters, the EPA proposes that EGUs would be required to set parameters based on 4-hour block averages during compliance tests and would demonstrate continuous compliance by monitoring 12-hour block average values below or above the lo west or highest 1-hour average measured during the most recent compliance test. The commenters do not believe that this approach adequately accounts for variability due to normal operation in some cases because (for example) the requirement to maintain a minimum pr essure drop and liquid injection rate on a wet PM scrubber will result in th e reporting of deviations during low generating loads. The commenters provide as another example the requirement to maintain sorbent injection rate at the ra te 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 commente rs suggest that an alternative approach for establishing a more representative se t of normal control device operating ranges might be a statistical analysis of historical operating data during which the control device was oper ating properly (no malfunctions). According to the commenters, the resulting operating limits could be discreet upper and lower bounds on certain operating parameters or a correlation between the control device operating parameter and one or more boiler operating paramete rs. If operating parameters are required, variability must be addressed. Therefore, one commenter reco mmends that the EPA should increase the averaging period from 12-hour block averages to 30-day rolling averages.

Similarly, other commenters ( 17808, 17870, 18025) state that setting anunreasonable 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 co llection field during each Hg, PM, and metals78 performance test, and the average of the three minimu m hourly values would then be used to establish a unit’s site-specific minimum voltage and current operating limits for the ESP. According to the commenters, maximizing power input and electric fiel d strength will generally maximize ESP collection efficiency and plant operators need a degree of flexib ility to balance the power input to the ESP in order to avoid serious damage to the system and downtim e. The commenters note that power input to an ESP is dynamically controlled by an au tomated 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 tr ansformer-rectifier in res ponse to signals received from sensors in the precipitator and the transforme r-rectifier itself. According to the commenters, power levels will vary depending on the amount of moistu re in the air, accumulated ash levels, and other factors, and as result, sustaining a minimum voltage and current level may not be possible or appropriate at all times, and could dama ge the control technology.

8. Several commenters (17775, 17800, 17821, 17868) state th at 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 suppl emental operational data will provide a higher level of compliance assurance than the level that ha ppens to be measured during a discrete performance test. The commenters assert that this is particular ly true for sources with a significant margin of compliance (see EPA-HQ-OAR-2002-0058-0413, Attach ment 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 estab lish “worst case” test cond itions 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 rese arch effort. The commenter s assert that allowing extrapolation of results avoids th e necessity of repeated testing. The commenters note the a similar approach has been used in CAM protocols for ESPs allowing extrapolation up to 1.25 times the recorded value for measurements at less than 80% of the applicable limit. Several commenters (17775, 17800, 17820, 17821, 17868, 18428) recommend a CAM-like approach where once established parameter would be monitored for deviations that would tri ggers 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 correct ive action (rather than simply record exceedances and report deviations ) achieves the intended result without subjecting sources to potential unre asonable enforcement.

Response to Comment 30: As noted above, the rule does not re quire monitoring operating limits where a CEMS is used for the applicable standard. With respect to the need for variability in establishing parameter limits because of load changes or changes in fuel, the rule provides for establishing different operating limits based on different loads. Note that th e ability to use paramete r monitoring is a choice made by the owner or operator. Where parameter m onitoring is chosen, we believe that continuous monitoring is needed to ensure ongoing compliance w ith this rule. As mentioned earlier, we require performance tests to demonstrate compliance with emission limits; we then use operating limits to ensure the source is operating similarly to how it was operating when it completed a successful performance test. Operating limits ar e 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. Yo u are also able to petition the Administrator for approval of an alternative monitoring plan under section 63.8(f) of subpart A of Part 63. This would include the possibility of adapting existing CAM plans that may rely on different parameters. Finally, we agree with commenters that collecting continuo us data, transforming it to 1-hour averages, and then calculating a 30-day rolling average based on those 1-hour averag es 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 quarterly testing to demonstrate compliance, you will propose a site-specific operating parameter mon itoring plan for your facility that should include the appropriate monitoring methods, QA/QC, and data reduction specifics for your unit. See the final preamble for further discussion.

5. ESP total secondary electric power (TSE P) requirements (sec tion 63.100010(h)(2)(iii)).

Comment 31: Several commenters (17402, 17715, 17775) express concern about proposed requirements under section 63.100010(h)(2)(iii) for EGUs th at have an operating limit requiring a total secondary electric power (TSEP) monitoring system on an ESP. Commenter 17402 requests that the EPA clarify how secondary power is calculated and if power is calculated on a field-by-field basis or across the whole ESP. Commenter 17715 states that th is parameter fails to take into account which fields are being powered and where in the precipit ator they are located. Commenter 17402 advises that under the EPA’s proposal, this monitoring will be pr oblematic because ESP power and PM collection efficiency vary by ESP configuration, fuel quality (coal sodium content), ash resistivity, number of electrical and mechanical fi elds, plate alignment, gas flow distribution, gas temperature, particle size and chemistry, rapper/vibrator setti ngs, and air in leakage. The co mmenter has observed ESP power fluctuations of 20 percent duri ng steady-state operation, and during startup and shutdowns, the ESP power shows even greater fluctuations–as high as 83 percent from high to low load. Commenter 17715 states that a TSEP minimum level set during a full load test is inadequate to assure compliance at all loads.

Comment 32: Several commenters (17775, 17800, 17868, 18428) re quest that the agency review the discussion on ESP performance in a report by McRani e Consulting entitled “C omments on the Proposed Utility MACT Rule - Operating Parameters” (July 2011) that was attached to their comments, because the report explains why proposed section 63.10011(b)(6 )(iii) is flawed. Accord ing to the commenters, Mr. McRanie explains that ESP power input simply is not directly related to PM removal performance (particularly for the modern multi-section ESPs that ar e likely to be installed to comply with a proposed MACT standard), and the total amount of power is not nearly as important as the location at which the power is being applied in the ESP. The commenters refer to an attached report indicating that ESP parameters are likely to have no relationship to PM emissions at units that also have a wet scrubber, because wet scrubbers are highly effective in controll ing 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 discover ed while seeking the high dust loads required under PS11 that even a fully disa bled ESP may have little effect on resulting PM concentrations when a wet scrubber is operating at expected efficienc y. 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 powe r input to the ESP collection plates. (Section 63.10011(b)(6)(iii)). According to the commenter, th e EPA’s proposal is flawed. ESP power input simply is not directly related to PM removal pe rformance, especially with a wet FGD following the ESP. According to the commenter, none of the ESP pa rameters are likely to have any relationship to PM at units that also have a wet scr ubber, since those systems also are highly effective in controlling high levels of PM coming out of an ESP that is no t 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 incr eases in emissions or damage to the control device. Commenter 17402 states that current, voltage, and to tal power are constantlyreacting to boiler ash conditions, flue gas temperature, fl ue 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 recogni ze the balancing act that plant operators perform daily to meet emission limits for not just HAP but all of the pollutants that are currently regulated.

Comment 36: Commenter 17808 agrees with the princi ple underlying the proposed parametric constraints on ESPs (i.e., that maximizing power input and electric field strength will generally maximize ESP collection efficiency), but the commenter states that plant opera tors need a degree of flexibility to balance the power i nput to the ESP in order to avoid serious damage to the system and downtime because the power input to an ESP is dynami cally controlled by an automated voltage control system to maximize power levels while avoiding sustained arcing between el ectrodes and collecting plates, which can damage the ESP; automatic controls adjust power in response to various sensors so that normal power levels will vary depending on the amount of moisture in the air, accumulated ash levels, and other factors. Commente r 17808 advises that this core func tionality of ESPs may make the proposed constraint for minimum vo ltage and current level inappropria te at certain times, and such a requirement could damage the control technology.

Comment 37 : Commenters 17808 and 17725 recommend that th e final rule requir e proper operation of the plant’s pollution control equipment and appropri ate parametric monitoring without establishing numeric operating limits.

Comment 38: Commenter 17772 notes that total secondary electric power is a poor measure of ESP performance. According to the commenter, this is es pecially true if it is tied to a minimum power concept. The commenter states that on some days pa rticulate loading to an ESP can be low, yielding a lower number of fly ash particles to be charged. Moreover, according to the commenter, during periods of low loading, total power can go dow n to levels lower than that wh ich may have been observed during the compliance test day if a larger number of fly ash particles were being se nt to the ESP during the compliance test; voltage may still be high, but because current is lower; total power is lower, and that does not mean that the ESP is operating poorly relative to the compliance test levels. In such instances, according to the commenter, it is either not possible to maintain a high level of current or, if possible, it may be a waste of energy. Commenter 17772 believes that the requirement to maintain “the 12-hour average secondary power input at or above the operating limits establ ished during the performance test” as required in section 63.10011 (c) is inappropriate and is not a true i ndicator of the operating condition of the ESP.

Comment 39: Commenter 17821 states that the secondary po wer approach for ESPs simply does not work and this fact is easily demonstrated by real world operating experi ence. 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 comm enter, this is a phenomenon that the commenter routinely sees in the operation of its own units. The commenter states that precipitator operation is complicated even further with the addition of sorbents into the flue gas for emissions control and that different fuels may require more or less dry sorbent injection, and those fuels will also cause changes in precipitator operation. According to th e commenter, these changes will likely result in a change in the total secondary power to the ESP but not necessarily a reducti on 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 E SP designs vary greatly, the parameters selected may include total percent of fields in service, or a limit on the number of fields in a give n train that may be out of service at one time.

Comment 40: Commenter 17881 states that under Table 4 – Op erating Limits for EGUs for ESPs, the requirement for ESPs conflicts with section 63.10011( b)(6)(iii), which does not impose a caveat on the ESP operating parameters such that it only applies to units with we t 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 to tal 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 stat es 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 no tion that total secondary power of an ESP could be the monitoring parameter for ESPs. According to the commenter, however, using secondary power of each ESP operating fi eld 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 successf ul 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 oper ating rate. To account for lower ESP power at lower operating fuel loads, the commenter suggests that the ratio of watts/1000 acfm should be monitored and targeted. According to the commenter, si nce 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 s econdary power when the fuel is, fo r 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 us ed in the past at combustion units to meet MACT requirements for ESP parameter monitoring and has b een found to be acceptable both on a technical and regulatory basis. The commenter asse rts that monitoring and setting th e operational target for an ESP using this parameter ratio is superior to monitori ng secondary power per field or even total secondary power to the entire ESP unit because it dampens th e impact on the signal of unit operating rate.

Comment 42: Commenter states that difficulties can be en countered when attempting to set operating parameters entirely based on stack testing. Accord ing 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, simp ly to provide set operating parameter ranges. The commenter also notes that while ESP power, a parame ter that must be monitored as described in the EGU MACT rule, at minimum power , provides good ESP performance info rmation, it is not necessarily a reliable indicator of poor performance. The comment er states that lower power generally means poorer performance, but ESPs are segmented into many elec trical 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, th is type of information would be difficult to verify through stack tes ting, considering other variables like fuel quality, varying loads, etc., but can be easily evaluated usi ng an ESP performance model. The commenter notes that where CEMS are available that information should be used to evaluate excess emissions.

Comment 43 : Commenters 17775 and 17790 recommend the use of boiler models or emissions models, in addition to manufacturer specif ications, to set up acceptable operating ranges. The commenter notes that, for example, in the CAM Program, the use of models and manufacturers in formation is allowed and that in the guidance document “Com pliance Assurance Monitoring (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 prope r operation of an ESP in between performance tests. According to the commenter, if the use of the model as required under su bpart Da is sufficient to assure compliance with the NSPS, it also should be sufficient under subpart UUUUU.

Response to Comments 31 - 43: Although the EPA notes some owners and operators have been successful in using parameters to model ESP performance, the comments are inapplicable, for the rule no longer requires parameter monitoring or operating limits for PM control devices.

6. Parametric limits for wet scrubbers (section 63.20011(b)(6)).

Comment 44 : Commenter 17775 expresses concer ns with the proposed parame tric operating limits for wet scrubbers at section 63.20011(b)(6)( i) and (ii); the commenter states that the proposed parametric ranges established during performa nce tests lack a sufficient relati onship 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, ca lcium 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 c oncludes that requiring op erators to artificially maintain pH to the level during a perform ance test is not a us eful requirement.

Comment 45: Commenter 17821 states that pH measurement is not suffici ently related to acid gas removal to apply enforceable limits. According to the commenter, the measurement of pH in an FGD system is only a small part of th e very complex chemistry in an SO 2 removal system; the pH is mainly used to prevent scaling of the modules. The commen ter 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 incr ease particulate emissions. The commenter notes acid gases such as HCl and HF are strong acids and very re adily dissolve in water, whereas SO 2 is a weak acid, which explains why its transp ort from the gas phase into the liquid phase in a scrubber occurs at a slower rate . According to the commenter, th e EPA acknowledges that acid gases are likely to be removed in typical FGD systems due to their solubil ity or their acidity (or both). The commenter states that the conclusion is that HCl and other acid gases are ve ry effectively removed by contact with water in a wet FGD system, so effectiv ely 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 ma intain a specified pH, the commenter suggests that the rule should require that sites develop site specific plans that incorporate parameters that more appropriately describe the operati on of an FGD system. For exampl e, the commenter suggests that stations may elect to use parameters such as num ber of absorber recircul ation 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 wants to restrict. There are two potential liquid flows in an FGD system; the firs t 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 dir ectly proportional to the mass of SO 2 that is removed in the scrubber per unit of time. According to the commenter, because th e chemical reagent must be added at the proper stoichiometric ratio, it is totally inappropriate to re quire a fixed feed ratio ba sed on full load, worst-case conditions; doing so will damage the FGD systemand will render it ineffective for removing SO 2 and other acid gases. As a result, the commenter concl udes, the EPA is not attemp ting to regulate lime or limestone reagent flow but instead seek s to regulate the total amount of liquid flow that is recirculated in the module and sprayed into the flue gas stream. Th e 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 pump s that run at a single speed. According to the commenter, mo st 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 util ize fiberglass reinforced piping (FRP) to transport recirculation flow through the FGD module. Accordi ng to the commenter, the FR P 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 accurat e readings. A ccording to the commenter, flow meters with the proposed accu racy of 2 percent are not practical for these FGD installations. The commenter states that internal fl ow meters may be able to provide more accurate readings immediately after insta llation, but the harsh conditions of the FGD will cause them to lose accuracy quickly. In any event, according to the comm enter, the length of FGD piping is short compared to its diameter, and has many elbows and fittings, so it typically does not have e nough straight lengths of pipe to allow for the installation of highly accurate flow monitors. A ccording to the commenter, even if the recirculation flow rate could be measured to th e desired accuracy, those measurements would not tell the whole story. The commenter states that in a properly operating FGD syst em, 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 opera tors do not have control over this recirculation flow because the piping systems do not have any sort of flow control valves. In short, the commenter states, a recirculation pump is eith er on or off, and . ther efore 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 achi eving the best removal efficiency.

The commenter states that the EPA should also realize that when anEGU reduces its load, the volume of flue gas passing through the FGD system decreas es, but the amount of r ecirculation flow stays relatively constant. According to the commenter, this results in an increase in the liquid to gas ratio, which in turn promotes even more efficient sc rubbing. Therefore, the commenter states, the more appropriate metric would be to requ ire that EGUs be required to maintain a minimum recirculation flow to gas ratio instead of a simple mi nimum liquid flow rate. According to the commenter, that would best be accomplished by requiring a minimum number of pu mps to be kept in service at all times as demonstrated during the performan ce test, and as a result, flow m onitors would not be needed or installed. In addition, the commenter states, it would be appropriate fo r the EPA to require sources to demonstrate that the flue gas is indeed going th rough the scrubber module and is not being bypassed. According to the commenter, these parameters w ill adequately ensure that the FGD operation will properly remove the acid gases that w ill be regulated in the final rule.

Comment 47: Commenter 17821 states that restricting FGD modules to minimum pressure drop requirements has no benefit. According to the comme nter, in the proposed rule, stations would be required to measure differential pr essure across the FGD module(s) dur ing the annual performance tests,84 and maintain a 12-hour pressure drop value above th e average measured in the performance test. The commenter asserts that like other limits the EPA ha s proposed, this limit fails to account for reduced load operation. According to the commenter, FGD pressure drop is a direct func tion of the amount of flue gas flow through the module, and thus is directlyrelated to boiler load. In a case where velocity doubles, the commenter stats, the pressure drop would quadruple. Th e commenter asserts that the reverse is also true, in that as the load drops, the scrubber pressure drop would also decrease. According to the commenter, there are different types of FGD systems such as open spray towers, and units with trays; however for all these designs, a reduced pressure drop at lower load does not by itself indicate a reduced level of HAP capture in a FGD system. In fact, according to the commenter, the scrubber performance is more likely to improve at reduced load because there is a higher ratio of liquid flow to flue gas flow; pressure drop is more a function of mi st eliminator cleanliness than acid gas removal. The commenter notes that there may be steady state syst ems, such as waste combustors, where measuring pressure drop could be useful. The commenter asserts that instead of using pressure drop to demonstrate compliance, the EPA should require sources to develop site-specific plans to ensure the effectiveness of the FGD for particulate removal and acid gas removal, which would then be s ubject to review by state and local agencies and contain mo re appropriate requirements such as maintaining a minimum number of recirculation pumps in service, eliminating any bypasses of the FGD system, and periodically inspecting internal components.

Comment 48: Commenter 18428 states the EPA’s proposal to use pH, pressure drop and liquid flowrate as operating parameters for wet scrubbers is subject to the same flaws as the EPA’s other proposed operating limits -- namely the lack of a sufficient re lationship between the para meters measured during performance testing and actual emi ssions. For example, the commenter states, because scrubber pressure drop, liquid flow rate, and sorbent in jection rate vary with boiler lo ad, establishment of a limit based on conditions during performance testing may tell the EP A little about actual em issions under other load conditions.

Comment 49: Several commenters (17775, 17868, 17800) state that because scrubber pressure drop, liquid flow rate, and sorbent injection rate vary with boiler load, establishment of a limit based on conditions during performance testing may tell little about actual emi ssions under other load conditions. Moreover, according to the commenters, when the EPA in 2008 considered the relationship between liquid flow rate and PM in the context of the NSPS for electric steam generating units at 40 CFR subpart Da, the EPA concluded that, at the level of the NSPS (i.e., 0.015 lb/MMBtu), PM emissions controlled by an ESP were not particularly sensitive to the actual liquid flow rate (U. S. The EPA “Response to Public Comments on Rule Amendments Propos ed June 12, 2008 (73 FR 33642)” (Nov. 2008), U.S. EPA-HQ-OAR-2005-0031-0284, at section 2.5.3).

Comment 50: Multiple commenters (17736, 17715, 17627, 17757, 18037, 18539, 19114) state that the proposed rule lays out a method to establish site specific operating lim its for various types of control equipment in Tables 7 and 8. According to the co mmenters, for example, a wet scrubber would be required to meet site-specific operating limits for pre ssure drop and liquid flow rate for compliance with the PM standard. The commenters note that pressure dr op and liquid flow rate may not be applicable to all types of wet scrubbers and that the parameters may not be directly related to emissions. According to the commenter, pressure drop is not a direct measurem ent of emissions and will naturally vary with load. The commenters also suggest that liqui d flow rate is also a function of load and the ability to measure it accurately may be a problem. Accord ing to the commenter, the same is sues are encountered when using these parameters as a metric for demonstrat ing continuous compliance with the HCl limits.85 Comment 51: Commenters 17775 and 17881 state operating lim its are not direct measurements of emissions or compliance. The commenters state that the proposed rule includes a requirement for wet scrubber controls to maintain a pressure drop across the scrubber and a minimum liquid flow rate. The commenters note that pressure drop is not used fo r control purposes, it is used to determine when cleaning is required and is not ne cessarily accurate for assessing scrubber performance. Commenter 17775 states that the EPA must also recognize that Chiyoda scrubbers operate on a completely different set of parameters than typical spray towers and that L/G is a more us eful indicator for some types of scrubbers. Commenter 17881 notes that under Table 4 – Operating Limits for EGUs for wet acid gas scrubbers the requirement states to maintain a mi nimum pH. Controlling pH is a maintenance incentive to prevent corrosion to major scrubber components. A ccording to the commenter, the pH of the scrubber vessel is an indication of the limest one slurry feed into the vessel, not the effectiveness of the slurry
spray.

Comment 52: Commenter 18023 states that pressure drop and li quid flow rate are not indicators of the level of PM control being achieved by a wet scrubber. According to the commenter, the establishment of operating limits for pressure drop and liquid flow ra te would unnecessarily lim it the range of key FGD operating parameters. According to the commenter, pre ssure drop is not a univers al indicator of the PM control achieved by wet scrubbers (Commenter refers to Figure 26 in its comme nt). According to the commenter, PM control by a modern je t-sparging type scrubber is not a function of pressure drop (three figures are provided in the document showing PM control vs. pressure drop, li quid flow rate and liquidto-gas ratio). The commenter further notes that liquid flow rate is no t a universal indicator of the PM control achieved by wet scrubbers. In the commenter ’s experience, PM removal by a modern spraytower-type scrubber varies widely for different li quid flow rates. According to the commenter, PM control is also not a function of liquid-to-gas flow rate.

With respect to HCl scrubbing, the commenter states that HCl is not easily m onitored on a continuous basis in flue gas. According to the commenter, pressure drop, liquid flow rate, a nd pH are not indicators of the level of HCl control being achieved by a we t scrubber, and the estab lishment of these operating limits would unnecessarily limit the range of key FGD operating parameters. The commenter states that HCl control by modern jet-sparging type scrubbers is not a functi on of liquid submergence (or its corollary pressure drop). Liquid submergence effectiv ely changes the liq uid-to-gas ratio of a scrubber. The lack of correlation between HCl emissions and liquid submergence suggests that there is also no correlation between HCl emissions and liquid flow rate.

Response to Comments 44 - 52: The comments are moot, as the rule no longer includes specific requirements for parametric monitoring or operational limits for acid gas control devices.

7. Operating limits for low-emitting EGUs (LEEs).

Comment 53 : Commenter 17402 states that operating limits are particularly inappropriate for low emitting units because the commenter believes the ope rating limit procedures in the proposed rule are repetitive, are counter to the purpose of the rule, and can result in f acilities being deemed non-compliant when controls are operating properly. The commenter states that these concerns are even more applicable to LEEs, as the emissions associated with LEEs are dramatically lower than those of the rest of the fleet. The commenter is concerned that slight variations in operating limits thatdeviate from the operating conditions of the most recent performance te st (that indicated the unit operates normally at a fraction of the standard) may be deemed non-compliantand cause the unit to lose LEE status when in reality the emissions never approached the MACT emissions limit. According to the commenter, this result is not consistent with th e 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 especi ally inappropriate.

Comment 54 : Commenter 18426 states that the proposed ru le includes a LEE definition for compliance monitoring purposes. According to the commenter, fo r Hg, emissions less than 10 percent of the Hg emissions limitation or less than 22.0 pounds per year on an existing unit may qualify for LEE status for Hg. The commenter notes that for Michigan’s Hg ru les, 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 th e unit utilization.

Comment 55 : Commenter 17752 requests clarification on the criteria for qualifying for LEE with regard to references to operating parameter limits in proposed section 63.10005(k)(3 ) and section 63.10006(c). The commenter requests that the EP A clarify whether the use of ACI is permissible to qualify for LEE and how operating limits would apply in that circumstance. The commen ter also requests clarification on fuel sampling as an operating li mit and as a demonstration of comp liance; 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 complian ce provisions in section 63.10011(c).

Comment 56: Commenters 17775 and 17868 support the LEE option but find that the proposed LEE requirements for “operating parameter limits” ar e not clear. Commenter 17775 finds the following inconsistencies with respect to Hg testing periods that need to be addressed in the final rule:

1. Commenters 17775 and 17868 state that the EPA s hould remove or appropr iately clarify the references to operating limits for LEEs. Accord ing to the commenter, proposed section 63.10005(k)(3) and section 63.10006(c) refer to establishment and main tenance of “operating limits,” but the provision cited in section 63.10005(k)(3) for establishing such limits – section 63.10010(k)(3 ) - does not exist and no other provisions address operating limits for LEEs . According to the commenter, proposed section 63.10021(a)(17) states that, for LEEs, results of emissi ons tests and fuel analysis - presumably the monthly fuel analysis required under section 63.10006(c) - demonstrat e continuous compliance, and the provision does not mention operating limits.

2. According to the commenters, the EPA’s descripti ons of the requirements for LEEs suggest they are not required to establish or comp ly with operating limits. Specifically, the commenters say that the EPA states: For existing units that qualify as low emitting EGUs (LEEs), conduct subsequent performance tests for the LEE qualified pollutant s every 5 years and perform fuel analysis monthly. Commenter 17775 states that if the EPA intende d to require that LEEs perform m onthly fuel analysis under section 63.10006(c), the EPA needs to make clear that complian ce with the maximum fuel input levels is not required and explain why it chose monthly testing. Th e commenter believes that analyzing fuel monthly when the fuel supply or mixture has not changed seems unnecessary.

3. Commenter 17775 states that if the EPA intended to require that LEEs establish and comply with maximum fuel input levels as an “operating li mit” under section 63.10011(b), rather than perform monthly fuel analysis, the EPA needs to explain that the fuel analysis is anoperating limit and not a demonstration of compliance usi ng fuel analysis under section 63.10011.

4. Commenter 17775 also states that the EPA needs to remove the monthly fuel sampling and analysis requirement in section 63.10006(c). According to the commenter, if the EPA intended to require that87 LEEs establish and comply with operating limits othe r than maximum fuel input levels, the EPA needs to issue a proposal that expl ains the purpose of those limits and how they apply.

Comment 57: Several commenters (19536, 19537, 19538) states that the EPA should discard its “Low Emitting Units” monitoring protocols. According to the commenter, monthly fuel testing does not assure continuous compliance, and the EPA’s variability analysis indicates HAP emissions are variable. Monthly testing does not reveal any information about emissions between the monthly tests. According to the commenters, the LEE monitoring should be e xpanded to require operational parameter monitoring as required for all other compliance testing, and m onthly fuel sampling further excludes emissions during startup and shutdown. The co mmenters state that the LEE exempti on should be eliminated, or the threshold redefined to capture only those plants whose future emissions are assured to remain below the prescribed limits. According to the commenters, if the EPA were to provid e reduced monitoring for certain low-emitting units, it should use a UPL for its thresholds, and if data from a unit indicates that the 99% UPL of that unit’s emissions are below 10% of the MACT limit, the EPA can be reasonably assured that unit’s future emissions will be below that threshold.

Response to Comments 53 - 57: The comments are inapplicable because the rule no longer requires operating limits for LEEs.

8. Oil-fired operating parameter comments.

Comment 58: Commenter 18025 states that for oil-fi red 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 reco mmends that the EPA re quire proper operation of the plant’s pollution control equipment and appropri ate parametric monitoring without establishing numeric operating limits.

Comment 59: Commenter 18428 states that it is not clear whether operati ng parameters and fuel input limits in proposed section 63.10011(b) to apply to oil-fired units. Accordi ng to the commenter, the preamble statement suggests that operating paramete rs do not apply (“Except for liquid oil-fired units,...we are proposing that you monitor during init ial performance testing specified operating parameters”). The commenter states that similar to LEEs, however, the EPA also suggests that liquid oilfired units must meet maximum fuel input limits as an operating limit. The commenter recommends that the EPA should make clear in section 63.10011(b) what operating limits apply as well as explain why.

Response to Comments 58 - 59: The final rule clarifies that operat ing limits do not ap ply 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 liqui d oil-fired EGUs); or, (2) a liquid oil-fired unit uses quarterly testing to demonstrate compliance with aci d gas emission limits (in wh ich case the source must develop a site-specific monitoring plan). See the fi nal preamble for further di scussion. Note that liquid oil-fired sources may also use fuel moisture cont ent analysis or supplier certification to show compliance with the acid gas standards.

9. Minimum sorbent injection rates.

Comment 60: Commenter 17821 states that there are multiple problems with the sorbent injection rate requirements. DSI and ACI feed rates are normally co rrelated with othe r plant conditions, such as unit load or flue gas flow, making a singl e fixed feed rate inappropriate. As an example, sorbent rates are88 normally set as a mass flow per volume of flue ga s, such as a pound of sorbent per hundred thousand cubic feet of flue gas. As a result, half the amount of sorbent would be injected when the flue gas flow is reduced to half the flow rate. In terestingly enough, the same mass feed rate of sorbent may actually be more effective at low flue gas flow rates, because it has more time to react due to the lower velocity. However it will also increase the amount of byproduct material generated. Commenter states that the problem of using one minimum flow rate for all conditions is the measurement of a sorbent has problems. The material handling equipment for a dry solid such as Trona, ACI or other materials whether milled or not, is not capable of precise weight measurements. Load cells are typically used to gather injection rates, but because the material can clump or surge, short term measurements such as a 15-minute interval are too small to absorb all these fl uctuations. Finally, DSI is also closely linked with ESP performance. Injecting a “minimum” amount of sorbent over the entire operating range of a unit could change the ash resistivity and thus impactprecipitator performan ce, 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 demonstrat e compliance with HCl or Hg standards, limits on sorbent inject rates should not be required since the CEMS woul d be used to demonstrate compliance.

Comment 61: Several commenters (17622, 18037 and 18023) refer to the proposed compliance approach for DSI systems (i.e., setting operational lim its of reagent injection rate based on performance testing at 76 FR 25031 and 25129). Commenter 17622 stat es that if operationa l limits consisting of injection rates for DSI technology are going to be utilized to demonstrat e 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. Comm enter 17622 also advises that for sodium reagents, the physical properties of either Trona or sodium bicarbonate can impact the effectiveness of a specific reagent for an acid gas control application; as an example, the particle size to which Trona is milled prior to use is an important considera tion. Commenters 18023 and 18037 state that the minimum sorbent injection rate may be an appropriate ope rating limit for DSI and/or carbon injection; however, the operating limit should be established in a way th at accommodates operating over a wide load range because it would not be prudent (i.e., it would pass unnecessary costs on to elec tricity customers) to operate a sorbent injection system at the maximu m injection rate when running at reduced load. Commenter 18023 concludes that the operating limit s hould allow normalizing for gas flow such as lb/MMacf or a calculated ratio. Th e 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 duri ng the most recent performance test because this is more consistent with how dry scrubbers ar e operated in the industry. Commenter 18023 concludes that any minimum sorbent injection requirement fo r DSI, carbon injection and dry scrubbers should be set in a manner that allo ws 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 wh at is necessary (simply to meet an arbitrary limit set by an emission test at one pointin time) creates an additional pot ential waste stream that must be managed. Commenter 18037 states that setting a minimu m injection rate will pot entially hurt units as they attempt to balance their PM limit with the minimum injection of sorbent necessary to control Hg or HCI. According to the commenter, sources should be able to maintain the flex ibility necessary to meet all of their emissions obligations.

Comment 62 : Commenters 17775 and 17800 state that the EP A should consider and review data to evaluate use of a load factor adjustment for thos e operating parameters that are load dependent. The89 commenters state that the EPA finalized a load fact or adjustment in the Industrial Boiler MACT for sorbent and carbon injecti on; specifically, the EPA revised the definitions of “Minimum sorbent injection rate” and “Minimum activat ed carbon injection rate” to take load into account by multiplying the “lowest hourly average” by a new term calle d the “load fraction” (see section 63.7575).

Comment 63: Several commenters (17627, 17715, 18539, 19114) take exception to the use of the minimum sorbent injection rate parameter for dry scr ubbers or DSI in Table 4 because they assert that such a restriction removes all of th e flexibility that a unit has to meet all of its obligations, and sorbent quality may vary between suppliers requiring differe nt injection rates per product. Additionally, they assert, sorbent may be injected for reasons other th an for HAP control; for ex ample, during the periodic MACT performance test an injection 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 64 : Commenter 17805 states that according to th e proposed rule requirements, ACI amounts, or other control media, would be set at the highest operating load and a unit woul d not be able to reduce the amount of product injected when running at lowe r loads and corresponding lower flue gas flows. According to the commenter, this does not make econom ic sense and is wasteful to add more material than necessary to control emissions.

Comment 65: Commenter 17881 states that Table 4 – Operati ng Limits for EGUs, the DSI sorbents are likely targeting HCl/HF, not just Hg as suggested in this requirement. According to the commenter, this paragraph should recognize that there may be multiple pollutant specific sorbents.

Response to Comments 60 - 65: These comments are inapplicable be cause the rule no longer requires operating limits for sorbent injection.

10. PM CEMS operating limits (section 63.10011(d) and table 4, parameter 8).

Comment 66: Several commenters (17705, 17754, 17775) requestthat the EPA clarify how the PM operating limits must be established because th e provisions of proposed section 63.10011(d) are inconsistent with the provisions for PM CEMS in proposed Table 4. Commenter 17775 adds that the EPA has provided no data or discussion to explain how the average of three Method 5 runs would be sufficient to capture variability under a various normal operating conditio ns. Commenter 17775 takes exception to the use of the term “highest hour” in propos ed Table 4 item 8 because it is not clear to the commenter whether this term applie s 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 m easured in hours but in sample volume (and runs will be more than one hour). The commente r also believes that item 8 makes no sense relative to hourly PM CEMS data because at the time the ope rating limit is established because the values would simply be output from the uncorrelated CEMS.

Response to Comment 66: In consideration of the PM emissi ons limit and the potential burdens associated with certifying a PM CEMS via PS 11, th e agency decided to focus on the use of a PM instrument not as a CEMS but as a CPMS. The PM operating limit for use in conjunction with a PM CPMS functions in the same manner as parameter monitoring from other rules. The highest hourly average of the PM CPMS signal produced over three te st runs is used as the operating limit, and that value becomes averaged over a rollin g 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 revise d to be consistent with this90 approach. The final rule does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

11. CPMS averaging times.

Comment 67: Commenter 17775 states that the EPA should cl arify the averaging tim e 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 th e “test average” during the most recent performance test, and to require complian ce on a 12-hour average basis under Table 8, other provisions and statements contradictthat definition. For example, stat es the commenter, proposed Table 4 instructs sources to maintain parameters “at orabove 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 paramete r values” for various control devices at or below the operating limits established during the most recent performance test; and in the preamble, the EPA describes operating limits as “[t]he average of th e three minimum (or maximum) values from the three runs for each applicable parameter . . . .” 75 FR 25,029/3. The commenter assumes that the proposed definitions and the 12-hour average in Table 8 reflect the EPA’s intent. The commenter asserts that the EPA also must provide data to support achievability and enforceability of operating parameters under its proposed definitions. The commenter states that although the EPA does not explain the “90 percent” criterion in this rule, when the EPA previously promulgated a similar definition in the 2004 IB MACT, the EPA explained that 90 percen t value was intended to provide a range around the test average to account for normal variations in th e operation of the source and the control device (EPA Response to Public Comments on Proposed Industrial, Commercial , and Institutional Boile rs and Process Heaters NESHAP (Feb. 25, 2004), EPA-HQ- OAR-2002-0058-0611 at 54). According to the commenter, the EPA must provide data to confirm that the 10 percent allowed variance is sufficient. The commenter states that before finalizing a rule that imposes parameters as enforceable limits, the EPA must analyze data to determine what definition provides adequate flexibility.

Response to Comment 67: The rule retains two operating limits in the final rule: for a PM CPMS and for site-specific parameters from liquid-oil fired E GUs that choose to comply with quarterly emissions testing for acid gases. See the final preamble for further discussion. The rule plainly states the PM CPMS operating limit averaging period as each rolli ng 30-day operating period. The limit is set based on the highest 1-hour average monitor output signal during a successful performance test. That average serves as a measure of ongoing control of the unit in accordance with the operati ons that exist during the performance test, and is similar to how the Agen cy has established operating limits under a number of NESHAP standards. The appropriate parameter, monitoring approac h, and data reduction requirements (including averaging periods as appropriate) for the liqui d oil-fired units will be set forth in the source’s monitoring plan. See the final preamble for further discussion.

12. Optional moisture measurement technique.

Comment 68: Commenter 17715 proposes an additional option be available for meas uring moisture: if the stack is saturated, a source should be able to use temperature, abso lute pressure, and a psychrometric chart to determine moisture; temper ature and pressure transmitters can be calibrated with NIST traceable equipment; during periods when the st ack is not saturated, default fact ors listed in the rule could be used.91 Response to Comment 68: While the rule does not contain th e additional options mentioned by the commenter, the commenter remains able to reques t use of such instrume ntation via the general provisions at section 63.8(f) of subpart A of part 63.

13. Frequency of QA/QC requirements fo r parametric monitoring devices.

Comment 69 : Several commenters (17716, 17725, 18014, 18498) state that sources that are required to conduct control device parameter monitoring must follow prescriptive QA/QC requirements and performance evaluation schedules as outlined in section 63.1 0010. According to the commenters, some of these requirements are unnecessarily frequent, such as the need to check pressure taps at least once each boiler operating day, and the requirement to c onduct annual evaluations of ESP power monitoring systems is excessive particularly for large ESPs w ith numerous electrical bus sections. The commenters suggest that the EPA specify all operating paramete r QA/QC activities and perf ormance evaluations in accordance with manufacturer’s recommended procedures.

Response to Comment 69: In the final rule, the s ource owner or operator must prepare a site-specific monitoring plan for its PM CPMS , and, for those liquid oil-fired sources that choose to conduct quarterly acid gas emissions testing, for appropriate parameters to demonstrate that operations at the unit remain consistent with operations during the perf ormance test. See the final preamble for further discussion. This plan identifies th e QA/QC procedures the source will follow and calls generally for a daily performance evaluation of some form for mo st 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 fulf ill this QC check in conjunction with developing the site’s monitoring plan.

14. Consistency of rule with data gathered during the 2010 ICR.

Comment 70 : Commenter 17775 believes thatthe EPA cannot require stack testing under conditions it did not consider in the standard setting process. Neither does commenter 17775 believe that the EPA can require EGUs to operate at a fixed load for 30 operating days. According to the commenter, the EPA proposes to require that all “performance testing” be conducted at “maximum normal operating load while burning the type of fuel or mixture of fuels th at has the highest content of chlorine, fluorine, nonHg HAP metals, and Hg” (Proposed section 63.10007. The commenter stat es that the EPA also proposes that it be able to request that performance tests be conducted under other representative conditions, and that EGUs be required to provide records to dete rmine those conditions upon request (proposed section 63.10007(f)). The commenter states that for EGUs us ing CEMS, the “performance test” runs for 30 operating days (proposed section 63.10005(a)). The co mmenter 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, instea d, the EPA should simply require representative operation. The commenter states that because such sources are monitoring compliance continuously after that point, there is no reason to require worst case testing conditions.

Response to Comment 70: The agency maintains that it has adequate ly incorporated variability into the final standards in response to other comments on this issue.

15. Frequency of stack tests.

Comment 71 : Commenter 17736 states that bi-monthly stack testing imposes an unnecessary drain of resources and will, inevitably, force units into non-compliance. The commenter states that an EGU92 electing to comply with the tota l or individual non-mer cury 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 resour ces. 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 pros cribed parameter limits should be eliminated and replaced with provisions allowing facilities to work with states to develop site-specific compliance plans, if deemed necessary, bi-monthly stack testing is especially excessive if/w hen the unit is subject to any additional monitoring requirements.

Comment 72: Commenter 17775 states that proposed fuel input limits and freque nt periodic stack testing requirements are duplicative because under the proposed rule, the maximum time between stack testing for non-Hg metals and HCl (for units us ing stack testing to demonstrate compliance) is approximately 60 days (i.e., every other month for EGUs with PM controls). The commenter states that if an EGU plans to combust a new fuel type or mixt ure and that fuel exceeds the maximum metals input level during the prior performance te st, a new performance test is requi red 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, gi ven the notice and planning requirements for stack tests, it also is not reasonable to require stack testing sooner. A ccording to the commenter, current operating parameters provide a reasonable assuran ce of compliance prior to the any new performance test and requiring testing of new fuels, and stack testing in res ponse 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 th e EPA has not provided ad equate justification for such frequent stack testing, and therefore the final ru le should require stack tes ting no more frequently than annually unless such a test is triggered by a ch ange in the maximum fuel input as a result of a change in fuel type.

Comment 73: Commenter 17798 recommends, for PM, stack te sting every 2 years or at a maximum on an annual basis in conjunction wi th monitoring operating parameters . According to the commenter, for units without pollution c ontrol equipment the source should perf orm continuous monitoring or stack testing every 6 months. The commenter further reco mmends that the stack testing regime address determining minimum and maximum operating para meters of control equipment under different conditions to address variability. Ac cording to the commenter, for po llutants 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 thatalso for these pollutants, testing and setting of pollution control operating parameters should be applied only in conjuncti on with the stack test compliance demonstration option. According to th e commenter, these changes will streamline the process, reduce cost, and achieve the same environmental result.

Comment 74: Commenter 17902 states that testing should be allowed on a less frequent 3-year or 5- year basis when HAP emissions are significantly be low the MACT emissions limits (as the EPA has proposed in section 63.1 0006). The comm enter states that additionally, EGUs that participate in an emissions averaging plan should not be restricted fr om reduced performance tes ting if the relevant HAP emissions from the units in combination are in fact below the percent thresholds of the relevant MACT limits.

Comment 75: Commenter 18426 states that emissions testin g required monthly or every other month depending on the unit and pollutant specified in th e proposed rule is excessive and inconsistent. According to the commenter, if anacceptable parametric monitoring system is developed, emissions93 testing once a year or every other ye ar should be sufficient, and even if no emission control system is in place, unless a significant change in the fuel char acteristics occurs, emissions testing once a year or every other year should also be sufficient. The commenter recommends that at a minimum, the EPA should make the testing and monitoring requireme nts consistent for the units and pollutants.

Response to Comments 71 - 75: The agency agrees that fuel input and frequent periodic stack testing requirements could be duplicative; therefore, the rule no longer requires fuel an alysis for pollutants. The rule requires quarterly emissions testing for units that choose to use emissi ons testing. In addition, sources remain subject to underlyi ng parameter monitoring that appl ies to many of these units, through Compliance Assurance Monitoring ( 40 CFR Part 64) or other existi ng regulatory programs. For liquid oil-fired units that choose to use emissions testin g, there is an additional requirement for continuous parameter monitoring of the method of control fo r acid gases. See the final preamble for further discussion. The quarterly stack tes ting period, coupled with underlying m onitoring 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 a nd 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 th e fuel, then a retest is required to reconfirm that the source remains in compliance under the new operating circumstances.

16. Operating parameters during SSM.

Comment 76: Commenter 17886 states that during startup, shutdowns, and malfunction periods use of established parameters set during performance tests w ould not be proper. The co mmenter notes that the EPA has not addressed this concern in the proposal but should consider some be st management practice option during those periods.

Comment 77: Several commenters (17775, 18428, 17800) state that they are very concerned about the potential for enforcement of opera ting parameter and opacity limits during periods of startup, shutdown, and in the event of equipment ma lfunction. According to the comment ers, 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 duri ng startup. According to the commen ters, these assertions regarding startup and shutdown are inapplicable to control device operating parameter limits, which are based on 12-hour averages established during performance testing. In short, assert the commenters, the EPA has made no allowance in its operating limits for periods of startup and shutdown but to the contrary, the EPA has proposed to require sources to establish control device operating parameter levels that are dependent upon load during periods of “maximum normal operating load,” or other frequently used loads, and then maintain those levels during other periods, including st artup and shutdown. The commenters urge the EPA to address these period s in another manner, for example by establishing simple work practice standards inlieu of operating parameters.

Response to Comments 76 and 77: As mentioned elsewhere, th e final rule no longer requires continuous measurement of operating parameters, ex cept when PM CPMS are used and when a liquid oil-fired EGU without an FGD uses a combination of emissions testing a nd continuous operating parameter monitoring to demonstrate compliance. B ecause work practice standards apply 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. Instea d, for coal and other solid fuels, the work practice standards for such periods will apply, together with the mon itoring and recordkeeping required to document94 compliance with those work practices. The final rule also provides for sources to apply affirmative defense of excess emissions includin g deviations from PM CPMS meas ured operating limits relative to process malfunctions.

17. Operating limits based on total PM.

Comment 78: Commenter 17402 states that they support ope rating 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 variabil ity with PM CEMS technology for the operating limit to be set, given the high level of uncertainty involved in the test. Recognizing that continuous condensable PM monitoring technology does not exist, the commente r’s preference is to preserve the flexibility allowed in choosing to re duce condensable PM or filterable PM by setting the operational filterable PM limit based on the differe nce 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 a pproach will provide flexibility and would address both variability concerns with tes ting, fuel supply and operations.

Response to Comment 78: Given our decision to use a filterable PM standard as the PM emission limit under this rule, this sugg ested approach would not be appropri ate. Moreover, the operating limit established for the PM CPMS is just that – an operat ing limit, and not a PM limit (filterable or total), and does not require the source to present the monitor output in terms of PM.

18. Request for clarification on multiple load testing (section 63.10007).

Comment 79 : Commenter 17316 requests clarification on proposed provisions for multiple load performance tests at section 63.10007 to establish load -specific operating limits. The commenter states that it is not clear which operati ng limits are re-set following a perf ormance test or whether a new performance test program erases a ll previous operating limits, or onl y those operating limits for loads at which testing was repeated. For example, the comment er asks if a unit initia lly conducted performance testing at 3 loads: 100 percent, 75 percent and 50 pe rcent, but for the next annual test cycle, only conducted testing at 100 per cent load to demonstrate compliance, wh ether 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 appropr iate 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 oper ating 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. Accord ing to the commenter, absent a means to account for an acceptable tolerance in these parameters, the rule allows for mu lti-load testing but fails to outline what load ranges would be required, how to address op eration between those loads and th e costs of the testing regiment, which would be high. The commenter recommends addi ng operating range tolerances as an appropriate solution.

Comment 81: Commenter 17805 states that the section 63.10 007 (Tables 5 and 7) contains compliance demonstration requirements, and specifically, demonstration “through performance testing”. According to the commenter, these provisions e ssentially require utility units to develop parametric limits at different operating levels and coal qualities. The commenter asserts thataccording to this section, stack testing is to be performed while units burn coal with the maximum c oncentration of HAP constituents,95 but units would still have to run at normal operati ng load. The commenter does not believe this would be possible since the commenter has observed that coal with the maximum HAP concentration characteristics generally contains lower heat content. Therefore, the commenter asserts, running a performance test solely with coal having the higher HAP concentratio ns, and lower heat content, would not allow a unit to attain normal ope rating 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 pe riods 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 show ing HAP concentration variability by coal-type and within coal-type before finalizi ng these monitoring requirements.

Comment 82: Commenter 17800 states that many units in the U. S. utility system are load following or cycling units that change load on a daily basis and that many of the control device operating parameters the EPA is requiring to be maintained will vary with load. The commenter states that to account for this, the EPA suggests that EGUs obtain differing operating limits at loads other th an the “maximum normal load” required for stack testing by testing at thos e other lower loads (secti on 63.10007(c)). According to the commenter, requiring EGUs to conduct performa nce tests at multiple loads is not practical or reasonable, and the EPA has not considered the time or cost of that kind of extensive testing.

Response to Comments 79 - 82: The EPA finds these comments moot , for the rule no longer requires operational limits except for those EGU owners or operators who choose to rely on PM CPMS to demonstrate compliance. To the extent that those owne rs or operators choose to operate their units at load levels other than normal operating conditions, thos e owners or operators w ill need to ensure that their units remain in compliance with the emission s 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 orig inal correlat ion testing occurred, the commenter would be ab le to use the previous correlati ons for its operating parameters when the unit’s load changed.

19. Miscellaneous.

Comment 83: Several commenters (19536, 19537, 19538) states that the monitoring of operating parameters as proposed under some scenarios does not assure continuous co mpliance with emissions limits that are only measured annua lly or every 5 years. According to the commenter, the amount of each HAP that is emitted ultimately depends on the amount in the coal, which is not tested more frequently than monthly (or upon a change of fu el type) under any of the compliance scenarios. Moreover, the commenter notes that the HAP content of fuel is highly variable ev en 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 th at variability into account to a large degree with the extensive database of emissions valu es and the statistical procedures used in establishing the floor and the final emissions limitations. We believe that so urces who demonstrate compliance with these limits must apply the control measures including use of fuel s that are consistent with the control measures applied by the sources used in developing the li mits. The commenter provided no information on how the variability of fuel HAP metals content can vary significantly beyond that found in the database used in setting the floor or to the ex tent that a source demonstrating co mpliance under the various compliance monitoring measures allowed in the final rule will have undetected excess emissions.96 Comment 84: Commenter 17795 states that the EPA did not provide an expl anation for selection of a 12-hour block average for operational monitorin g. According to the commenter, the EPA should maintain consistency among averaging periods for de monstrating compliance with emission standards or operating limits; averaging operating parameter data over the same time period when employing direct or surrogate continuous monitori ng provides adequate a ssurance that equipm ent is operated and maintained in compliance with standards or limits. According to the commenter, this also reduces the data management and the quality assurance burden currently proposed with 12-hour block averaging periods.

Response to Comment 84: This comment is moot given the changes in the final rule. The PM CPMS will use a rolling 30-day average. Site-specific mon itoring for liquid oil-fired units, if required, will establish the appropriate av eraging period based on the parameters being monitored.

Comment 85: Commenter 17740 states that it has significant concerns with the EPA’s proposed testing requirements for solid oil-derived fuel and coal-fired EGUs using total PM emissions as a surrogate for non-Hg metals ( see 40 CFR section 63.10006). The commenter unde rstands 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 surroga te limit. The commenter asserts that the EPA does not have the authority to “adjust” surrogate em issions 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 ar e 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 th e 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 nonHg HAP metals emissions were based on the top 12 percent of the total number of EGUs...”). According to the commenter, nothing in the CAA author izes the EPA to subsequently review and revise these standards on a unit-by-unit basis.

Comment 86 : Commenter 17740 states that Congress specifi cally limited the EPA’s authority to review and revise emissions standards promulgated under section 112. Section 1 12(d)(6) instructs the Administrator to “review, and re vise as necessary (taking into account developments in practices, processes, and control technologies ), emission standards promulgated under this section...” According to the commenter, the CAA manifestly does not perm it the agency to circumvent the requirements of Section 112(d)(3) and set standa rds 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 di rectly 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 expre ssed intent of Congress”). Accord ing to the commenter, if, after issuing a final rule, the EPA determines that a surr ogate emission standard is no longer appropriate, the agency must review and revise the standard inaccordance with the expr ess 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 comme nter states that a so urce has no way of knowing whether its emission control measures are sufficien t to comply with the EGU MACT if the EPA can review and revise a MACT standa rd based on performance test resu lts. According to the commenter, even if a source makes substantia l capital investments and achieves a proposed surrogate emission limit, it may be forced to make additiona l investments in a short timeframe to achieve a new, individual limit based on its performance test results . The commenter asserts that this circumstance creat es substantial regulatory uncertainty for affected sources.97 Response to Comments 85 and 86: The final rule no longer includes th e use of PM as a site specific emissions surrogate for HAP metals. Instead, the final rule allows the source to choose and comply 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 87: Commenters 17718 and 17881 note that sect ion 63.10005(d)(7) states that initial compliance through the use of CPMS can be determined using the average hourly PM, non-Hg HAP metals, HCl, HF, or Hg concentrations obtained during the first 30-day operating period. In turn, commenters note that continuous parameter monitoring systems, or CPMS, are defined at section 63.2 as “Continuous parameter monitoring syst em means the total equi pment that may be required to meet the data acquisition and availability requirements of this part, used to sample, condition (if applicable), analyze, and provide a record of process or control system parameters.” According to the commenters, they have been unable to identify any other place in the proposed rule where it is stated that CPMS can be used for initial compliance, nor does the comme nter understand how such monitoring systems could be used for purposes of a direct compliance assessment with the emission limits inTables 1 and 2 of the proposed rule.

Response to Comment 87: The final rule in this section refers to “CMS”, and is re ferring to continuous emission monitoring systems that are used for dire ct compliance. Section 63.10005(c) discusses that you may be required to establish an operating lim it using a PM CPMS during an initial compliance performance test period.

Comment 88: Commenter 17881 states that under section 63. 10011 the concept of selecting the highest minimum/maximum values across a series of performance tests is not congruent with multiple operating limits for different scenarios.

Response to Comment 88: Given the simplification of the oper ating limit and parameter monitoring provisions in the final rule, the EPA does not believe this comment remains applicable.

Comment 89: Commenter 17881 states that insection 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 lim its without having to report a de viation (as long as the compliance test results show compliance with the emission limit).

Response to Comment 89: The EPA disagrees. Given the 30-day averaging period, there is adequate flexibility for a short term increase in PM CPMS out put during a short term test without this type of special allowance.

Comment 90: Commenter 17881 states under Table 4 – Oper ating Limits for EGUs, for IGCCs the combustor temperature would likely be a better measure, as compared to electrical load (as a percent of maximum output) which will float with ambient conditions.

Response to Comment 90: This comment is moot given the ch anges to the operating limits required under the final rule.

Comment 91: Commenter 17881 states under Table 4 – Operati ng Limits for EGUs, with respect to PM CEMS, that for concentration based emission or operating limits, it is norm ally appropriate to correct the98 concentration back to a reference O 2 /CO 2 level for purposes of consistenc y (i.e., the diluent gas levels will affect the concentration).

Response to Comment 91: There is no need to report the data from a PM CPMS in PM concentration values.

Comment 92: Commenters 18014 and 17716 state that in Table 8, CPMS data is required to be reduced to 12-hour block averages. However, the commenters a ssert that this requirem ent is not specified in section 63.10010(h).

Response to Comment 92: The final rule has eliminated the parameters measured on a 12-hour block average, and now requires only a 30-day ro lling average for an operating parameter.

Comment 93: Commenters 18014 and 17716 state the limits fo r 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 perfor mance 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 repres entative operating parameters.

Response to Comment 93: These comments are moot given the changes in the final rule, as discussed above.

Comment 94: Commenter 18015 states that facil ities should have the flexibil ity 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 importa nce of various operating parameters ca n 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 thatthe alternatives should be established through submittal of monitoring pl ans before testing and certifying CEMS.

Response to Comment 94: These comments are moot given the changes in the final rule, as discussed above. The one circumstance in which the rule relies on flexible parameter sel ection is for liquid oilfired units that demonstrate compliance with em ission limits for acid gase s by conducting quarterly performance tests. In that situa tion, the source must also develop a site-specific monitoring plan to ensure that operating conditions remain consistent with conditions during the performance test. See the final preamble for further discussion.

Comment 95: Commenter 17925 states that parametric moni toring should be applied as an action indicator and not applied as a compliance monitor because they do not give a true indication of compliance especially for multi-pollutant control configurations. According to the commenter, for example, for PM emissions, the EPA has determin ed that ESP secondary current and baghouse leak detection will be indicative parametrically of PM filterable emissions. However, the commenter states, other equipment on units such as FGD systems (wet sc rubbers) or DSI for ESP ash resistivity adjustment also can serve to reduce filterable and condensable PM emissions. According to the commenter, in such cases, a wide range of ESP secondary power rates and baghouse leak rates coul d be experienced while PM emission limits are still achieved due to the im pact of the other equipment. The commenter does note that if parametric monitoring remains a co mpliance monitoring method, they agree with the99 approach of providing a variable ra nge 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 95: These comments are moot given the changes in the final rule, as discussed above. See also response to Comment 30 in this section.

Comment 96: Commenter 17923 recommends that the oper ational limitations of the air pollution control systems reference the manufacture reco mmendations. According to the commenter, the methodology required by the proposed rule would significantly limit operational flexibility and significantly increase the emissions tes ting required at affected facilities.

Response to Comment 96: These comments are moot given the changes in the final rule, as discussed above.

Comment 97: Commenter 17718 states that the proposed re gulatory 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 “dur ing the same compliance te st period and under the same process (e.g., fuel) and control device operating conditions.” According to the commenter, process improvements discovered after initial compliance tes ting could potentially allow for the same or better control of emissions yet move the control device ope rating conditions outside of what was established as the “operating limits” established pe r 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 th e commenter, this would be simila r to language proposed in 40 CFR 63.10006 (e), (f), (g), (j), (k), (l), and (m) where testing under those “same conditions” is not required.

Response to Comment 97: These comments are moot given the changes in the final rule, as discussed above.

Comment 98: Commenter 19033 states that section 63.10010 (h )(2)(i) is overly prescriptive with respect to the minimum acceptable criteria for liqui d flow monitoring. The commenter asserts that the +/- 2 percent accuracy (section 63.10 010 (h)(2)(i)(B)), is excessive, gi ven the purpose for which liquid flow monitoring is intended (verific ation that the scr ubber is operating in a manne r 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 assert s that the proposed regulation also does not take into account that there could be issues with spray pa tterns as nozzles wear over time. According to the commenter, liquid flow measurements would not take th at effect into account and would thus not be an accurate indicator of pollutant removal. The commenter estimates th at $250,000 would be needed to add the liquid flow measurement and associated data acquisition syst ems needed to meet se ction 63.10010 (h)(2)(i)(B) and that such an expenditure is not ju stified. The commenter agrees with the concept outline d in the July 29, 2011, comments letter provided withrespect this proposed regulat ory action by Thomas Easterly, Commissioner of the Indiana Department of Environmental Management, i.e.

“Indiana asks that States be allowed maximu m flexibility to develop alternate compliance plans that afford the regulated community opportunity to assure timely compliance, while also assuring that consumers are not adversely affected.”100 In concert with the sentiment expressed by Comm issioner Easterly, 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 pl an 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) thr ough (D) of this section.

Response to Comment 98: As discussed elsewhere, the use of operating parameters is no longer required in the rule except for those associated with use of PM CPMS or thos e associated with use of liquid oil-fired units whose owners or operators choose acid gas emissions te sting and must provide continuous parameter monitoring of their flue gas de sulfurization systems. Where operating parameters are used, the rule does not prescribe minimum qualit y assurance or control sp ecifications; in concert with the commenter’s suggestion, thes e specifications are left to th e EGU owner or operator to choose and follow.

Comment 99: Commenter 19033 states that 63.1 0010 (h)(2)(ii)(D) is overly pr escriptive. According to the commenter, EGU operators may have experience that pressure drop sensors may provide reliable output at a less frequent cl eaning frequency than daily and alternat ively, systems equipped with an auto purge system would not require the daily operato r interaction of manuallycleaning the sensors. According to the commenter, this parameter is another candidate for negotiation between the state regulatory agency and EGU owner. The commenter recommends that section 63.10010 (h)(2)(ii) be amended as follows:

(ii) If you have an operating limit that requires the use of a pressure monitoring system, you must develop a pressure monitoring plan in consultation with your state regulatory agency. The plan must be approved by the agency in advance of the initial compliance demonstration requirements in (A) through (F) of this section. The plan must include the recommended accuracy, and include a recommended maintenance interval for adequate sens or cleaning if an auto purge system has not been installed.

Response to Comment 99: These comments are moot given the changes in the final rule, as discussed above.

Comment 100: Commenter 17821 disagrees with the EPA’s unwillingness to delegate some key responsibilities to state and local agencies. The commenter states that in section 63.10041, the EPA defines who is responsible for implementation and enforcement of this subpart: “In delegating implementation and enforcement authority of this subpart to a state, local, or tribal agency under 40CFR part 63, subpart E, the authorities li sted in paragraphs (b)(1) through (4 ) of this section are retained by the EPA Administrator and are not tr ansferred to the state, local, or tribal agency; however, the U.S. EPA retains oversight of this subpart and can take enforcement act ions, as appropriate.

1. Approval of alternatives to the non-opacity emission limits and work practice standards in §63.9991(a) and (b) under § 63.6(g). 2. Approval of major change to monitoring under § 63.8(f) and as defined in § 63.90, and approval of alternative operating parameters under §§ 63.9991(a)(2) and 63.10009(g)(2).

The commenter strongly recommends that approval of alternatives to work practice standards and alternative operating parameters be delegated to the state or local agencies for multiple reasons.101 According to the commenter, first, the state and local agencies are in a much be tter position to review and access the merit of changes requested by individua l operators; while it can articulate direction for how to approve these requests, the EPA does not ha ve the unit specific k nowledge 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 oper ating parameter limits for the wide diversity of EGUs. According to the commenter , because of the wide variety in EGU construction, control equipment, and operation, it is unlikely that the EPA can develop a one-size-fits all approach that will properly apply to the entire industry, and as a result, st ate and local agencies thatare more familiar with each source should be allowed to make those decisi ons. Finally, the commenter anticipates that there will be a large number of these requests and that restricting approval to the EPA will create a terrible delay in their approval that will put sources at a compliance risk.

Response to Comment 100: The EPA disagrees. Under implementation of the NESHAP program, the EPA routinely retains the approval au thority over these issues. There is nothing so unique within the EGU sector as compared to all other industries to take a different approach under this rule.

Comment 101: Commenter 17752 requests that the EPA pr ovide guidance on how to operate a baghouse to obtain the three di fferent PM concentrations.

Response to Comment 101: The comment is moot, as the rule no longer requires control device operational parameters to be monitored.102 5A05a - Testing/Monitoring: Operating paramet er monitoring (bag leak detection systems)

Commenters : 17704, 17716, 17725, 17737, 17775, 17868, 17871, 18014, 18498

Comment 1 : Several commenters (17716, 17725, 17775, 17868, 18014, 18498) recommend that the EPA remove the requirement to comply with th e procedures in EPA-454/ R-98-015. According to the commenters, the referenced document is based on ope rating and maintenance proc edures for a specific type and model of bag leak detector (BLD) and is inadequate for many BLD systems (BLDS). The commenters state that the definition of BLDS clearly allows use of a variety of technologies, including electrodynamic, light scattering, and light transmittance. According to the commenters, the required guidance document excludes all other technologies (e.g., light scattering, light transmission, optical scintillation, and el ectro-dynamic devices).

Comment 2 : Commenters 17775 and 17868 request clarifica tion regarding the a pplicability of the requirements for fabric filters. The commenters state that although several provisions suggests that BLDS are only required if an EGU “chooses” to dem onstrate compliance using a BLDS and cite, as an example, proposed section 63.10011(b), other provisions ap pear to require any EGU with a fabric filter to employ a BLDS along with any other applicab le 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 recordi ng alarm time in 1-hour increments is unreasonable. In the case of a br oken bag, the most common baghouse failure, alarms can usually be cleared in only a few minutes by removi ng a single compartment from service.

Comment 5 : Commenter 17737 strongly objects to any re quirement to use BLDS to demonstrate compliance. The commenter has been operating these devices on two of its units , and they have proven to be extremely susceptible to false alarms. A ccording to the commenters, on numerous occasions (sometimes multiple occurrences in one day) the BL DS have indicated an alarm, following which an investigation reveals no problems rela ting to particulate emissions or control equipment, and often, the condition is rectified simply by cl eaning the probes. According to the commenters, these false alarms add to operational costs and keep plant personnel from their regular duties. The commenter suggests the use of opacity measurement in pl ace of PM CEMS or BLDS as compliance assurance monitors. The commenter notes this would be similar to the re quirements of 40 CFR 60.48 Da. According to the commenters, opacity monitors have proven to be reli able in detecting changes in PM emission levels which could trigger an operator i nvestigation of potential malfunctions and take appropriate corrective action. According to the commenter, because there is no reliable num erical correlation between PM emissions and opacity, the opacity monitoring (and the same holds for BLDS, should an operator elect to use them) should be used solely as an indicator and not for comp liance. 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 suitab le for continuous compliance with the MACT standard for non-Hg metals especially wh en a control device with efficiencies above 99.5 percent is used for PM contro l, such as a fabric filter.

Comment 6: Commenter 17871 states that nearly all units are required to insta ll a continuous opacity monitoring system (COMS), either as a result of the NSPS or thr ough the NSR program. According to103 the commenter, in other rulemakings, the EPA has a sserted that while COMS “cannot directly measure PM emissions,” a “properly calibrated and maintained COMS is sufficient to demonstrate long-term PM control device performance, since the purpose of the monitoring is to demonstrate with reasonable certainty that the PM control device is operating as well as it did during the PM emissions test used to demonstrate compliance” (In re Newmont NevadaEnergy Investment, LLC, PSD Appeal No. 05-04 (EAB 2005) (citing 70 FR 7905, 7908 (Feb. 16, 2005))). According to the commenter, where each unit would be subject to comprehensive and duplicative monitoring schemes, the EPA should refrain from requiring installation of an expensive CEMS that does not provide additional compliance certainty.

Response to Comments 1 - 6 : The final rule does not require use of a BLDS for EGUs that employ a fabric filter control device. We be lieve 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 th e proposal were duplicative and unnecessary. In order to simplify and streamline the final rule, we have removed most operating parameter monitoring from the final rule. We have retained the owne r-defined operating limit monitoring using a PM CPMS as an option to periodic emission testing.

The rule establishes the PM CPMS as an operating lim it monitor and not a direct filterable PM emission monitoring requirement that meets PS11 requirements. While we recognize the importance of continued control device performance to ensure emissions mini mization, we also are aware that other rules that apply to these units - including butnot limited to the operating permits rule, the CAM rule, and the NSPS – already require continuous m onitoring in most cases. Those rule s 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 include s no requirements applicable 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, 17808, 17843, 17868, 17877, 17881, 17930, 18014, 18025, 18039, 18421, 18428, 18449, 18498, 18023

1. Requested clarifications and corrections.

Comment 1: Commenter 18014 advises that proposed s ections 63.10010(f) and 63.10021(h)(ii) have contradicting requirements for quarterly accuracy de terminations and daily ca libration drift tests.

Comment 2: Several commenters (17728, 17758, 17775, 17868) state th at all references in the proposal to 40 CFR Part 60, Procedure 5 (e.g., section 63.1 0021(a)(14)(ii)) should be deleted because the quarterly and daily requirements in Procedure 5 ar e duplicative of and conf lict with some of the proposed requirements in proposed Appendix A, and use of Procedure 5 is incons istent 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 pr eamble to the proposed rule.

Comment 3: Commenter 17775 states that proposed Appendi x A contains a number of provisions that conflict with and/or duplicat e requirements of part 63, subpart A, or with other proposed requirements in subpart UUUUU:

1. For example, according to the commenter, propose d section 7.2.2 requires 21 days notice of RATAs, whereas 40 CFR section 63.9 requires 60 days notice of performance evaluations (a term that is defined in section 63.2 to include RATAs). 2. According to the commenter, proposed section 7.2.3.1 requires submission of a monitoring plan 21 days prior to initial certification testing or recertification testing, whereas proposed section 63.10000(d) requires submission of the monitoring pl an 60 days before the initial “performance evaluation.” 3. According to the commenter, proposed section 7.2.5.5 requires the owner or operator to submit a compliance certification in support of each report based on reasonable i nquiry, 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 si gnature, 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 secti on 63.10000(d)(6) and Table 9. Specifically, the commenter asserts that Appendix A establishes data validation criter ia for Hg CEMS in Table A-3, which sets the acceptance criteria at ≤ 5.0 percent of span value or ≤ 1.0 μ g/scm, proposed section 63.10000(d)(6) requires development and implementati on of a site-specific monitoring plan that “defines a continuous monitoring system that is out -of-control consistent w ith 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 insection 63.8(c)(7). ” The commenter states that the term “out-ofcontrol” also is used to determine what data may be used to report emissions and what constitutes a deviation of monitoring requirements under propo sed 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 appli cable performance specifica tion of in the relevant105 standard.” According to the commenter, this de finition is inconsistentwith 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 inc onsistencies, and where a requirement in Appendix A is more detailed or restrictive thana similar requirement in the part 63 general provisions or subpart UUUUU, or vice versa , the EPA must explain the n eed for the more restrictive requirement.

Response to Comment 3 : The EPA indicated in the preamble to the pr oposed rule that its intent was to adopt the CAMR-based requirements for Hg monito ring because many sources had already installed monitors to meet those requirements. Thus, the intent of our proposal wa s to use these specific requirements in place of the gene ral part 63 Hg monitoring requireme nts. These requirements for Hg CEMS went through notice and comment rulemaking fo r the same set of sources. Although CAMR was set aside on other grounds, these te chnical specifications and QA require ments reflect significant input from stakeholders and analysis by the EPA to establish an appropriate founda tion for Hg monitoring at electric utilities under the CAA. For the final rule, we have made conforming changes to ensure that this intent is carried out effectively throughout the rule text and Appendix A, as well as including certain additional clarifications base d on the input received in response to this proposed rule.

Comment 4: Commenters 17620 and 17691 state that it is unclea r, from the form of the Hg emissions limit and the compliance methodology, whether the EPA in tends that the Hg limita tions include total Hg or only vapor-phase Hg. The comment ers state that according to the proposal, continuous compliance can be demonstrated by the use of Hg CEMS, whic h measure only vapor-phase Hg and that the EPA also mentions of the use of Method 29 or Method30B for demonstrating compliance. The commenters state that Method 29 measures total Hg whereas Method 30B measures only vapor-phase Hg. Additionally, the commenters state that in its discussion of allowa ble certification methods for Hg CEMS, the EPA references the use of the Ontario Hydro Method or EPA Method 29, each of which measures total Hg.

Comment 5: Several commenters (17804, 17843, 18039) state th at it is not appropriate to allow compliance demonstrations without accounting for particulate bound Hg which can be a substantial fraction of total Hg emissions. The commenters have determined that the filterable portion of total particulate emissions for coal-fired EGUs without wet scrubber controls can produce an average of 30 percent- 40 percent filterable PM. The commenters recommend that the EPA require total Hg emissions to be the basis of compliance demonstrations by ta king into account the aver age particulate bound Hg measured during the most recent st ack test on that unit in combinati on with the total vapor-phase Hg measured by the CEMS until such time as Hg CEMS to measure particulate-bound Hg are installed at a unit. Commenter 17853 provides as an example the Massachusetts Department of Environmental Protection’s final Hg emissions re gulation at 310 CMR 7.29(5)(a)3.g.ii.

Response to Comments 4 - 5: The Hg emissions limits were estab lished based principally on the results from Method 30B emissions tests (vapor phase Hg) coupled with data from some Method 29 test programs. Though the Method 29 results would incl ude the particulate fraction, this generally constitutes less than 5 percent of the total Hg. The final rule then requires continuous monitoring for units firing fuels other than liquid oil using either a Hg CEMS or a sorbent trap monitoring system both of which measure vapor phase Hg concentration. The final rule allo ws for the use of Method 29, the Ontario Hydro Method, or Method 30B if the source el ects to use such methods when emissions testing a liquid oil-fired unit. Method 29, Method 30B, or Ontario Hydro Method testing for Hg is not applicable for other types of affected units.106 Comment 6: Commenters 17718 and 17781 request clarifica tion 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 “af ter the monitoring system is certified, ” though this language does appear in similar monitoring system sec tions (i.e., 40 CFR 63.10005(d)(4)-(6)). The commenters note that there are sorbent trap monitoring system certification requirements (e.g., RATA) mentioned in the proposed “Appendix A to subpart UUUUU – Hg M onitoring 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 sorb ent 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 belie ves that any 30-day period within the first 180 days following the applicable compliance date should be allowed for the initial compliance demonstration.

Response to Comment 6: This concern has been addressed by cl arifying the language in the final rule.

2. Technical review of appendix A and incorporation of part 75 provisions.

Comment 7: Several commenters (17752, 17775, 18014) find similarities between Hg CEMS requirements in Appendix A and the now-vacated CA MR provisions of Part 75. The commenters generally support attempts to provide consistenc y between the proposal and Part 75, but Commenter 17775 does not believe all of the Part 75 requirements are necessary in a MACT standard or that the proposal established that all requirements can be consistently met. Comm enter 17775 incorporates a memorandum by McRanie Consulting with the fo llowing technical recomme ndations for proposed Appendix A:

1. The consultant recommends adding language that specifically allo ws for use of backup monitors. Commenters 17752 and 18014 also support such a cl arification and commen ter 17775 states that such language should apply to both Hg CEMS a nd sorbent trap systems. Several commenters (17752, 17775, 18014) also recommend incorporation of pr ovisions 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 th e 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; comm enter 17752 believes that a 720-day grace period for like-kind replacements should be sufficient for require d factory repairs and that a grace period of at least 24 hours is needed for w eekly system integrity checks. Commenter 17775 believes that the system integrity test is likely to be one of the most challenging test s 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 proce ss and identify problems during th e test. According to commenter 17775, these issues led Northeast States for C oordinated Air Use Management, (NESCAUM) to conclude:

At this point, it appears that the equipment associated with the system inte grity 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 integritytest cannot be automated, EGUs will need to monitor operating hours to determine wh en a test will be due, and ensure that a qualified technician is available because most EGUs do not have technician s available to perform r outine tests on nights and weekends. According to the commenter, even if the te st is scheduled to be performed on time, issues with monitoring system breakdowns and the time necessa ry to complete maintenance could also result in late tests. Commenter 17775 states th at the proposal provides no basis for specifically excluding the test from grace period provisions, and the commenter request s at a minimum that the final rule include an operating hour grace period of at least 72 unit operat ing hours before data are invalidated because that would provide an EGU time to schedule and perform a test if one were triggered unexpectedly by a unit startup or shutdown, and such a grace period would be consistent with provisions for linearity checks, 3- level system integrity checks, and RATAs. Comm enter 17775 suggests that a nother possible approach would be a calendar day interval fo r testing combined with an opera ting hour grace period to provide relief if the unit is not operating or the monitori ng system is out of service when the test is due. According to the commenter, if the EPA does not provide some sort of flexibility, the availability of valid Hg CEMS data for compliance calculations may be needlessly limited simply due to late tests that do not indicate any actual problem with the monitoring system or data quality.

1. The consultant recommends removing the seco nd sentence of section 3.1.7 because the recommended nominal span ratio yields a span that, according to the consultant, “makes it impossible to comply with many of the other QA/ QC requirements of this appendix because the available NIST traceable Hg calibration gas concentra tions are not compatible.” The consultant also points out that the second sentence of secti on 3.1.7 is inconsistent with section 3.2.1.4.2, and commenter 17775 emphasizes how important these s ections are for specifyi ng appropriate rounding procedures for establishment of span because of the current unavailability of NIST traceable Hg calibration gases at lower spans. Commenter 17775 reque sts that the final rule include such rounding provisions 2. The consultant recommends removal of the “lev el detectable” and “det ectable 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 re ferences 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 consultant s review states that si nce these provisions are incomplete and potentially inconsistent with Part 75 provisions, operators that already are complying with Part 75 should have the opti on of simply meeting the Part 75 re quirements. The consultant also states that references to MPC should be remove d from Appendix A because “MPC has no meaning for O 2 , CO 2 , or stack flow rate in this proposed ru le 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-12Aand 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 testi ng companies to the misc onception that all of108 PS-2 applies to Appendix A procedures. The consu ltant further recommends that the final rule include the relative accuracycalculations in Appendix A. 8. The consultant believes there are problems units of measure and dry and we t bases within section 12 of PS-2 with respect to proposed Appendix A that are likely to create confusion and recommends adding the following sentence to section 4.1.1.5.2, “For purposes of cal culating the relative accuracy, ensure that the reference method and monito r 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 ex changes between the ag ency’s testing personnel and source testers conducting Method 30B and PS-12B at units with ve ry low Hg concentrations. According to the consultant, the “breakthrough” specification is not achievable as Hg concentrations approach zero. Commenter 17775 states that for concentrations < 0.5 μ g/m 3 but > 0.1 μ g/m 3 , the alternative breakthrough criteria could be < 50 percent of the section 1 Hg mass. For concentrations < 0.1 μ g/m 3

, there would be no breakthrough crit eria and the validity of the sa mples would rest on all other performance specifications being met. A consistent achievable alternative sp ecification also should be provided in Method 30B. Comme nter 17775 requests promulgation of revisions concurrent with finalization of subpart UUUUU, or complete a ru lemaking to revise PS-12B and Method 30B well in advance of the subpart UUUUU compliance deadline. 10. The consultant encourages the agency to expedite publication of the “codes” referenced in proposed Appendix A for various parameters to facilitate development of reporting software by venders. 11. The consultant believes that references to “...tests descri bed in paragraphs 7.1.10.3 through 7.1.10.6 ...” should be corrected to “...tests descri bed in paragraphs 7.1.10.1 through 7.1.10.6 ...” but generally finds section 7.1.10 to be confusing. 12. The consultant states that se ction 7.2.5.3.3 requires elect ronic reporting of “The information in paragraphs 7.1.2 through 7.1.19 ....” but advises that there are no sections 7.1.11 through 7.1.19.

Several commenters (17752, 17775, 18014) state that the EPA should cons ider adding provisions for conditional data validation in the final rule si milar to section 75.20(b)(3)(ii)-(vi); Commenters 17752 and 17775 also state that setting dataas conditionally valid following th e calibration error test (or other maintenance activities that requ ire further QA procedures) is a good provision for improving data availability.

Response to Comment 7: The EPA acknowledges commenters’ ge neral support for finding consistency with Part 75. For the items concerning backup m onitoring and conditional data validation, the EPA agrees and has made changes to the final rule and Appendix A to provide for backup monitoring and conditional data validation similar to part 75 approaches. For the c oncerns raised with the system integrity check requirement, the final rule retain s the weekly system integrity check requirement, without a grace period. However, to add flexibility, th e required frequency of th e test has been changed from once every 168 operating hours to once every 7 ope rating days. Operating days are much easier to track than operating hours. The test can be done at any time during the 7 thoperating day, rather than requiring it to be done at a certain hour. We believe that this added flexibilitywill 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 secti on 3.2.1.4.2 with respect to rounding in order to provide for consistent implemen tation. For item 2, the EPA notes that the use of zero gases for calibration is a well -understood concept within the indus try. The rule language has been revised slightly to provide for a workable standard that can adjust over time as industry-standard detection limits may change. For Item 3, the EPA agr ees, and has made a number of changes to provide direct references to Part 75 in A ppendix A in lieu of specifying compar able provisions in this rule. For the specific recommendations in items 4 throug h 12 above, the EPA has made conforming revisions109 generally consistent with these clar ifying suggestions. In particular, th e 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 Me thod 30B. Section 4.1.1.5.2 has b een revised to ensure that RATA data are compared on a consistent mois ture basis. Regarding the recommendation for an alternative “breakthrough” specification for Meth od 30B and PS-12B, the EPA plans to propose, in revisions to Method 30B, the altern ative breakthrough specifications s uggested by the commenter to be applicable to relative accuracy te sting. The EPA does not plan to m odify 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 secti on 4.1.2.2 of Appendix A to include the alternative breakthrough specifica tions suggested by the commenter fo r relative accuracy testing of sorbent trap monitoring systems; th e agency will consider revising PS- 12 B at a later time as part of ongoing evaluation of that performance specific ation. The EPA will be proceeding with ECMPS modifications with appropriate reporting codes as the commenter notes is needed.

Comment 8: Commenter 18449 states that many of the assumptions and regulations regarding “Span” date back a generation or more when chart recorders and 4-20 mA links were commonly used. According to the commenter, in those days, readings exceeding the “Span” value resulted in invalid data, and the chart recorder or the 20 mA loop pegged, clamping the data at the maximum span value. The commenter notes that much has changed with both instrumentation and data acquisition systems. According to the commenter:

1. All of the commercially successful Hg CEMS are atomic fluorescence (AF) based and are linear over a very wide range. (e.g., Tekran: 0.01 – 300 μ g/m3) 2. The systems operate linearly over this range as on e span range. (i.e., There are no range knobs, or other adjustments required to obtain this range.) 3. They report digitally, such that th e actual concentration value is re ported. There is thus no loss of accuracy in transmitting this wide range of values. 4. The systems report with an “overload” flag wh en they finally reach their limits, positively identifying periods of invalid data. 5. Provided that a CEMS can demonstrate good (i.e., low) zero readings, usin g a higher concentration gas to calibrate a Hg CEMS does not affect its lo w concentration accuracy. For example, states the commenter, calibrating an AF based CEMS using a 9 μ g/m3 calibration gas will not cause it to read a subsequent stack concentration value of, say 1 μ g/m3 any less accurately than having calibrated it with a 4.5 μ g/m3 calibration gas; in fact, the 9 μ g calibration gas would probably yield a more accurate number since the uncerta inty of the actual cal gas con centration is smaller at higher concentrations. (According to the commenter, this is largely a function of the uncertainty that NIST can provide.)

Commenter 18449 states that, despite the past practic e, any requirement to r un dual spans is totally unnecessary for Hg CEMS. The commenter notes:

1. Each span range requires independent QA/QC. This requires three separate concentrations of elemental and ionic calibration gases for each sp an. 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 ge nerators 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 oc casional high peak.110 3. Many systems have separate ionic calibrators. If two ionic calibrators are required, the total could become four separate calibrators per system, which is impractical.

The commenter believes the EPA should take this opportunity to finally address this issu e in a rational manner. According to the commenter, calibration of Hg CEMS should be atthe normal (low level) span range to maximize accuracy. Manufacturers should be allowed to demonstrate the dynamic range of their instrumentation. The commenter states that if an instrument calibrated at a normal span range was shown to be capable of measuring a much higher c oncentration accurately, (with in x percent) the data would be deemed valid no matter how much it exceeded the span value. According to the commenter, this might take specialized generators capable of producing high output concentrations, and a factory “type approval” or one time on-site demonstration would be sufficient.

Response to Comment 8: The EPA agrees that dual range Hg CEMS are not a requirement of this rule. Appendix A of this rule provides guidance and requi rements for establishing the span value and fullscale range for monitoring with a Hg CEMS. Th e span value is established based on the Hg concentration corresponding to the applicable emission limit. Establishing the range will require identifying the Maximum Potential Concentration (MPC ) which defines the full-scale range that the Hg CEMS being used must be capable of monitoring.

Comment 9: Commenter 17800 states that it is unrealistic to require submittal of hourly Hg data in a format that this similar to part 75 (see Appendix A section 7.2). The commenter notes that in the Cement MACT the EPA has not required the submittal of hour ly data for any of the CAA section 112 listed pollutants. According to the commenter, the reporting requirements in these rules rely solely on the recordkeeping and reporting requirements contained in 40 CFR part 63, subpart A and 40 CFR part 60, subpart A. The commenter states that in the propo sed Utility MACT rule, co mpliance with the Hg limit is determined on a 30-day rolling average and thus th e need for hourly measured Hg concentrations is superfluous and the EPA has provided no reason for this treatment. The commenter recommends the EPA revise Appendix A to subpart UUUUU and require only semi-annual reporting of what is required in 40 CFR part 63, Subpart A.

Response to Comment 9: The EPA has retained the hourly reporting of CEMS data, using the ECMPS approach as outlined in the proposed rule. This approach was supported by a number of commenters. See further discussion of this decision under re sponses to comments in 5B03 of this document.

Comment 10: Commenter 17800 states that the EPA’s assumpti on 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 part 75 monitors do not have moisture monitors and adding them will be an added expense.

Response to Comment 10: Moisture monitoring is not required but is an option for use in calculating emissions in units of the emission limit. The EPA expects that units that currently have moisture monitors installed under part 75 may use those under this rule, but that other sources will use one of the other options available, such as a moisture default value.

Comment 11: Commenter 17877 states that weekly system in tegrity checks should be eliminated and are unnecessary to demonstrate compliance with a not-t o-exceed limit. According to the commenter, the existing CAMR performance criteria were created unde r the auspices of a cap and trade program. The commenter states that performing the standard ongoi ng QA tests that are deemed sufficient for the Acid Rain Program (daily calibrations, quarterly linearity checks, and a nnual 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 le vel of the monitoring technology. The commenter states that at a minimum, a qualified technician would have to be devoted to a full day each week in order to try and complete a successful integrity check and that many more man-hours are already going to have to be devoted to maintain CEMS for utilities th at will also be operating PM and HCL monitors. The commenter suggests that as an altern ative to a weekly inte grity check, a quarterly sorbent trap test (in non-RATA quarters) along with the quarterly linearity check.

Response to Comment 11: The EPA disagrees and has retained the proposed requirement for weekly system integrity tests if the CEMS uses a converter and if daily calibrations ar e not done with a NISTtraceable source of oxidized Hg. The system integrity test assesses the efficiency with which the converter reduces oxidized Hg to elemental Hg; c onversion efficiency must be confirmed as poor efficiency would result in a low bias in the Hg m easurements. 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 additi on, to add flexibility, the required frequency of the test has been changed from once every 168 operating hours to once ev ery 7 operating days. Oper ating days are much easier to track than operati ng hours. The test can be done at any time during the 7 thoperating day, rather than requiring it to be done at a certain hour. We beli eve that this added flexibil ity will allow utilities to schedule the test in accordance with the technician’s work schedule.

3. Achievability of Hg p erformance specifications.

Comment 12: Commenter 18023 states that Hg CEMS are not capable of achieving the data availability of CEMS for other pollutants because Hg presents unique problems. According to the commenter, first, Hg levels are being measured equivalently in parts per trillion (ppt) whereas other pollutants are measured on a parts per million (ppm) basis, Hg has a tendency to adsorb and desorb from the sampling system, and the measurement technology requires consid erable time to stabili ze 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 currently, Appendix A of the proposed rule contains only the requirement that entities report when data is unavailable And Appropriately, the ru le 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. Comm enter 18023 suggests that therefore th e EPA should allow utilities to gain several years of experience with these system s 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 ch allenges 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 Meas urement of Mercury Emissions from Coal-Fired Power Plants in the Un ited States: A 2010 Status Report, Northeast States for Coordinated Air Use Management, July 2010.” A ccording to the commenter, this report notes the existence of reasonable concerns about the reliability of Hg CEMS and that, in general, availability is a concern for new technology. The commenters state that the proposal did not provi de data to establish consistent achievability of all pr oposed 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 ti mes that the affected unit is in operation (except for CEMS malfunctions and QA checks). The agency believes that the record indicates adequate availabil ity of Hg CEMS necessary to comply w ith the final standards. To the extent that a facility does not believe the CEMS can func tion to provide adequate data availability at a particular source, the facility may elect to use a sorbent trap monitoring system and/or a backup monitoring system.

Comment 14: Commenters 17677 and 17681 relay experience measuring Hg emissions since 2008 using a dilution-extractive CEMS and state that th e proposed Hg limit is below accurately measureable concentrations. Through RATA one commenter asserts significantly increased er ror 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 lim it well below the accuracy capabilities of Hg CEMS. The commenter contends that the proposed limit is f undamentally immeasurable and states that the EPA should set a Hg emission level that is measurable and supported by sound scientific data pertaining to CEMS technology.

Comment 15: Several commenters (17638, 17681, 17930) state that Hg CEMS are not sufficiently accurate or reliable at the EPA’s proposed emission le vels to justify their use. Commenter 17930 states that the UV lamps in Hg CEMS are particularly troublesome and that pr oblem, along with others, results in numerous failures of the CEMS.

Comment 16: Commenter 17675 describes agreements with th e state permitting authority to reduce Hg emissions and the associated experience with Hg CEMS on coal-fired EGUs. According to the commenter, these systems provide accurate and aud ited continuous monitoring for Hg emissions. Even though these CEMS are currently state of the art, the lower limit of quantification for these CEMS and other similar technology is very near the Hg level required to be achie ved 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 “DETERMININGTHE VARIABILITY OF CMMS AT LOW HG LEVELS”. The commenter states th at while it is likely that the quantification limits of Hg CEMS will improve as more systems are installed to monitor for compliance with the MACT standards, EGUs subject to these proposed standards that prefer to install CEMS early may be forced to install sorbent traps to be assure d that the systems will meet MACT monitoring requirements. Commenter 17675 believes that sources that have already installed Hg CEMS should be given an automatic extension of th e Hg monitoring requirements if the CEMS that are already installed need to be upgraded to meet the EPA’s monitoring requirements.

Comment 17: Commenter 17728 relays experience with Hg CEMS operating on side-by-side sister units and states that the instruments do not yield comparable results for unknown reasons.

Response to Comments 14 - 17: If for a particular source, a facili ty believes that a Hg CEMS cannot achieve the performance requirements needed to satis fy the final standards, the facility may elect to install and use a sorbent trap mon itoring system to monitor for conti nuous compliance. There are data in the draft report cited by one of the commente rs, “DETERMINING THE VARIA BILITY OF CMMS AT LOW HG LEVELS,” that demonstrates reasonable performance of at le ast 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 expe rience with eight installed Hg CEMS at three facilities in New York, the cost to operate and maintain these system s are not warranted given obvious compliance. According to the commenter, ingeneral, CMMS are e xpensive to operate and maintain, there is a limited pool of qualified support contractors, they ar e tricky to install, difficult to operate correctly, and, since the inst allation of baghouses at Dunkirk and Huntley, the concentrations are so low that we are not always confident of the resu lts even when the calibrati on and all requirements are met. The commenter states that if the CMMS had been required under CAMR, the commenter suspects that resolving the problems woul d have been very difficult. The commenter recommends a reduced monitoring plan if faci lities 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 be lieves those provisions a llow for cost-effective monitoring where sources have very low emissions.

Comment 19: Commenter 17761 states that based on their more than 4 years of experience with Hg CEMS at the Scott Energy Center Unit 4 Hg CEMS can overstate actual emissions, demonstrates significant variability, does not nece ssarily correlate with stack test ing measurements (20-25% higher than through stack testin g), and will have difficu lty meeting the aforementioned 95% availability requirements.

Response to Comment 19: See response to Comments 12 and 13 above.

Comment 20: Commenter 17805 states that based on their experience with Hg CEMS they have found the system to challenging and the company is st ill working with the Hg CEMS vendor to resolve monitor issues. Based on th is, the commenter states that it is still appropriate for the EPA to allow alternative methods of demonstrat ing compliance. The commenter further notes that the EPA should confirm with suppliers and vendors th at all necessary Hg NIST traceable calibration gases are available. The commenter also believes the certification requirement for the monitoring system NIST certified calibrator by an offsite third party vendor will cr eate challenges for system s already installed under state-specific requirements. The commenter reco mmends 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 understandi ng 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 approach es to Hg CEMS calibration including NIST traceability of elemental and oxidized Hg ga s generators based on its work with NIST and numerous other stakeholders. To the extent that the commenter or others believe an alternative calibration approach can provide equi valent results, then the commen ter may apply for an alternative method under the provisi ons of section 63.7(f).

Comment 21: Commenter 17690 states that becau se New York State requires Hg CEMS they are in a unique position to comment on the proposed rule’s continuous compliance requirements. The commenter believes that all of the proposed additiona l monitoring requirements are similar to the New York requirements in that they re present the specificati on of an advanced technology that does not have a long and widespread history. Th e commenter states that while the testing equipment vendors may114 argue that their monitoring systems are fully functional, the commenter’s experience is that for these types of applications the vendor infrastructure, industry capabilities, and even regulatory understanding and support are inadequate to meet the compliance schedule in the pr oposed Utility MACT rule. Further background information and detail to this commen t are provided in Appendix 2 (see EPA-HQ-OAR2009-0234-17690-A1.pdf for Appendix 2 pg 21.) The comm enter provides the following observations and recommendations:

1. Commenter agrees that it is appropriate to harm onize monitoring and reporting requirements, to the extent possible, with those of 40 CFR Part 75. 2. Commenter supports the option to s imply integrate air toxic emissions data and QA test results into the existing 40 CFR Part 75-compliant data acquis ition and handling system computers already in place. However, we would prefer to use the 40 CFR Part 60 deviation-based reporting approach because acid gas, metal and PM hourly measurements have little value; ultimately, long-term totals are of greater value in determining impact. 3. According to the commenter, it is appropriate to use the existing Emissions Collection and Monitoring Plan System (ECMPS) infrastructure for reporting air toxics dataand QA test results but commenter does not believe that is appropriate to develop a differe nt reporting system. 4. Commenter supports disabling the bias adjustment for all air toxics data because bias adjustment is only appropriate for emissions trading programs. 5. Commenter agrees that hours when a monitoring system is out of service should simply be counted as hours of monitor down time, to be counted against the percent monitor availability. 6. Commenter favors the EPA’s proposed streamlined continuous compliance approach and suggests that if this program were to integrate the CleanAir Markets Division (CAMD) staff experience to the maximum extent possible thatthe reporting process will be user friendly and efficient. 7. Commenter recommends adding at le ast 2 years to the final implementation date for the continuous monitoring requirements. During the extended im plementation period, affected sources should provide documentation of procurement, installati on and testing progress. The EPA and NIST should develop the necessary traceability protocols and testing programs necessary to support widespread air toxic continuous monitoring programs. It would also be appropriate to try to develop sorbent trap methodologies for air toxics. 8. Commenter recommends that if continuous monitoring at any affected source finds that the majority of observations are less than a ce rtain level then the source shoul d 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 μ g/m3.

Response to Comment 21: The EPA largely agrees with the co mments related to the use of ECMPS and electronic reporting of data. See further discussion under s ection 5B04 of this document. The EPA disagrees with the need for an additional 2 year s for compliance with the monitoring requirements. Compliance with the final rule is 3 years followi ng promulgation, which should provide sufficient time for continued advancement of Hg CEMS monitoring technology, which has already been demonstrated successfully at numerous f acilities. For the bias adjustment co mments, 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 requirem ents in Appendix A for Hg go far beyond what is necessary. According to the commenter, the EPA por trays this proposed reporti ng requirement as easy and that sources would “simply inte grate Hg emissions data and QA testresults 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, so urces would “need to have a data handling system(DAHS) that: (1) Is programmed to capture da ta from the Hg CEMS; (2) uses the criteria in Appendix F to Part 60 to validate or invalidate the Hg data; (3) cal culates hourly averages for Hg concentration and for the auxiliar y 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; a nd (5) identifies any devi ations that must be reported to the agency.” 2. “Simply integrate Hg emissions data and QA test results into the existing Part 75-compliant DAHS” and submit data through ECMPS. Af ter presenting these tw o options, the EPA stat es that it obtained “feedback from several DAHS vendors” who suggested the cost of the sec ond option was “similar, and some cases, less than the cost of the first option.”

According to the commenter, however, any software under Option 2 would have to do everything the EPA described under Option 1. The commenter assert s that sources would lik ely 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 w ould be simple or cheap to implement.

Response to Comment 22: The EPA disagrees. As other commenters have stated generally, the use of a unified approach to CEMS reporting under this rule and the Part 75 reporti ng already conducted by the affected EGU population provides a st raightforward and consistent re porting method for the industry.

Commenter 17805 supports using a Hg CEMS to de monstrate continuous compliance and has been operating and maintaining a Hg CEMS to report emissions at the Lewi s & Clark Station to the Montana Department of Environmental Quality for about 2 year s. However, the system has been challenging and the company is still working with the Hg CEMS vendor to resolve monitor issu es, and therefore, it is still appropriate for the EPA to allow alternative methods of demonstrating compliance.

Comment 23: Commenter 17626 states that Hg limits need to be set to be consistent with the technology not only for control but fo r reliable and accurate measurement. The commenter believes that the proposed levels may be theoretically achi evable, but current monitoring technology and standardization does [not] exist to measure these levels accurately and precisely. According to the commenter, this places the supplier in the position of being unable to guarantee such performance. The commenter notes it is not a not a measurement supplier but supports the position taken by such organizations as the Institute of Clean Air Companies (ICAC) to resolve these issues.

Response to Comment 23: If for a particular source, a facilitybelieves that a Hg CEMS cannot achieve the performance requirements needed to satisfy the fi nal standards, the facilitymay elect to install and use a sorbent trap monitoring system technology to monitor for continuous compliance. See section 5A06 for further discussion of Hg CEMs and sorbent trap monitoring.

Comment 24: Commenter 17637 states that itis not precisely determined whether test methods exist that are accurate, reliable and c onsistent enough to ensure compliance with the stated emission limits. Hg stack testing and other on-line measurements have not been fully developed to provide an accurate, repeatable and reliable level of Hg emissions. According to the commenter, although a performance specification has been proposed by the EPA, the hardwa re to support such a sta ndard in the day-in-andday-out environment is still unproven.

Response to Comment 24: The EPA disagrees that the test me thod and monitoring hardware are not fully developed to meet the stated emission limits inthe final rule. Performance Specification 12B which116 is required in the rule along with Performan ce Specification 12A which has similar hardware requirements to those in the rule have both b een promulgated since September 9, 2010 (75 FR 54970). See 5A06 in this document for further discussi on of Hg CEMS and sorbent trap monitoring.

4. QA requirements for elemental and HgCl 2 generators.

Comment 25: Commenter 17197 has concerns with Appendix A, section 3.2.1.2 Reagent and Standards Requirements and sections 3.1.4 and 3.1.5 based on experience with an Hg CEMS since 2007. The commenter has concerns with the referenced NIST traceability protocol’s 8- quarter recertification interval for HgCl 2 “user generators” because th ese interim protocols will requi re the “user generators” to be removed from the Hg CEMS and sent to the ma nufacturer for recertifi cation. According to the commenter, these calibration gas generators are inte gral components of the TEKRAN Hg CEMS and are not easily removed or reassembled. The commenter st ates that the TEKRAN Hg CEMS is not designed to accept calibration gas from a ge neric “Field Reference Generator, ” or cylinder gas standard (NIST transfer standards) and that recer tification of the “user generators ” may require that many of their subassemblies (gas and liquid flow meters, temperatur e controllers) be calibra ted to NIST reference methods. According to the commenter, this requir es specialized equipment and knowledge generally available only from the manufactur er and consequently, the “send-to -manufacturer-for-re certification” prerequisite is the only real opt ion provided under the interim protoc ols. According to the commenter, this option presents significant challenges, costs, and risks because the seque nce of removing the user generator, installing the temporar y user generator, configuring the DAHS for the temporary user generators, and then rein stalling the recertified us er generator and reconf iguring the DAHS for the recertified user generators is ve ry complex. The commenter states th at specialized TEKRAN knowledge is required for these certification ac tivities. A significant concern for the commenter is the potential for generator and Hg analyzer cont amination, and equipment damage during disassembly, shipping, and reassembly. According to the commenter, the elemental and HgCl 2 generators contain very delicate subassemblies that can be damaged in shipping, whic h may affect the recertification. The commenter states that to help ensure proper Hg CEMS ope ration, onsite equipment ve ndor technical assistance would likely be required to install the temporary user generators and to reinst all the recertified user generators. The commenter believes th at the significant costs, technical challenges, and equipment risks associated with the interim NIST traceability protocol’s user generator recertification interval provisions are overly restrictive. Consequently, the commente r advocates that the pro posed NIST traceability specifications referenced in Appe ndix A only become effective when they become final and that the “... or an interim version of that protocol ” phrase in Appendix A, sections 3.1.4 and 3.1.5 definitions be deleted.

Comment 26: Commenter 17197 also recommends that the interim NIST tr aceability protocols be modified to include a recertificat ion interval extension option for th e user generators when the Hg CEMS meet a RATA incentive specif ication. The commenter proposes th at the final NIST traceability protocols contain a RATA performance incentive option that extends the user generators’ 8-quarter recertification in terval another four quarters if the Hg CEMS successfully pa sses the annual RATA testing at the following proposed incentive specification:

 10 percent RA,

 or < 0.8 μ g/scm difference, if RM average is ≤ 5.0 μ g /scm.

According to the commenter, the proposed <0.8 μ g/scm difference is consiste nt with the linearity and integrity check requirements. It is the commenter’s view that the us er generators should retain their NIST 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., daily calibration, weekly integrity, quarterly linearity). The commenter assert s that if the Hg CEMS cannotachieve 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 co mplexity of the user ge nerator recertification
process.

Response to Comments 25 and 26: The EPA disagrees. The interim NIST traceability protocols for elemental and oxidized Hg gas generators represent si gnificant 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 a ddressing those issues. In fact, one pa rt of this collaborative effort between the EPA and its stakeholders focused on the de velopment of an approach to allow the elemental Hg generators to remain ‘in the field’ for recer tification and one of the organizations representing industry demonstrated how it could be effectively accomplished.

5. Monitoring challenges for new unit Hg limits.

Comment 27: Commenter 17622 believes that Hg CEMS ar e superior to sorbent traps because continuous monitoring is best done with methods that provide “real time” monitoring that can alert operators to changes in conditions th at affect emission rates. Accordi ng 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 achie vement of compliance at the newunit limits. The commenter believes that operators will likely target lower emissions levels (e.g., ~50 percent of the limit for a new unit) for their control set points, in order to have sufficient margin to achieve the proposed 30-day rolling average limitation. According to the commenter, as electron ic real-time Hg CEMS will likely be used for emissions control, monitoring and reporting, there ar e a number of prospective hurdles for new units because commercially-available Hg CEMS have not been fully certified at low levels (<1.0 μ g/m3) due to the NIST standard at 0.5 μ g/m3 only recently being available. Commenter 17622 goes on to state that the EPA NIST protocol for traceability of Hg generato rs has not been implemented at Hg concentrations <0.5 μ g/m3. According to the commenter, more testi ng, and possibly developm ent and evaluation of commercially-available Hg generators, is needed to ensure that NIST traceabil ity 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 st ates that Sorbent Trap Reference Method 30B requires a fresh look, particularly relative to sampli ng protocol and lower limits of detection (LLD) to meet and certify the new EGU limits for Hg and that itis unlikely that current electronic Hg CEMS can be confidently or reliably employed for monito ring, control and reporting of prospective new EGUs emissions under the proposed Utility MACT. Accord ing to the commenter, there are clearly both challenges and concerns about th e traceability of commercially - available Hg CEMS required to effectively administer the proposed existing unit emission limits. The commenter recommends that the EPA develop a strategic initiative with NIST, targeting lower-level Hg (i.e., <0.5 μ g/m3) calibration and standards traceability and support for Hg CEMS and sorbent trap methods.

Comment 28: Commenter 17758 states that the proposed ne w source Hg limit cannot be measured by any current or planned instrument, and even if a new unit could meet the limit, there is no way to assess compliance.

Response to Comments 27 and 28: The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. The EPA believe s the record clearly s hows these to be proven technologies, each providing certain advantages. For existing and some of the new unit limit standards,118 the level of the NIST traceable Hg standard is adequa te and consistent with existing applications of Hg CEMS. For the lowest new unit standard, the affected facilities may opt to us e sorbent trap monitoring systems to comply. As noted in a previous response , there are data in the recent draft report entitled “DETERMINING THE VARIABILITY OF CMMS AT LOW HG LEVELS,” that demonstrate reasonable performance of at least one Hg CEMS at Hg levels below 1.0 ug/m3 down to approximately 0.1 ug/m3.

Comment 29: Commenter 17704 supports both the use of Hg CE MS and the alternative use of sorbent traps as proposed. The commenter also supports the proposed use of 30 days worth of valid Hg CEMS data as the initial compliance test.

Response to Comment 29: The EPA acknowledges this support. See further discussion of sorbent trap monitoring option, below.

Comment 30: Several commenters (17758, 17868, 18428) state that the Hg monitoring requirements should be revised because the accuracy of Hg CEMS near the concentration of the proposed existing source limit is questionable, and one commenter states the technology is not viable at the proposed level of the new source limit for the following reasons:

 The high relative uncertainty of NIST-traceable calibration gases and the lack of any NISTtraceable calibration gases corresponding to the proposed emissions standard.

 Persistent issues transporting samples fr om the stack to the measurement cell.

 The EPA acknowledged unreliability of Hg CEMS at concentrations corresponding to the standard when responding to questions on the EGU ICR; see https://utilitymacticr.rti.org/F AQ/FAQEmissionsTesting.aspx#TEST-002

.

Commenter 17758 states that without further investme nt in developing Hg CEMS technology to address issues with the availability of NI ST-traceable calibration gases at th e appropriate concentration levels and sample transport, the only viable option for electric utilities for m eeting the continuous Hg measurement requirement is to install, certify and operate a Hg sorbent trap -based monitoring system meeting the specifications in PS12B.

Response to Comment 30: See response to Comments 27 and 28 above.

Comment 31: Commenter 17383 states that theyinstalled 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 calib rators and calibration gases to i ndustry. The commenter states that with respect to standards for new units, the EPA de veloped 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 ope rator. Sorbent trap monitoring has been shown to be highly reliable and accurate for long term monitoring of HG emissi ons. Those options should provide sources with the flexibility to select and operate the monitoring system that provides effective da ta collection sufficient to demonstrate compliance. We understand the concern about the technical hurd les with applying new technologies but we disagree that the Hg CEMS technology is not ready for this application. See also the response to Comments 14- 17, above and 32-34, below.119 6. Sorbent traps.

Comment 32: Commenter 17402 expresses strong support for the use of sorbent traps as the preferred method for Hg monitoring because the commenter’s experience has been that CEMS struggle to measure low levels of Hg in the range of 0.10 μg /m3 to 0.50 μg/m3. By contrast, according to the commenter, sorbent traps are demonstrably capable of measuring Hg in that range, and sorbent traps offer a more consistent and accurate means for monitoring complian ce. The commenter states that consequently, the EPA should ensure that sorbent traps remain a permissible means of compliance monitoring in the final rule. If the EPA decides to allow only one method of monitoring, the commenter favors the use of sorbent traps becau se of their heightened accuracy when compared with Hg CEMS. The commenter relays specific expe rience with both CEMS and sorben t traps that indicates monitoring results with sorbent traps are more reliable. The comme nter believes that it would be far more reliable to look to sorbent traps for compliance with the MACT rule for facilities emitting more than 22 pounds per year, and the commenter provides a lengthy list of problems encounter ed with Hg CEMS deployments and highlights how sorbent traps do not encounter these problems.

Comment 33: Commenter 18023 states that a sorbent trap-based Hg monitoring systemis not a realistic option for units using ACI because r eal-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 system s, but the new source Hg emission limit is so stringent that it will require sorbent injection for contro l, yet sorbent trap based monitors cannot be used to modulate ACI systems. The commenter states th at sorbent trap based Hg monito ring systems would have limited use on any unit unless the compliance averaging time is ex tended to at least a 90-day block average because if significant amounts of data are lost over th e 30-day compliance period, then demonstrating compliance becomes problematic. According to the commenter, sorbent trap based Hg monitoring systems have the potential for losing at least seven days’ and as much as fourteen days’ worth of data. The commenter states that the potent ial loss of data out of a 30-day pe riod would be a particular problem for units that must meet the new source limit because the Hg compliance limit is so low for those units.

Comment 34: Commenters 17808 and 18025 support the use of sorbent traps and note that the EPA should not assume that most EGUS have Hg CEMS.

Comment 35: Commenter 18421 strongly supports the EPA’s pr oposal to require the use of CEMS or sorbent traps for Hg as this will ensure affected sources can demonstrate continuous compliance with the proposed Hg emissions standards. According to the commenter, the EPA’s assessment that most, if not all, units that would have been subject to the CA MR had purchased an advanced Hg monitoring system like CEMS or sorbent traps is s upported by evidence in a report by NESCAUM. The commenter states that according to NESCAUM, Hg CEMS and sorbent traps are currently in use on over 700 coal-fired power plant stacks (over 600 Hg CE MS and nearly 100 sorbent traps) (see NESCAUM, Technologies for Control and Measurement of Mercury Emissions fr om Coal-Fired Power Plants in the United States: A 2010 Status Report). According to th e commenter, the EPA also correctlypoints out that many states require coal-fired units to install and operate such controls to de monstrate compliance with SIP or consent decrees.

Comment 36: Commenter supports the inclusion of sorbent trap monitoring systems as an appropriate testing method for continuous Hg monitoring. Commen ter installed both CEMS and a sorbent trap on Unit 2 at its Spurlock Station in2008 to compare the operation and maintenance characteristics of the two technologies; operation of the Hg CEMS began in October 2008 an d sorbent trap monitoring in120 January 2009. The commenter states that it has experi enced recurring reliability issues with the Hg CEMS including constant calibration drift issues, sample tr ansport issues, probe c onvertor failures, Hg analyzer and Hg lamp failures, design issues th at result in a time consuming process to diagnose problems, the need for continual recertification of the calibrato r 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 th e system including reliable design with no sample transport issues (the sample is co llected at the end of the probe in the traps), the system is simple, problems are diagnosed easily and qu ickly, the system is appropriate for wet stacks and the system provides accurate Hg data.

Response to Comments 32 - 36: The final rule includes the option of using sorbent trap technology as well as Hg CEMS for monitoring comp liance with the Hg standard. For th e 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 bac kup monitoring provides a further op tion for addressing the concerns over data loss mentioned by the commenter. The EP A disagrees that the sorbent trap method cannot work on a continuous basis at the emission limit levels in the final rule. While it is true that the potential exists for increased capture of other stack gas constituents by the sorbent traps during long-term monitoring, PS12B addresses this situation. As a result, achieving the monitoring method’s measurement performance requirements ensures data of known and acceptable quality. The EPA disagrees that a systematic error exists between the Hg CEMS and sorbent trap technology. In fact, the data from the EERC study definitively show that the agreement between the sorb ent trap technology and Hg CEMS at these low levels is significantly better than that required by the relative accuracy specifications in PS 12A, which are consistent with those in the final rule. Als o, with respect to PS 12B, section 8.3.2, PS 12B is an approve d regulatory requirement that ha s gone through notice and comment rulemaking as an appropriate set of requirements fo r a sorbent trap monitoring system. The EPA is not revising PS 12B as part of this rule making. The requirement to utilize th e same type of sorbent material in the sorbent trap monitoring system as will be used in the future for daily operations simply provides for an additional check on the overall system and procedures. If Method 30B is employed as the reference test method to conduct the relative accuracy testing, the tester may choose to use a different sorbent for the Method 30B sampling train to provid e additional independence in the measurements. For low level concerns, the EPA disagree s that the sorbent trap referen ce method (Method 30B) is unsuitable to reliably perform RATA testing on electronic CEMS at low Hg emissions concentrations. Method 30B is a performance-based method that is, in effect, self-validating each time it is applied and the methodspecific performance criteria are me t. Moreover, recent testing conducte d as part of the Utility MACT ICR demonstrated that Hg concentrations well below 0.1 μg/m 3 (100 ng/m 3 ) were reliably 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 perf ormance capabilities of Method 30B. For NIST capability issues, see earlier response to Comments 27, 28, and 30.

Comment 37: Commenter 17757 suggests that quarterly performance tests and analyses of sorbent trap monitoring data would be adequate to determin e compliance with an annual emission limit.

Response to Comment 37: The EPA disagrees. Monitoring tec hnology adequate to show continuous compliance in accordance with the emission limit exists and is preferable to periodic emissions testing. In other circumstances unde r the rule, the EPA has allowed for peri odic 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 38: Commenter 17775 supports use of sorbent trap monitoring systems and reliance on PS 12B, subject to the following commen ts. According to the commenter:

1. First, the EPA should explicitly provide an optio n for use of backup monitoring systems to allow sources to plan for the possibilityof significant monitoring system failures where it is economical to do so. 2. Second, the EPA should provide a low emitter “br eakthrough” specification in PS 12B and in 40 CFR Part 60, Appendix A, Method 30B. According to the commenter, the current performance specification for Method 30B allows for 10 percent br eakthrough for effluent concentrations above 1
μ g/m3 and 20 percent for concentrations below 1 μ g/m3, and as the actual effluent Hg concentration approaches zero, this specification becomes virtuallyimpossible 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 du ring testing for the 2010 ICR, RMB Consulting & Research, Inc. identified this i ssue 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, In c., “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 percen t-based specifications lose meaning as results approach zero, and RMB recommended that the EP A provide the following a lternative performance specifications for breakthrough: A) For concentrations < 0.5 μ g/m3 but > 0.1 μ g/m3, the alternative breakthrough criteria could be < 50 percent of section 1 Hg ma ss; B) For concentrations < 0.1 μ g/m3, there would be no breakthrough crit eria and the validity of the sa mples would rest on all other performance specifications being met.

According to the commenter, in response, the EPA st aff indicated that, for the purposes of the 2010 ICR testing, and for stack concentra tions less than or equal to 0.5 μ g/m3, EGUs could consider Method 30B data valid as long as it meets all other QA/QC criteria, even if it does not meet the section 2 breakthrough criteria of Table 9- 1 of Method 30B but that the EPA indicated that approval of the exception for the use of Method 30B when conduc ing RATAs or compliance tests would require additional discussion within the ag ency. Commenter believes that a num ber of units being retrofitted with baghouses and scrubbers may achieve Hg emissions levels below 0.5 μ g/m3. According to the commenter, in order for sorbent trap monitoring syst ems 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 shoul d be provided in Method 30B, and commenter requests that the EPA promulgate those revisions concurrent with fina lization of subpart UUUUU, or complete a rulemaking to revise PS 12B and Method 30B well in advanc e of the subpart UUUUU compliance deadline.

Response to Comment 38: See the responses to Comment 7, above.

Comment 39: Comment 18449 states the continuous sorben t trap method has not been tested or validated at the very low leve ls 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 meas urements. The commenter st ates that cartridges will be exposed continuously for (typically) 1 or 2 weeks, resulting in massive buildup of other stack contaminants as compared to the short term (2 to 4 hour) exposure period of reference cartridges. According to the commenter, the high levels of poten tial interferents that are co-eluted when the cartridge is heated will challenge the performance of the analytical 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 extr aordinary care in running the samples, and the manufacturer of the analyzer, Ohio Lumex, pr ovided considerable support throughout the study. The commenter states that agreement between the Tekran CEMS and the sorbent tr aps was very good, with virtually no zero offset and a R2 value of 0.990. Th e commenter states that even under these best possible conditions, there was a systematic 11 percent difference in sensitivity between the Tekran CEM which used a NIST traceable elemental gas generator for calibration, and the sorb ent traps, which used a NIST traceable liquid solution for calibration. Th e commenter questions which was correct.

Commenter 18449 states that PS 12B is mentioned as the standard for continuous sorbent Hg monitoring systems. The commenter provides that Section 8.3.2 under RATA testing, states that “The type sorbent material used in the traps must be the same as that used for the daily operation of the monitoring system.” According to the commenter, the purpose of a RATA is to provide an independent test of the validity of the continuous monitoring system’s resu lts, and if different sorb ent types yield different results, this is an indication of a severe problem somewhere. According to the commenter, it may be desirable, from a user point of vi ew, 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 withrespect to the sorbent tube provisions:

1. If Hg levels in the low ng/m3 range are set as th e 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 estab lish that it could be used to reliably perform RATA testing on electronic CEMS. 2. NIST is incapable of measuring or certifying Hg concentrations in the low ng/m3 range. According to the commenter, after 5 years of effort, th e lowest point that NI ST can certify is 0.5 μ g/m3 and even this point can only be certifie d to an uncertainty of 6.1 percent. The commenter notes that this level of uncertainty applies to the NIST calibrator only and that vendor and user calibrators would have still higher uncertainties. Absent major developments, the commenter does not believe the NIST traceable gases be available to validate low ng/m3 measurements.

Response to Comment 39: See response to Comments 32-36 above.

7. Provisions for Hg CEMS on bypass stacks.

Comment 40: Commenter 18023 states that the final rule should clarify the provisions for units with a main stack and a bypass stack regarding use of th e maximum potential concentration (MPC) for each hour in which the bypass stack is us ed. According to the commenter, if this approach is used, the EPA needs to clarify what value is used when Hg CEMS installed on a bypass stack measures a number higher than the MPC. The commenter also asserts th at the EPA should specify that when multiple units are controlled by the same device and less than all of those units are being bypassed only the MPC for the units being bypassed, should be reported. Accordi ng to the commenter, MPC should not be used for any of this since the MPC approach is only used for emission trading programs; a lower confidence interval type of value should be used instead fo r conditions where a bypass stack is not monitored.

Comment 41: Commenter 17774 states that one difference between se ction 63.10010(a) and Appendix A section 2 is the provision of an option for use of an assumed value durin g use of a bypass stack. The commenter states that Appendix A section 2.4.2 provides for use of the “maximum potential concentration” of Hg in lieu of installing an Hg CEMS or sorbent trap system on a bypass stack.123 According to the commenter, installation of CEMS on a bypass stack can be problematic from a number of perspectives. According to the commenter, in a ddition to the costs of the additional monitoring system, bypass stacks will not be used with sufficient frequency to perform those periodic QA tests that require unit operation (e.g., RATAs a nd linearity checks). The commenterasserts that correlation of a PM CEMS on a bypass stack would be nearly impossible to accomplis h without significant operation with bypass (since PS 11 require s a minimum of 15 runs).

Response to Comments 40 - 41: The EPA agrees with one of the commenters that the MPC approach for bypass stacks is more suited to an emissions trad ing program. Rather than require the use of the MPC to estimate emissions from the bypass stack, the fi nal rule now requires us e of one of two options: (1) direct monitoring of both the main stack and the bypass stack for Hg or (2) counting of bypass hours as hours of deviation from the Hg monitoring require ments. The EGU owner or operator remains subject to the 30 boiler operating day ro lling average during bypass operations . In addition, the final rule no longer requires correlation of a PM CEMS accordi ng to PS 11. The monitor will be used as a PM CPMS, although the final rule does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

8. Provisions for bias adjustments.

Comment 42: Commenter 18023 states that the final rule sh ould not require the bias test and bias adjustment for Hg CEMS as proposed in section 4.1.1.5.3 because the Hg CEMS by nature exhibit drift in both the positive and negative directions depending on the cause of the drift which is best corrected through normal quality assurance activi ties, and basing adjustment of the hourly averages on a one-time per year test would adversely aff ect data accuracy. According to th e commenter, if a bias test were required, it should quantify bias in either direction and allow for adju stment in either direction. The commenter states that when stack gas flow is used for the mass calculations then non-bias adjusted flow values should be used for that purpose.

Comment 43: Commenter 17805 agrees with the EPA that ap plication 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. According to the commenter, since Hg will not be traded, the bias adjustment is not necessary.

Response to Comments 42 and 43: No bias adjustment or bias testis required under the final rule.

9. General concerns.

Comment 44: Commenter 17621 states that the EERC of No rth Dakota conducted a study to investigate the low-level measurement capabilities and variabili ty 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 le vel of the Tekran system was 0.1 micrograms per normal cubic meter ( μ g/Nm3), compared to 0.4 μ g/Nm3 for the Thermo Scientific system (EPRI, 2010b) and that these concentrations are equivalent to about 0.1–0.4 lb/T Btu. The commenter states that Method 30B was used as the basis for comparison, with extended sampli ng times used to reach the low levels of Hg. The commenter asserts that based on this study, CMMs from both vendors can measure Hg accurately at the proposed MACT limit for existing coal-fired EGUs but that CMM would neither be able to measure Hg124 accurately at the revised MA CT limit for new coal-fired EGUs greater than or equal to 8,300 Btu/lb or at the proposed limits for either existi ng or new liquid oil-fired EGUs.

Response to Comment 44: The final rule provides the option for use of either Hg CEMS or sorbent trap monitoring systems. The EPA believes the record cl early shows these to be proven technologies, each providing certain advantages. For ex isting and some of the new unit limit standards, the level of the NIST traceable Hg standard is adequate and consiste nt with existing applications of Hg CEMS. For the lowest new unit standard, the affect ed facilities may opt to use so rbent trap monitoring systems to comply. As noted in a previous response above, there are data in the recent draft report entitled “DETERMINING THE VARIABILITY OF CMMS AT LOW HG LEVELS”, that demonstrate reasonable performance of at least one Hg CEMS at Hg levels below 1.0 ug/m3 down to approximately 0.1 ug/m3.

Comment 45: Commenter 17747 states that the cycle time test unfairly excludes monitoring technologies that can provide accurate mercury meas urement. According to the commenter, Xact (the commenter’s proprietary testing te chnology) has demonstrated its abil ity to measure Hg accurately on several different source types includi ng coal-fired power plants. Comment er provided results of studies on 585 MW coal fired electric gene rating facility equipped with E SP controls and located in the northwestern United States. According to the comment er, 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 de signed to measure Hg by sampling stack effluent nearly continuously, excluding only th e time required for the tape to advance from the sampling area to the analysis area (~ 20 sec). The sample is typicallygathered for 15 minutes and then analyzed for 15 minutes to achieve detection limits that are appropri ate for coal fired power plants, and this means that concentration data is reported a bout 30 minutes after starting to gath er the sample. According to the commenter, the proposed cycle time would preclude the use of Xact. The commenter states that the key issues are whether the instrument can measure Hg accurately and precisely and whether emissions are nearly constantly monitored and that provided the technology can dem onstrate these things, response or cycle time is irrelevant.

The commenter notes that the current cycle time re quirements are apparently based on what atomic fluorescence-based instrumentation can do. Although this te chnology can deliver mercury concentration data more quickly than XRF base d technology, it can only measure mercury. The commenter notes that the Xact, on the other hand, can measure mercury as we ll as several other metal hazardous air pollutants (HAP) including (antimony, arsenic, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium). According to the commenter, this type of data is currently not available using any other instrument, and it is unlikely that it could ever be obtained from any atomic fluorescence based instrument.

The commenter notes that the propo sed Hg monitoring performance speci fications are inconsistent with those already promulgated under PS 12A. According to the commenter, this pe rformance specification does not require a cycle time test, which indicates that EPA does not view a cycle time test as critical to the performance requirements of a Hg CEMS. The commenter notes that the reason the EPA did give for not using the PS 12A requirements is to “simplify compliance with the proposed rule by harmonizing its monitoring and reporting requirements, to the extent possible with 40 CFR Part 75.” According to the commenter, this would include eliminating semiannual hard copy reporting of de viations 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 repor ting requirements. The commenter not es that the proposed EGU MACT does allow for the use of PS 12B (sorbent trap monitori ng) and that in this case facilities may sample for125 up to 14 days before ending the traps to a lab for Hg analysis. According to the commenter, this would potentially allow 4-6 weeks to elapse before Hg data would be generated and reported, and it clearly does not make any sense to allow up to 6 weeks or more for data to be reported under one method of monitoring (sorbent traps) but re quire data every 15 minutes under a nother method (CEMS). Finally, the commenter notes that because Hg health effects are chronic there is no health benefit associated with 15- minute cycle times.

Response to Comment 45: The EPA agrees that the cycle time test requirements may be overly rigid for integrated batch sampling-based Hg monitoring t echnologies, and we have made revisions to the final rule to accommodate these technologies while still acquiring monitoring data at least once every 15-minutes consistent with our practice for CEMS.

Comment 46: Commenter 18428 states that an alternative to using CEMS for compliance, the EPA should allow fuel sampling and analysis for Hg determining Hg emissions from coal-fired units, particularly those with low coal Hg content. According to the commenter , this would be consistent with the fuel sampling option for oil-fired units under the proposed rule, as well as the similar option contained in the Industrial Boiler MACT rule.

Response to Comment 46: The fuel sampling option discussed in th e proposed rule is no longer part of the final rule because of technica l issues with those proposed requirements. The final rule retains the proposed approach for Hg monitoring, requiring either a CEMS or sorbent trap monitoring system, or LEE testing for existing units with very low emissions.

Comment 47: Commenters 17724 and 17876 state that the CEMS th e facility installed in preparation to CAMR have significant reliability and operationa l 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 me thodologies for demonstrating. Commenters 17724 and 17876 state the EPA purports to provide compliance flex ibility while in reality there is very little flexibility in light of the pr oblematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not commercially available to measure HCl emissions fr om coal-fired EGUs, and no HCl CEMS were used to collect the data the EPA used to establish the HCl standard.

Response to Comment 47: The agency disagrees with the comment ers. As mentioned elsewhere, the agency finds that the operation and maintenance issu es for the CEMS mentione d 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 w ith respect to compliance demonstra tion, containing numerous choices for compliance, including the use of em issions 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 continuousl y, that the HCl emissions limit was developed from emissions testing and has been adjusted to be ap propriate for measurement with HCl CEMS, and that emissions testing options to demonstrate complian ce exist for those EGU owners or operators who choose not to use CEMS.126 5A06a - Testing/Monitoring: Applic ation of Hg CEMS (Appendix A)

Commenters : 17725, 17770, 17795, 17796, 17800, 17820, 17821, 17881, 17886, 18449, 19114, 19121, 19122, 18023

1. Rounding issues.

Comment 1: Commenter 17881 states that section 7.1.8.2 requi res Hg mass emissions be reported as pounds, to three decimal places. According to the comm enter, this is not sufficient precision to allow a meaningful comparison to the Hg emission limit fo r new coal-fired units (c oal > 8,300 Btu/lb). The commenter states that the Hg emission limit fo r such units is 0.0002 lb/GWh based upon the EPA’s 05/18/2011 revised MACT floor analysis memorandum a nd 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 commente r asserts that after r ounding 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 emi ssion 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 indisc riminately 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 lit tle sense, as all lb/TBtu emission limits in the proposed rule are expressed to one decimal place, and several of the lb/GWh Hg emission limits are expressed to beyond three decimal places. The commenter states that as noted in relati on 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 decima l 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, woul d round to 0.000 lb/GWh, which is comp liance with the emission limit).

Comment 3: Commenter 18449 states that under “Calcula tion of Mercury Mass Emissions” on page 25145 the rule requires that report ed concentration averages for bot h CEMS and sorbent methods be rounded, to the nearest tenth but that it is not clear how this would work with proposed MACT limits of 0.02 μ g/m3, or how accurate 30-day rolling averages could be calculated with sources in the submicrogram range. The commenter states that it has existing customers that have short term concentrations of 0.03 to 0.5 μ g/m3, which have been verified by RATA testing. According to the commenter, hourly averages should be rounded to tw o or three significant figures, not tenths. The commenter believes that reporting to more decimal points has no downside provide d that violations are defined as significant exceedances of the limit and that more accurate reporting would also give customers due credit if they had low level emissions and had invested in the technology able to report them.

Response to Comments 1 - 3: The EPA agrees with the commenters regarding the precision of the Hg concentration values and the Hg emission rates. The final rule requires the hourlyHg concentrations and emission rates to be reported to three significant figures, rather than specifying a particular number of decimal places. The 30-day average Hg emission rates are to be rounded to two significant figures (i.e., the same precision as all of the Hg emission limits). We believe that these changes address the concerns of the commenters.

2. Calculating Hg emission rate.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 those derived consis tent with the procedures in s ection 3.3.6 may also be used for these calculations for calculating the Hg emissi on rate in units of lb/TBtu, According to the commenter, this change is necessary due to the fa ct that Method 19 does not contain fuel factors for subbituminous coals, petroleum coke or tire-deriv ed fuels, and the provisions of section 12.3.2 of Method 19 would therefore require fuel sampling and an alysis in order to dete rmine site-specific fuel factors. The commenter states th at the preceding would represent an unnecessary burden in light of the EPA having already established fuel f actors for these fuels under 40 CFR Part 75. 2. Sections 6.2.1.2 and 6.2.2.2 of Appendix A relate to th e calculation of Hg emi ssion rates in units of the applicable standard (i.e., lb/TBtu of lb/GWh). According to the commenter, , this section should also describe the diluent capping procedure fo r start-up and shutdown, as allowed in section 63.10005(l). The commenter states that without reference to the preceding diluent capping provisions, these sections would a ppear to always require the use of the actual measured diluent gas concentration (in the context of section 6.2.1.2) or measured electrical load for the hour (in the context of section 6.2.2.2). 3. Section 6.2.2.2 should specify the use of the gross elec trical output (consistent with the gross output definition in section 63.10042) in or der to eliminate any possible conf usion as to the basis of the MWh values to be used in the ca lculations (i.e., gross or net). 4. The formulas for calculation of the lb/GWh Hg emi ssion rate (i.e., A-2, A-3 a nd 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 electr ical load can be used to direc tly calculate the Hg emission rate in units of lb/GWh. (commenter references a formula “Consider the fo llowing substitution of Equation A-2 into the term Mh inEquation A-4, and note that the te rm th cancels out, as it appears in both the numerator and denominator:”)

Response to Comment 4: The EPA agrees with items 1 through 4 in this comment and has made corresponding changes in the final rule.

3. Grace period.

Comment 5: Several commenters (17770, 17820, 17886) note that pa rt 75 has a grace period for system integrity checks and recommend the same. Commenter 17820 states that the system integrity test is likely to be one of the most cha llenging tests and if the test cannot be automated EGUs will need to monitor operating hours to determine wh en a test will be due, and ensure that a qualified technician is available to generate the oxidized Hg and ensure that the test is conducted properly. According to the commenter, if the unit is not fully base-loaded, this will be difficult; most EGUs do not have technicians available to perform routine tests on nights and weekends, and even if the test is scheduled to be performed on time, issues with monitoring systembreakdowns 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 invalidate d, which would provide an EGU time to schedule and perform a te st if one were triggered.

Response to Comment 5: For concerns raised with the system integrity check requirement, the final rule retains the weekly system integrity check requirement, without a grace period. However, to add flexibility, the required frequency of the test has been changed from once every 168 operating hours to128 once every 7 operating days. Operating days are much easier to track than opera ting hours. The test can be done at any time during the 7 thoperating day, rather th an requiring it to be done at a certain hour. We believe that this added flexibility will allow util ities to schedule the test in accordance with the technician’s work schedule.

4. Recordkeeping and reporting under Section 7 of Appendix A.

Comment 6: Commenter 17881 requests clarification of the recordkeeping and reporting provisions contained in appendix A, section 7:

1. The commenter states that it is unclear whether th e requirements are meant to apply to the Hg CEMS and sorbent trap monitoring systems, or all m onitoring systems used to demonstrate compliance 2. The commenter states that Section 7.1 requires th at all measurements, data, et cetera, must be maintained for a period of 5 years from the date of the record. According to the commenter, since many of the auxiliary monitoring systems employed under Appendix A will also likely be subject to 40 CFR Part 75, the EPA should harmonize the data retention requirements with those found in 40 CFR 75.57(a), which requires that data be maintained fo r a period of at least 3 years from the date of each record. According to the commenter, having two different retention schedules for the same data elements (i.e., flow rate data, diluent data, et c.) will simply lead to confusion and potential noncompliance, especially in cases where a facility currently has well establis hed procedures to purge various Part 75 data elements af ter the required 3 year period. 3. The commenter states that the EPA should clarif y that none of the provisions in section 7.1.1 and related sub-sections apply to those auxiliary monitoring systems wh ich are subject to 40 CFR Part 75, as many (if not all) of these requirements are duplicative of those that already exist within 40 CFR Part 75. 4. The commenter questions the rationale for some of the requirements to be re ported in the context of Hg emissions monitoring. The commenter provides an example of megawatt ratings under section 7.1.1.2.1; according to the commenter, the EPA makes the presumption that all individual units have a defined megawatt output, which is not correct. According to the commenter, In those cases where multiple units share a common steam extraction turb ine and electrical generator, steam output is often the basis for the individual unit ratings, and this approach is clearly allowed under 40 CFR Part 75 (refer to section 75.53(e )(1)(i)(I)). The commenter also states that the basis for any load rating must be specified (i.e., net or gross). 5. The commenter notes that under sect ion 7.1.1.2.1 the identification of controls should be specific to those types of controls which have relevance under 40 CFR part63, subpart UUUUU and that these would include acid gas controls, PM controls and Hg specific controls. Thecommetner questions how the collection of information on NO X controls, for example, would be relevant under the proposed EGU MACT. 6. According to the commenter, formulas used to ca lculate emissions and h eat input under section 7.1.1.2.1 only need formulas which are specific to the determination of the Hg emission rate in units of the applicable standard. The commenter also st ates that the calculation of heat input is not required to support the Hg emission rate determina tion, and this reference should be removed from the rule. 7. The commenter states that Secti on 7.1.2 relates to vari ous operating parameter records which must be maintained “to the extent that these data are needed to convert Hg concentration data to the units of the emission standard”. According to the commenter , rather than leaving it to the discretion of the regulated entity to determine whether certain da ta elements are needed, the EPA should clearly specify which data elements are necessary for each of the Hg emission limit forms (i.e., lb/TBtu and lb/GWhr).129 8. The commenter states that Sect ion 7.1.5.2.5 also requires the reporti ng of hourly PMA, which is not appropriate when missing data s ubstitution is be ing prohibited.

Response to Comment 6: For item 1, appendix A applies to any Hg CEMS or sorbent trap monitoring system, as well as any other auxilia ry monitoring required to report emi ssions in terms of the standard. As suggested in item 3 of this comment, the final ru le clarifies that where su ch auxiliary systems are used, the recordkeeping provisions of part 75 generally apply to those systems. As in the proposal, one exception to that rule is that, consistent with th e general recordkeeping provi sions under the Part 63 NESHAP program, records used to demonstrate complian ce with this rule must be kept for 5 years. For items 4 through 6, revisions in the fi nal rule directly address these co ncerns and streamline the specific records that apply. For Item 7, th e EPA has left the “as applicable ” language as proposed; the reporting system will provide for capturing the correct inform ation 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 unnecessa ry. This information will be used to ensure that sources continue to operate and maintain their mo nitoring systems in accordance with the requirements of section 63.10020(b) and the general monitoring operation provisions that apply across part 63.

5. Recommendations - Appendix A.

Comment 7: Commenter 17725 recommends that the EPA ad d a subsection to Appendix A section 7.1.5.2.3 that clearly states that 40 CFR Part 75 data substitution procedur es 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 Secti on 3.1.12 should be rewritten to allo w the use of the closest upscale gas from actual stack concentratio ns and that currently, the propos al suggests implementing a Hg monitor span of 0-10 ug/m3. According to the commenter, for existing units > 8300 Btu/lb to demonstrate compliance with the proposed limits, Hg concentrations would need to be less than 1.2 ug/m3, and therefore the low level calibration gas would be closer to actual emissions and should be used as the daily calibration standard (20–30 percent of span value). 2. The commenter recommends quarterly, instead of weekly, oxidized Hg (Hg+2) converter checks. According to the commenter, NIST-traceable Hg +2 in the Tekran Hg monitoring systems is currently limited to ~2.5 ug/m3, but Hg+2 will be < 0.5 ug/m3 after controls to achieve compliance with the proposed standards. According to the commenter, quarterly checks will be more than sufficient at these levels. The co mmenter states that a weekly requirement was understandable for the trading program that would have been adopted for the CAMR where Hg+2 could exist in the gas stream of units purchasing of Hg allowances, but for this program Hg+2 w on’t be quantifiable for units in the > 8300 Btu/lb category. According to th e commenter, calibrating a system at more than 5 times the measurable concentration would produc e accuracy problems and filter contamination if conducted weekly at these levels.

Response to Comment 7: The EPA sees no need to add a subs ection 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 th at allowing a low-level gas to be used for daily calibrations is necessary. Appendix A provides sufficien t flexibility in setting th e Hg CEMS span value and selecting calibration gases. The span value is set starting w ith the Hg concentration (μg/m 3 ) corresponding to twice the le vel of the standard. This value is then rounded upw ard, 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 con centration of 1.2 μg/m 3 , as suggested by the commenter, the span value could ei ther be set at either 3 μg/m 3 , 5 μg/m 3 , or 10 μg/m 3 . If it is set at 3 μg/m 3 , a mid-level calibration ga s 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 fo r daily calibrations. We believe this addresses the commenter’s concerns.

Regarding the system integrity check, the EPA does not agree with the commenter that a quarterly test frequency is sufficient. To obtain accurate data with a Hg CEMS th at has a converter, you must ensure that the converter is working properly. The system inte grity check provides that assurance. Therefore, it is not appropriate to allow long time intervals betw een converter checks. If a quarterly test frequency were implemented, there could be more than five m onths between successive system integrity checks, e.g., if the test is done in early January (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 CEMS outlined in CAMR and duplicated in Appendix A of the proposal are appropr iate for determining that the unit is providing accurate results and should not be changed becaus e now compliance is based upon an emission limit and not a yearly mass for trading purposes in CAMR.

Response to Comment 8: While the EPA agrees in many respects, we have made certain changes to the CAMR-based Hg monitoring procedures as appropriate, such as not using bias adjustment factors and not relying on data substitution practices.

Comment 9 : Commenter 18023 states that under section 3.2. 3.3, to provide for efficiency, the option should be provided to allow the use of monitors already installed and certified under part 60 or 75 without any additional requirements.

Response to Comment 9: The commenter is referring to the addi tional monitoring systems described in sections 3.2.3.1 and 3.2.3.2 (not section 3.2.3.3, which addresses monitor span and range). These additional monitors (i.e., diluent gas, flow rate, and moisture ) are needed to convert Hg concentrations to the units of the emission standards. The final rule mandates that all of these monitoring systems be installed, certified, operated, and maintained according to 40 CFR Part 75 (see §§63.10010(b) through (d)), and that the data from these monitoring system s be reported using the EC MPS 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 certificati on testing is required under Subpart UUUUU for previously-certified Part 75 systems that are continuing to meet Part 75 QA requirements (see §63.10005(d)). Note, however, that the use of Part 60 monitors is not allowed---these monitors must either be replaced or upgraded to meet Part 75 requirements.

Comment 10: Commenter 17820 generally supports the EPA’s attempt to provide consistency between this proposal and Part 75 but notes that not all of the part 75 requirements are necessary in this context. Some of these concerns include:

1. Commenters 17820 and 17800 note that while the EPA proposes ongoing QA requirements for Hg CEMS in Appendix A, the rule proposes in se ction 63.10021(1)(14) to require compliance with quarterly accuracy determinations and calibration dr ift tests in accordance with Part 60, Appendix F, Procedure 5. According to the commenters, the qu arterly and daily requireme nts in Procedure 5 are duplicative of and conflict with some of the proposed requirements in Appendix A, and use of131 Procedure 5 is inconsistentwith the EPA’s preamble statement th at it considered and rejected using Procedure 5. 2. The commenter opines that two provisions from Part 75 that could help improve data availability are the provisions for use of back up monitoring systems and the provisions for use of conditional data validation. According to the commenter, these opti ons have been used under Part 75 for years without any reduction in data quality, and the EP A should include provisions in Appendix A to allow use of similar procedures. 3. The commenter opines that the EPA should incl ude back up and like-kind replacement monitoring system options similar to Part 75 in Appendix A. According to the comment er, including specific provisions will avoid the need for future guidance a nd/or unit-specific petitions if cases arise where a backup or replacement is needed. 4. The commenter states that Secti on 75.20(b)(3)(ii) allows sources that have made a change to a monitoring system that requires additional tes ting (e.g., repairs, replacements, adjustments, linearization, reprogramming, reloca tion, etc.) to conditionally validat e data prior to completion of all required tests by performing a successful “probati onary calibration error te st.” According to the commenter, this provision has been crucial to ma intaining good data ava ilability under Part 75, by avoiding invalidating data after a monitoring system has been confirmed to be operating properly but before all of the required confirming tests can be scheduling and completed.

Response to Comment 10: The final rule removes the references to Procedure 5 and adopts the part 75 options discussed in items 2 through 4 of this comment.

Comment 11: Commenters 19121 and 19122 support the monitori ng requirements for Hg outside of part 75. However, the commenters recomme nd the following changes to Appendix A:

1. Commenters recommend amending the minimum requi rement 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 alternativ e 2 for accounting for gas mois ture content under section 3.2.3.1 commenters believe that the moisture value need not be limited to the most recent Hg emissions test. Commenters recommend that any test event that requi res a Method 4 analysis to be performed such as a CEMS RATA or Method 4 particulate test result be a valid representation of the stack moisture condition.

3. Commenters recommend that “sig nificant percentage” language in section 5.1.5 be more clearly defined. The commenters believe that it is likely infeasible to perform a diagnostic linearity check within 168 hours of a span change as it would require that the Hg calibration gas gene rators’ output values be adjusted by the manufacturer to th e new linearity requirements which require new NIST certification of the generators. Thus, according to the commenters, the time needed to ship the calibration gas generators to the manufacturer, modify and recertify the gene rators can take longer than 168 hours. Commenter 19121 recommends that owners/operators have 30 operating days to perf orm 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 secti on 6.1.3 that states “for any operating hour in which valid data are not ob tained, either for Hg concentration or for a parameter used, in the emissions calculation, or moisture, as applicable, do not calculate th e Hg emission rate for that hour.”132 5. Commenters recommend the EPA incorporate by referenc e parts of Part 75 that are used to determine Hg emission rate calculations in section 7.

Response to Comment 11: Regarding changes 1) through 5) suggested by the commenters:

1. At this time, the EPA has no inte ntion of reducing the minimum number of test runs for the RATA of a Hg CEMS from nine to three, as recommended by the commenters. The nine run RATA is a wellestablished procedure that provides a robust statis tical basis for determining the accuracy of a CEMS, and is familiar to, and widely accepted by, the regula ted community and source testers. The commenters provided no data to support their cl aim 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 propos ed reduction in the number of paired runs to “certification and r ecertification events in other app licable Part 60 rules” is beyond the scope of this rulemaking.

2. Sections 63.10010(b) through (d ) of the final rule specifies that a ll of the additional monitors needed to convert Hg concentrations to units of the emi ssion standard must meet the requirements of 40 CFR Part 75. To account for stack gas moisture content, Part 75 provides three po ssible compliance options: (a) install and certify a continuous moisture monitoring system; (b) use a fuel-specific default moisture value from §75.11(b); or (c) petiti on 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 renum bered 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 requireme nt to perform a diagnostic lin earity check within 168 operating hours after changing the span of a Hg analyzer has been retained, but a clearly defined window of time in which the span change must be implemented has been added. The owner or operator has up to 90 days after the end of the calendar quarter in which the need for a span change is identified to implement the span adjustment.

4. The EPA has not incorporated the commenter’s r ecommendation. 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 consis tent with a long-standing pos ition that compliance with emission rate limits must be based exclusively on actua l, 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 progra ms 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 s uggestion to simplify section 7 of Appendix A by referencing relevant sections of Part 75, but only for the additional m onitoring systems that are needed to convert Hg concentration to units of the standard (i.e., diluent gas, flow rate, and moisture systems). Similar cross-referencing of Part 75 is not possibl e for Hg emission rate calculations because, as explained in the previous paragraph, Part 75 no longer includes Hg m onitoring provisions.133 Comment 12: Commenter 17800 states that the EPA needs to remove the requirement for a NIST traceable oxidized Hg standard from the certification tests (see 86 FR 25034). The commenter is not aware of any oxidized standard for Hg, let alone a “NIST-traceable oxidized Hg standard”.

Response to Comment 12: The definition of a “NIST-Traceable Source of Oxidized Hg” in section 3.1.5 of Appendix A refers to a generator that: (a) is capable of providing known concentrations of vapor phase mercuric chloride and (b) meets the perf ormance requirements of the interim version of the “EPA Traceability Protocol for Qualification and Cer tification of Mercuric Chloride Gas Generators”. That traceability protocol was developed with signif icant 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 measure these reagents in th e process of producing the gas, e.g., weighing and mass flow meters. This approach represents th e current “state of the art” and has been agreed upon by EPA and industry as an in terim methodology. Further re search is needed to develop direct NIST traceability for oxi dized Hg calibration gas standards.

Comment 13 : Commenter 17821 states that section 3.2.1.4.3 propos es to require that the full “range” of the Hg analyzer be capable of measuring the MPC values that are de fined in section 3.2.1.4.1. Commenter encourages the EPA to define the MPC va lue as the “span” and “range” of the Hg CEMS and suggests that this value be used as the basis fo r determining calibration and linearity gas values and calibration errors. According to th e commenter, modern Hg CEMS ar e based on digital technology and do not have “span ranges” built in to the technology like the older an alog analyzers of the past. The commenter states that they do have analog outputs th at can be scaled such that a zero and full scale value can be defined to match with the 4-20 mA output signal used for data recording, but that this setting is not a span range setti ng in the analyzer. According to th e commenter, modern Hg analyzers have a measurement range that is limited only by the lower and upper detection limits of the measurement sensors within the analyzer. Commenter understands the need to determine the accuracy of an Hg analyzer and the need to determine calibration and linearity errors. However, according to the commenter, defining an arbitr ary value for “span” is meaningless to a modern Hg analyzer, and a better method would be to utilize a standard “span” valu e for all Hg CEMS used in compliance with these proposed rules. (Commenter provides an example .)

Comment 14: Commenter 17821 recommends that the EPA defi ne the “range” of the Hg CEMS as a range from zero to the appropriate MPC (see s ection 3.1.13). According to the commenter, a source would then perform linearity checks “across the range as determined by these rules” instead of across the analyzer’s entire measurement capability. The co mmenter states that mode rn Hg analyzers have a large measurement range, and the commenter does not be lieve that EPA intended for sources to test the analyzer across its entire range of measurement but rather across the “span” or full “range” defined for use with compliance of these proposed rules.

Response to Comments 13 - 14: The commenter appears to misunderstand the terms “span” and “range” as they are presented in Appendix A. Th e purpose of the span value is to determine the appropriate calibration gas con centrations for daily calibrations and linearity checks---these concentrations are all expressed as percentages of the span value. To comply with the stringent Hg emission limits in subpart UUUUU, Hg concentrations must be reduced to very low levels. Section 3.2.1.4.2 of Appendix A requires the span value to be set by multiplying the Hg concentration corresponding to the standard by two, and then r ounding off the result appropr iately. Flexibility is provided; the span value (in units of μg/m 3 ) may be rounded to either the ne xt highest integer, the next134 highest multiple of 5 μg/m 3 , or the next highest multiple of 10 μg/m 3 . If better accuracy at the lower end of the scale is desired, rounding off the span value to the next highest integer or multiple of 5 μg/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). Th e EPA recognizes that low Hg conc entrations are often attainable only by operating wet scrubbers and/or carbon injecti on systems, and that it is possible for these emission controls to malfunction. During control devi ce malfunctions, Hg concentrations may approach the level of the maximum potential concentration (MPC). Therefore, section 3.2.1.4.3 of Appendix A also requires the Hg analyzer to be capable of reading Hg concentrations as high as the MPC.

Comment 15: Commenter 18023 states that section 3.1.7 re quires the span value to be set to approximately twice the concentr ation corresponding to the emissi on standard and alternatively rounding the span value to the nexthighest interval of 10. Accordi ng to the commenter, based on the emission limit stated in the current draft rule, th is would restrict the sp an value to either 2 μ g/m3 or 10
μ g/m3. Commenter recommends that they should be a llowed to set the span value anywhere between 2 and 10 μ g/m3 as long as that range falls within acceptable limitations of the NIST traceable calibrator. The commenter states that the EPA also proposes that the full-scale range shoul d be set to include the MPC. According to the commenter, the EPA should al low the full-scale range to be set at one number (10), and perform quality assurance testing over a lo wer portion of that range (0- 5). The commenter also states that 40 CFR part 75 has an annual requirement for the major ity of analyzer readings to be between 20 and 80 percent of full-scale, which should not apply to Hg.

Response to Comment 15: In the final rule, greater flexibility in setting the span value is provided; the span value (μg/m 3 ) is twice the Hg concentration correspond ing 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 con centration corresponding to the standard is about 1.5 μg/m 3 . Therefore, the span value could be set to either 2.0, 5.0, or 10.0 μg/m 3 . If the span value is set at 5.0 μg/m 3 , the required QA tests (i.e., da ily calibrations, linearity checks and system integrity checks) will be performed in the 0-5 μg/m 3 portion of the measurement scal e (as suggested by the commenter). Then, provided that the analyzer is capable of reading Hg concentratio ns 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 concentra tion data to be within 20 to 80% of the analyzer’s full-scale range.

Comment 16: Commenter 17821 opposes the requirement unde r 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 co al-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 other regulations, such as 40 CFR 60 a nd 40 CFR 75, require the span of a CO 2 monitor to be set at 20 percent. According to the comment er, the difference between these es tablished rules an d this proposal results in a conflict of span setti ngs which would require sources to ei ther 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 comply with all applicable 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 16: 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 thatall diluent gas monitors used to provide data under Subpart UUUUU must meet the requirements of 40 CFR part 75. Part 75 span values for CO 2 or O 2 monitors are therefore acceptable for Subpart UUUUU and there is no conflict between the135 regulations. Essentially all coal-fired util ity units already have certified part 75 CO 2 or O 2 monitors in place to meet Acid Rain Program requirements.

Comment 17: Commenters 17821 and 17881 object to the re quirement at section 7.2.5.1 to submit quarterly Hg monitoring data. Accord ing to the commenters, this rule is not based on a cap-and-trade program but on compliance with emission limitations and structured around excess emissions and deviation reporting. The commenters opine that under those types of compliance programs, there is no need for sources to submit hourly monitoring data, al ong with the other data th at is required by this section and later subsections. Commenter 17881 states that the EPA does not justify the requirement to electronically submit data under section 7.2.4.

Response to Comment 17: The EPA disagrees. These provisions provide extremely useful compliance oversight information regardless of whether compliance is market-based or emission limit based. With the existing structures built around Pa rt 75 reporting for these sources, reporting these data through the ECMPS mechanism is an efficient means of ensuri ng these records are maintained and available for review. Having an hourly record of unit operating time, measured emissions, and monitor outages provides added assurance the emission limits are being me t. Electronic audits can be performed to verify that the 30-day rolling average emission rates are being calculated correctly nationwide.

Comment 18: Commenter 18449 states that the Appendix A Performance Specification appears to replace PS-12A in this MACT but not in the other recently prepared MACT rules. According to the commenter, the previous PS-12A document had been created with considerable input from many sources and had undergone several revisions, has work ed 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 genera tion CEMS performance specs of th e PS series, and in particular combines PS-12A, PS-12B and Procedure 5. Accord ing 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 implemen ted as higher level functions of the DAS.

Response to Comment 18: The commenter is correct that Appendi x A of this rule contains the Hg CEMS and sorbent trap system requirements for Hg m onitoring for this rule; the rule does not reference or rely on PS-12A. In addition, Appendix A contains specific recordkeeping and reporting requirements for Hg monitoring data to support entry of the data into ECMPS.

In particular, the final rule requ ires 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 si nce been removed), and were desi gned to be implemented through ECMPS. PS 12B is referenced as it is essentially identical to the former Appendix K of Part 75, which was to be implemented through ECMPS under CAMR.

Comment 19: Commenter 18449 states that the requireme nt to report readings of either CO 2 of O 2 , on any constant basis is unnecessary. The commenter st ates that Hg monitors (or any other pollutant monitor) always report concentratio ns, either volumetrically (ppm, ppb) or m/v basis (ug/m3). Most CEMS are diluting and report on a wet basis. Accordi ng to the commenter, the emission limits are given as a mass emission limit per unit of plant activ ity, and the correction of the pollutant output concentration to a specific CO 2 or O 2 concentration does not in any wa y facilitate this calculation but adds unnecessary variables that will increase the uncer tainty and calculation error. The commenter states136 that corrected (CO 2 or O 2 ) pollutant concentrations are not used in any of the subsequent mass emissions calculations being proposed by the EPA fo r concentration based Hg analyzers.

The commenter states that stack velocities determin ed using pitot tubes or other measurement devices are not measured on a constant O 2 basis. Thus, according to the co mmenter, the stack volumes would need to be recalculated on a 7 percent O 2 basis in order to allow calcu lation of the mass emission rate. The commenter states that the so rbent 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, if the Hg CE MS intrinsically produces a concentration corrected to 7 percent CO 2 , these results must be back corrected to yield an as-is value to allow comparison. This is a needless step that complicates matters and introduces errors. The commenter states that most existing CEMS do not have an O 2 monitor. According to the commenter, it is unnecessary and punitive to require the addition of an O 2 monitor to a Hg CEM, whic h will reduce reliability and accuracy of the overall system. Acco rding to the commenter, all commer cially available dilution-based Hg CEMS analyzers are capable of directly determining their ow n dilution ratio by injecting Hg calibration gas at various points within th e system, which means that the use of CO 2 or O 2 as a dilution ratio check is not required.

Response to Comment 19: The commenter appears to be objecting to the use of diluent gas, flow rate, and other parametric measurements to convert Hg con centrations 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 intentio n 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 c ontain a diluent gas concentration term and some of them require corrections for the stack gas moisture cont ent. The commenter’s assertion that an O 2 monitor is required in incorrect; the final rule allows th e 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 needed in that case.

Comment 20: Commenter 18449 states that under the RA TA testing section 4.1.1.5 the procedure should require only that the CEMS and reference results be converted and compared to each other on a consistent basis. According to th e commenter, the reference method doe s not report on a diluents basis and Hg analyzers will not report on this basis, and thus any requirement to co rrect to some reference CO 2 (or O 2 ) basis needlessly complic ates the RA testing.

Response to Comment 20: The EPA agrees with the commenter that for the purposes of this rule, the Hg monitor should be assessed on the basis of how accurately it measures Hg concentrations. Therefore the RATAs must be done on a concentration basis, comparing the μg/m 3 readings from the reference method to the μg/m 3 readings from the monitor. This is cl early stated in sections 4.1.1.5.2 and 4.1.2.4 of Appendix A.

Comment 21: Commenter 19114 states that the EPA appears to have overlooked many of the issues that were resolved in the earlier CAMR rulemaking process. The commenter attached its 2005 CAMR comments to further address issues that had prev iously been addressed in the previous CAMR rulemaking. Some issues identifi ed by the commenter include:

 According to the commenter, the proposed rule doe s 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 stat es is similar to how Part 75 handles negative137 data. According to the commenter, if instrument drift and allowable calibration error tolerances are included, it is possible to be within the an alysis 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 betw een the two rules.

 Commenter recommends an additional option be available for measuring moisture. According to the commenter, if the stack is saturated, a source should be able to use temperature, absolute pressure, and a psychrometric chart to measure mo isture. 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. Accordi ng to the commenter, during periods when the stack is not saturated, default factors listed in the rule could be used.

Response to Comment 21: Regarding the three issues raised by the commenter:

1. This issue can be handled through the ECMPS Reporting Instructions. There is a Method of Determination Code (MODC) in Part 75 (i.e., M ODC “21”in §75.57, Table 4a) that addresses the handling of negative values. The EPA will instruct sources to use MODC 21 and report zero Hg concentration when a negative value is r ead by 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 de finition of “zero air materi al” in section 72.2 In view of the confusion of terms and incorr ect rule citations, EPA is unable to provide a meaningful response to this comment.

3. The final rule allows the “additional option” for measuring moisture described by the commenter. In cases where the Hg emissions calculations require corrections for moisture, affected sources must account for the stack gas moisture content in acco rdance with 40 CFR 75.11. The affected source may either: (a) install and certify a continuous moisture monitoring system; (b) use an applicable fuelspecific default moisture value prov ided 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 psychrometri c 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 measured on the same basis, asserts the commenter, a stack moisture monitoring system would not be required.

Response to Comment 22: The commenter’s statement is true, but the EPA sees no need to make any changes to the rule text. Secti on 3.2.3.1 of Appendix A clearly states that “in some cases” stack gas moisture content must be considered. The need for mo isture 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 m easurement basis (wet or dry) of the pollutant and diluent gas species. Therefore, it will be obvious to the affect ed sources if and when moisture corrections are needed.

Comment 23: Commenter 17881 states that the requirement s of section 63.10010 for main and bypass stacks conflict directly with those in Appendix A (section 2.4.2 of Appe ndix A allows installation of a138 CEMS on the main stack and the use of maximum pot ential Hg concentration whenever the bypass stack is utilized). The commenter states that EGUs with multiple stack or duct configurations are addressed in section 63.10010(a)(5). The commenter appreciates the flexibility afford ed in this paragraph but opines that the EPA should specify the method used to merg e the multiple stacks or duct values into a single value which could then be compared to the emission limit. According to the commenter, in the absence of such guidance, it could be construed that each monitoring location must independently show compliance with the applicable EGU emission limits, and this could resu lt in situations of seeming noncompliance. The commenter questions whether, for ex ample, if Hg monitoring is conducted in A and B ducts associated with a single E GU and one duct monitor shows a comp liance 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 flowweighted manner, etc.

Response to Comment 23: For a unit with multiple parallel control devices with multiple stacks or ducts where all stacks or ducts are monitored, sect ion 63.10010(a)(6) of the final rule states that the pollutant emission rate for the unit must be calcu lated, weighted by stack ga s volumetric flow rate, where the weighted average emission rate is calculated according to section 63.10010(a)(6).

Comment 24: Commenter 17881 states that span values for auxiliary measurement systems (i.e., flow rate, diluent gas and moisture monitors) in section 3.2.3.3 contain undefined terms such as maximum potential flow rate and maximum potential concentration. The commenter notes that these provisions are on the surface similar to those found in 40 CFR part 75, albeit without mu ch of the detail necessary to implement the provisions (i.e., how is the maxi mum potential flow rate or maximum potential concentration determined). questions the commente r, at a minimum, the span, range and maximum potential flow rate/concentration provisions of 40 CFR part 75, A ppendix A should be allowed, and it may be prudent to abandon the details contained in section 3.2.3.3 and simply refer to the associated 40 CFR part 75 provisions.

Response to Comment 24 : The EPA agrees with the commenter’s recommendation to dispense with the details in section 3.2.3. The final rule simply requires all of the additi onal monitoring systems needed to convert Hg concentrations to the un its of the standards to meet the requirements of 40 CFR part 75. This approach is appropriate, since ECMPS will be used to receive and process the CEMS data that are used to assess compliance with the Hg emission limits under subpart UUUUU.

Comment 25: Commenter 17881 states that the cycle time test provisions of part 75, Appendix A, section 6.4 allow a change of < 6% of the average reading over a 6-minute period to define a stable reading when conducting the cycle time test and that this provision should also be allowed in section 4.1.1.4 of Appendix A.

Response to Comment 25: In the final rule, the additional text suggested by the commenter has been added to the cycle time test proce dure in section 4.1.1.4 of Appendix A.

Comment 26: Commenter 18449 states that span ranges wi ll 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 sp an 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 util ity MACT spans should be fixed at 5, 10, 20, and 40 ug/m3. (Commenter 18449 states that Cement MACT spans s hould not be available in increments of 10 ug but should be spaced much farther apart, such as 100, 180, 260, etc. Commenter 18449 states the wording should be clarified so that users can choose such ranges, rather than forced to nearest multiple of 10.)

Commenter 18449 states that CAMR also required Hg calibration gases be traceable to NIST, however, NIST at that time had no idea how to certify Hg gene rators or calibration gase s and had to develop the methodology, procedure, and processes, with no prot ocols in place until well af ter the start of the program, so that the EPA was forced to defer the NIST traceability requirem ent for a year. Commenter 18449 notes that the EPA and NIST still have a number of current issues, for which NIST will require external funding, and identifie d these issues as follows:

1. Measure and certify lower level elemental concentrations. According to the commenter, currently NIST can only certify con centrations down to 0.5 μ g/m3, and this value has a very high uncertainty of 6.1 percent (Prob_95 percent). The commen ter states that NIST will have to be able to certify points at 20-30 percent of the lowest span value th at the EPA envisions; for example, a 0.25 μ g/m3 certified concentration would be needed for lower span ranges.

2. Measure and certify high elemen tal concentrations (100 to 260 μ g/m3). The commenter states that this is required for the Cement MACT rather than this ru le, but it’s included here since it has to be done.

3. Measure mercury chloride generators. According to the commenter, currently there is a 9 percent discrepancy between NIST traceable elemental calib rators and NIST traceable ionic evaporative calibrators, and the reason for this is unknown. The commenter states that if NIST could accurately measure the output of evaporative calibrators, this difference could be expl ained. According to the commenter, the current Interim Oxidi zed Protocol deems a generator to be certified if all inputs are NIST traceable. The commenter states that this appro ach can remain, but the ability of NIST to confirm the output of even a single test ionic generator would increase confid ence that the various types of generators all yield identi cal output concentrations.

4. Improve “routine” elemental certifications. The comm enter states that certi fications of elemental calibrators by NIST ove r the range 0.5 to 38 μ g/m3 have been “routine” for several years, but it recently took three separate attempts with NIST and over one y ear for the commenter to have a pair of calibrators correctly certified over this range. Th e commenter states that the high levels were correct, but the low concentrations were off by up to 12 percent, and if legislation been in place, this delay would have caused enormous problems.

5. The EPA Interim Traceability Protocols currently state: “For CEMS applications, this protocol applies only to Hg monitoring system span values greater than or equal to 5.0 micrograms per cubic meter ( μ g/m3)” According to the commenter, this must be changed if the EPA envisions span values of less than 5 μ g/m3 will be required under the new legislation. The commenter states that rovided that NIST can provide lower uncertainties for lower concentrat ions for elemental generators, the commenter does not see any reason why the interim pr otocols will not work at the lowe r concentrations needed for a 2
μ g/m3 span range.

6. Vapor pressure of mercury. The commenter states th at there is a 7 – 9 percent difference between two proposed mercury vapor equations. According to the co mmenter, these equations are used to predict the output concentration of saturated va por 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 NIST Gas Metrology Group, and the other, recently proposed by another group within NIST (Boulder Colorado) predicts a merc ury concentration in saturated va por 7 to 9 percent higher but as viewed as “theoretically correct ”. The commenter states that a lthough the EPA’s Interim Elemental Mercury Traceability Protocol neatly sidesteps this i ssue, 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 va lues should be specified in PS-12A or Appendix A; however, in the final rule, the EPA has revised Appendix A, which includes the Hg monitoring requirements specific to this rule, to enable greater flexibility when identifying an appropriate span value. The A ppendix A requirements provide for identifying a potential span value (based on a level two times the Hg concentration e quivalent 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, th e EPA disagrees that NIST 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 elementa l Hg concentrations less than 0.5 μg/m 3 are required by the final rule. The EPA does, however, encourage the development and use of lower span ranges (that meet Appendix A), wher e appropriate. If a span value is chosen that requires the use of certified elemental Hg concentrations less than 0.5 μg/m 3 , NIST would be capable of conducting certifications at this level, though as far as the EPA is aware NIST has not yet c onducted certifications at these low levels. Regarding Item 2, the EPA agrees that higher level elemen tal Hg calibration gas concentrations are needed for potential future regulatory requirements independe nt of this rule. The EPA has worked with NIST to expand the range of NIST elemental Hg reference concentrations that can be certified and certified elemental Hg concentrations ranging from 0.5 μg/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 chlori de generators is desired; however, in the absence of this capability, the current Interim Traceability Protocol for certify ing oxidized Hg gas generators is accepted as the appropriate methodology for establis hing NIST traceability for mercur ic chloride. Moreover, this approach reflects significant effort on the part of the EPA, the CEMS vendor community, and affected sources to examine the calibration ge nerator traceability issues, and de vise an agreed upon approach for addressing those issues. For Item 4, it is the EP A’s understanding that NIST currently performs elemental Hg gas generator certifi cations on a routine basis and the EP A 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 by this rule and as a result, changes to the Interim Traceability Protocol s are not necessary for implementation of the rule. The EPA does agree with the commenter that the EPA Interim Traceab ility Protocols are suitab le for lower elemental Hg concentrations such as those associated with a 2 μ g/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 μ g/m 3 , so the EPA will consider modifying the protocol at a later time. Finally, regarding Item 6, while the EPA is aware that there is a 7 to 9% difference between two Hg vapor equations used by the scientific community, the EPA’s application of NIST traceabili ty for elemental Hg is empirically based upon an unbroken chain of comparisons anchored to an a ccepted, NIST elemental reference gas which is independent of these theore tical Hg vapor equations.141 5A07a - Testing/Monitoring: Application of PM CEMS

Commenters : 17197, 17383, 17402, 17621, 17623, 17638, 17655, 17675, 17677, 17681, 17689, 17696, 17702, 17704, 17705, 17711, 17714, 17716, 17725, 17728, 17729, 17730, 17737, 17740, 17747, 17752, 17754, 17756, 17758, 17761, 17774, 17775, 17790, 17795, 17796, 17798, 17800, 17801, 17808, 17812, 17813, 17818, 17820, 17821, 17868, 17871, 17881, 17886, 17912, 17913, 17914, 17975, 18014, 18428, 18443, 18447, 18498, 18831, 18935, 18963, 19033, 19114, 19120, 19121, 19536, 19537, 19538, 18023

1. Support of use of PM CEMS during startup and shutdown.

Comment 1: Commenter 17975 supports the proposed requi rement to use PM CEMS on EGUs that elect to comply with the PM filte rable limit as a surrogate for non-Hg metals because PM CEMS are an EPA approved monitoring method, and in use at anincreasing 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, s hutdown, maintenance, and malfunctions, when PM emissions may be at their peak. The commenter refers to an “expert’s” conversations w ith several PM CEMS vendors that indicate these monitors can be cal ibrated to accurately measure PM at very high concentrations that occur during startup and shutdown.

Response to Comment 1: The final rule clarifies that the operating limit monitoring for the PM and HAP metals emission limits requires use of a PM CPMS, not PM CEMS, and work practice standards that include operation of monito ring, not numerical emissions limits , during periods of startup or shutdown. The final rule also does provide for the us e of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

2. Recommendations to use PM CEMS as indicator/CAM.

Comment 2: Multiple commenters (17705, 17725, 17716, 17820, 17886, 18014, 18498) suggest that the final rule use PM CEMS data as an indicator of PM control performance, but not to enforce a numeric PM limit, and that altern atively, sources could also demons trate a reasonable assurance of compliance based on opacity or parametric monito ring as the EPA has already proposed under other rules.

Comment 3: Several commenters (17623, 17638, 17681, 17676, 17775, 17886) suggest using PM CEMS within a MACT monito ring program modeled after the part 64 CAM program.

Comment 4: Several commenters (17402, 17716, 17737, 17775, 17886) believe current PM CEMS technology is useful as a compliance assurance m onitoring tool that can trigger requirements for investigation and corrective action.

Comment 5: Several commenters (17402, 17681, 17716, 17737, 17775) note successful implementation the CAM rule under 40 CFR part 64 and request that the final rule adop t this approach for continuous monitoring. Commenter 17402 suggests that CAM plan s could include opacity monitoring, a sitespecific utility MACT compliance pl an, and periodic stack testing.

Response to Comments 2 - 5: The final rule requires the use of a PM CPMS for an operational limit and does not enforce a numeric PM limit when this monitoring approach is used. In the final rule facilities would be allowed to petition the Administra tor 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 clarification on establishment of PM CEMS operating limits.

Comment 6 : Commenter 17729 requests clarif ication that the ru le requires using the filterable PM measurement to set an ongoing 30-day rolling aver age operational limit with compliance based on a filterable PM CEMS.

Response to Comment 6: The final rule requires the use of a PM CPMS for an operational limit and does not enforce a numeric PM limit. The PM CPMS is required to report measurements in raw data output from the monitor and not a correlation to manual filterable PM measurements. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble fo r further discussion).

Comment 7: Commenter 17881 states that it is not clear if section 63.10011(b)(3) ap plies to units with PM CEMS. Commenter notes that for a unit complying via the use of PM CEMS, it is not clear if “nonHg HAP metals” refers to the aggregate of all re gulated HAP metals or each of the individual HAP metals. According to the commenter, it seems like this provision must be based on all metals in aggregate, or it would be impractical to implement.

Response to Comment 7: The final rule requires the use of a PM CPMS for an operational limit and does not enforce a numeric PM limit. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion). The so urce has the option to measure non-Hg HAP metals with a reference method each quarter. The monitoring and testing that is requi red will depend on which emission limit the source elects.

Comment 8: Several commenters (17730, 17868, 18023) state that proposed reliance on total PM as a surrogate for the non-Hg HAP metals, and the use of the PM CEMS to conduct performance testing and measure ongoing compliance is poorly defined. Commen ters (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 ini tial performance test, they must de velop a filterable PM emission limit based on a compliant stack test us ing Method 5 and Method 202, but th e proposal fails to provide any further explanation of how sources are supposed to derive the filterable PM limit, or whether or not sources are also required to comp ly 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 specifie d in the proposal. The commenter characterizes this portio n of the proposal as “essentially esta blishing a surrogate for measuring a surrogate” and “simply nonsensical.” The commenter be lieves it is unreasonabl e for the EPA to seek comment on such a poorly defined proposal, and the comm enter believes that if the agency continues to pursue the total PM standard as a surrogate for n on-Hg HAP metals, the agency should make clear the methodology for establishing the filterable PM limit and re-propose the rule for public comment because the commenter cannot effectively provid e 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 establishe d 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 withthe filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 9: Several commenters (17754, 17800,18963, 18023) stat e that the owner/operator must “[m]aintain the PM concentration (mg/dscm) at or below the highest1-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 th e operating limit for PM should be based on the average of the PM filterable resu lts of the three Method 5 performance test runs, whereas Table 4 provides that the PM limit shall be the highest 1-hour average m easured during the most recent performance test. According to th e commenters, these two relevant provisions appear to reflect inconsistent analyses and complian ce demonstration periods and therefor e should be clarified in order to avoid potential confusion, misinter pretation, and/or inconsistent a pplication. The commenters request that the proposed rule be clar ified to expressly provide that the operating limit for demonstrating continuous compliance with the emission standard for total PM shall be based on the highest 1- hour average measured during the most recent perf ormance test, in accordance with Table 4 of the proposed rule. The commenters state that consistent wi th this approach, if the total PM emissions from an affected EGU exceed the previously-est ablished operating limit during any period, the owner/operator of such unit would have the optio n of conducting another performance test, and the highest average value measured during such test w ould become the new applicable operating limit for the relevant unit.

Response to Comment 9: Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrat e continuous compliance, you must install a PM CPMS and establish the operating limit during the in itial compliance test fo r filterable PM, total nonmercury HAP metals, or individual non-mercury HAP metals (or HAP metals inclusive of mercury for liquid oil-fired units). The operating limit for demons trating continuous shall be based on the highest 1- hour average measured during the mo st recent performance test. If you use a PM CPMS and associated operating limit, you must conduct the applicable Me thod 5 or Method 29 testonce annually and reestablish the operating limit during each performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emissi on limit if the source elects to use this approach (see the final preamble fo r further discussion).

Comment 10: Commenter 17871 states that the EPA has fa iled to demonstrate that a functional relationship between filterable particulates and condensable particul ates in EGUs. According to the commenter, this approach becomes unworkable whenone 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 technolog ies used for removal of acid gases are primarily those that are also used for FGD” (76 FR 25023). Th e commenter states that SO 2 would be measured with a CEMS certified and operated in accordance with part 75. According to the commenter, even though proven technology and quality assured emissi on 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 ra te measured during the most recent performance test. Commenters 17871 and 17740 state that by setting up comp liance in this manner, the emission standard becomes the basis for an operating limit, which in turnbecomes 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 imposes two MACT standards on sources.

Response to Comment 10: The comments are inapplicable, as the final rule no longer contains a condensable PM emissions limit and, for those so urce owners or operators who choose to use SO 2 CEMS, no operating limit ex ists and no parameter monitoring is required.

Comment 11: Commenter 17623 states that the total PM stan dard is unclear and impracticable because it will be difficult for sources to plan for change s to the limits resulting from performance testing. According to the commenter, the PM limit of 0.030 lb /MMBtu for existing sources would be adjusted downward based on the PM emission rate measured by the reference method during each periodic performance test. The commenter be lieves that there are two possibl e interpretations of the proposed rule that would result in this downward adjustment.

1. According to the commenter, one interpretation would require the PM limit to be adjusted down based on the proportion of Total PM emissions that are condensable. The commenter states that if, for example, 50 percent of the to tal PM emissions are condensable at a particular unit, then the applicable PM CEMS limit for that un it would be reduced to 0.015 lb/MMBtu. 2. According to the commenter, the ot her interpretation would require the PM limit to be set at the actual filterable PM emissions rate measured during the initial and subsequent PM performance tests conducted for the unit. The commenter states that under either approach, the conversion of the total PM numeric rate limit into a filterable PM standard that a PM CEMS can monitor will require sources to readjust their compliance level after each performance test.

Response to Comment 11: Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrat e continuous compliance, you must install a PM CPMS and establish the operating limit during the in itial compliance test fo r filterable PM, total nonmercury HAP metals, or individual non-mercury HAP metals (or HAP metals inclusive of mercury for liquid oil-fired units). The operating limit for demons trating continuous shall be based on the highest 1- hour average measured during the mo st recent performance test. If you use a PM CPMS and associated operating limit, you must conduct the applicable Me thod 5 or Method 29 testonce annually and reestablish the operating limit during each performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emissi on limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 12: Commenter 17795 states that there is conflic ting language in the pr oposal. According to the commenter, pages 25029-25030 indicat e that ESP and fabric filter pa rameter monitoring is required for all units not using HCl CEMS, but the language from page 25031 stat es that parameter monitoring is required only if units are not using PM CEMS. Accordi ng to the commenter, fabric filter BLDS and ESP voltage limit monitoring requirement s should apply only to units that do not use PM CEMS as stated on page 25031. The commenter believes this was the EPA’s intent, as there is no ju stification or further assurance of compliance for the monitoring of par ticulate 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 fa bric filter BLDS readings an operational limit if a unit uses a PM CEMS to demonstrate compliance.145 Response to Comment 12: Control equipment parameters are not m onitored under the fina l rule, so this concern is moot.

4. Concerns with using PM CEMS data to determine compliance with non-Hg metals standard.

Comment 13: Commenter 17621 states that the merits of including condensable PM in the total PM limit are difficult to evaluate, as no test data are available for the ex act condensable PM method that is required for compliance with the proposed MACT lim its. The commenter states that the ICR required condensable PM to be measured using OTM-28, whic h method was changed significantly before it was promulgated in 2010 as revised Method 202. According to the commenter, most ICR test contractors used OTM-28, a few used the original Method 202, and because none of the ICR tests used revised Method 202, the conclusions of EPRI’s evaluation of condensable PM method usefulness are uncertain. According to the commenter, adding a condensable PM measurement to the filterable PM sampling train increases the total variability and reduces the se nsitivity of the combined measurement system. The commenter states that a recent field study conducted by American Electric Power (AEP) and EPRI found that Method 202 (condensable PM) had much highe r variability than Met hod 5 (filterable PM) for replicate test runs (EPRI, 2011) and that in the ICR Part III tests at coal-fired EGUs, the relative standard deviations (RSDs) of conde nsable PM test series averaged s lightly 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 measuremen t adds uncertainty to the total.

Moreover, according to the commenter, the accuracyof the new Method 202 has not been demonstrated adequately and requires additional research. The commenter states th at laboratory studies conducted by EPRI pointed to a potential negative bias in OTM-28, which did not effectively capture SO 3 (EPRI, 2009)., and that only about half of the SO 3 introduced into the sampling train was captured. According to the commenter, this finding indicates that Met hod 202 may not be accurate under flue gas conditions that are expected to be increasingly prevalent in power plants as wet FGD systems (which tend to produce SO 3 ) are added.

The commenter states that a total PM limit is probl ematic for compliance monitoring, as continuous PM monitors measure only filterable PM. According to the commenter, since condensable PM emissions are a product of the coal sulfur content and other factors (e.g., ash properties, SCR SO 2 oxidation rate), it is not clear how a power plant would determine complian ce 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 w ith total PM limits will depend on the percentage of total PM that is condensable PM and how variable the ratio of f ilterable PM to condensable PM is over time. Commenter states that(in document; Figure 2-2 is hist ogram of condensable PM as a percentage of total PM: Part III ICR Coal-fired EGUs) the fraction of total PM that is condensable PM varies from under 1 percent to over 99 percent across the coal-fired EGUs tested in the ICR. According to the commenter, the ICR database does not contai n sufficient historical c ondensable PM data to determine how much condensable PM emissi ons will change at a unit over time.

Finally, the commenter states that EPRI’s study has implications for howrepresentative the ICR data are of industry emissions, as well as for future performance testing. The commenter states that the EPA based the MACT floor for total PM on the lowest te st series for each EGU, regardless of the method used to measure filterable PM (Method 5, Method 29, or OTM-27). According to the commenter, as many of the lowest ICR emissions are from Method 29 tests run at 320 °F, those results will not be representative of tests made using Method 5 at 250 °F , and as a result, there is considerable uncertainty146 regarding the true emissions of filterable PM from the power industry. The commenter states that the compliance method for filterable PM specified in the proposed rule is Method 5, while the ICR test data include filterable PM results from Methods 5, 29, and OTM-27. According to the commenter, to 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 ther e should be a requirement to use nonreactive filters.

Comment 14: Commenter 18429 states that the unit-by-unit, single test approach in setting a MACT limit proposed by the EPA is inappropriate. The commen ter notes that an exampl e of the difficulty in meeting a PM operational limit is one of the commen ter’s units equipped with a wet scrubber, SCR, and ESP for emissions controls. According to the comme nter, when following the stack test that would establish the filterable PM operational limit, the un it’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 ov er 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 cat egory-wide, filterable PM limit that is achievable under the variety of conditions that utility units experience. The commenter further notes the comments submitted by EPRI in this docket provide detailed analysis justifying the use of filterable PM as an adequate surrogate for all non-Hg metals. The comment er states that among the key conclusions are that filterable PM is correlated to emissions of partic ulate-phase metals (e.g., chromium) and there is a statistically significant correlation with metals that ar e volatile at stack gas temperature, particularly Hg and selenium.

Comment 15: Commenter 17197 believes the proposed PM CEMS operating limit determination method is unworkable, arbitrary, likely overly restrictive, and non -representative. The commenter believes the better solution is replacing the proposed total PM limit with a filterable-only PM limit for non-Hg HAP metals using PM CEMS, however the commenter offers an alternative. Commenter recommends instead that the surrogate PM CEMS operating limit (filterable PM) be established by using the simultaneous EPA Method 5 and Method 202 stack te sting results to establ ish the EGU’s filterableto-total PM ratio. According to the commenter, the PM CEMS operating limit (filterable PM) would be appropriately set by adjusting the total PM limits (0.030 lb/MMB tu or 0.30 lb/MWh) using the filterable-to-total PM percentage established duri ng the three 1-hour test r un performance testing. The commenter states that for example, if the measured filterable-to-total PM factor was 0.5, the PM CEMS operating limits (filterable PM) would be set at 50 pe rcent of the total PM Limits (0.015 lb/MMBtu or 0.15 lb/MWh). According to the commenter, setting th e PM CEMS operating limit using this alternate methodology is more representative because it utilizes all three performance test runs and not just the highest 1-hour average measured EPA Method 5 rate . The commenter asserts that this methodology is less dependent on short-term PM control system pe rformance, since it is based on the established filterable-to-total PM ratio, and is less arbitrary since the resulting PM CEMS operating limits have some equivalence to the underlying total PM limit.

Comment 16: Several commenters (17623, 17677, 17681, 17730, 17775, 18023) believe that it is problematic to use PM CEMS data to determine compliance with a total PM limit because PM CEMS only measure filterable particulate. Commenters (17623, 17775) states that the technology used to establish the total PM limit and to perform periodic stack tests that re-set the “floating” PM CEMS operating limit use significantly different technol ogy. 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 con cerned that the PM CEMS operating limit appears147 to be an enforceable requirement treated as equivalentto the total PM limit despite the fact that the PM CEMS limit reflects only a fraction of the total non- Hg metals being emitted during the performance test. Commenter 17677 believes that setting an enfor ceable limit on a surrogate seems refutable during enforcement proceedings. Several commenters (17623, 17677, 17681) suggest requiring another stack test for total PM within 60 da ys of exceeding the PM CEMS operating limit rather than deeming the source out of compliance with the HAP emissions limit. Commenters (17676, 18023) believe that annual compliance tests are sufficient to ensure compliance.

Comment 17: Several commenters (17689, 17704, 17813, 18014) st ate that the proposed PM total approach is unworkable for several reasons. Accord ing to the commenters, Me thods 5 and 202 would be utilized to determine the condensab le and filterable portions of PM total, with PM CEMS measurements used to set unit operating limits af terwards, but Method 5 does not and cannot account for variations in PM filterable actual levels over a range of unit oper ating levels, including startup and shutdown, that a PM CEMS would measure, so, in effect, Method 5 measurements when compared to PM CEMS measurements over full unit operating conditions is not appropriate. Several commenters (17689, 17702, 17704, 17813) state that the PM standard should be based on a PM filterable limit only.

Comment 18: Commenter 17737 states that PM CEMS provide an indirect measure by “correlating” the monitor’s response to short term stack tests (e.g., Method 5 tests) condu cted over a range of concentrations that must be sufficient to include the level of the applicable emission standard. Commenter provides an analysis by UAR G that indicates that a PM CEMS meeting the criteria in PS 11 can produce responses that differ sign ificantly (on the order of 25 percen t) from what would be obtained with Method 5. (See, e.g., UARG Comments , EPA-HQ-OAR-2002-0058-2880 at 51-54; EPA-HQOAR- 2005-0031-0246, at 3-10). According to the commenter, for example, if the filterable PM limit is set at 0.030 lb/MMBtu and the Meth od 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 dem onstrated false exceedance of the PM limit where the true PM level should ha ve be in compliance.

Response to Comments 13 - 18: The final rule no longer requires monitoring with a PM CEMS. Under the final rule, you may elect to comply with an op tional operating limit for PM. If you use this method to demonstrate continuous compliance, you must instal l 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 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 19: Commenter 17737 states that they conduct Me thod 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 th at are certain to occur. According to the commenter, this is likely because the three-run average of a stack test conducted during 1 day at constant operating conditions, essentially represents a single point measuremen t, which by its very nature cannot provide any indication of variability. Several commenters (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 re sults), and utilities wo uld 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 19: Under the final rule sources are al lowed to establish different operating limits monitored with a PM CPMS if they believe ther e is variability due to va rying load conditions. The final rule no longer requires monitoring with a PM CE MS. 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 pr eamble for further discussion).

Comment 20: Commenter 17711 states that PM CEMS m easure only filterable PM yet the EPA proposes that the operating limit for facilities us ing PM CEMS is the highest 1-hour average concentration in mg/dscm measured during the mo st recent performance test. According to the commenter, the EPA is setting an artificially low PM standard for units using PM CEMS. The commenter states that the compliance method shoul d match the standard; the EPA should either set filterable PM emission limits or establish more appr opriate operating limits for sources using PM CEMS (e.g., the total PM limit minus the amount of condens able PM measured during the last performance test).

Response to Comment 20: Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrat e continuous compliance, you must install a PM CPMS and establish the operating limit during the ini tial compliance test for f ilterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals inclus ive of Hg for liquid oil-fired units). The operating limit for demonstrating cont inuous shall be based on th e 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 annua lly 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 provi de for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 21: Commenter 19120 states that the establishm ent of an operating limit makes the 0.030 lb/MMBtu limit on total PM arbitrar y. According to the commenter, for example, if the emissions rate during stack testing for total PM is well below 0.030, exceedance of the filterable PM operating limit would not be an indication that the actual emi ssions limit of 0.030 lb/MMBtu was exceeded or even approached. The commenter recommends that the EPA base the operating limit on a more representative value than simply basing it on th e value achieved during the stack te st and notes that while section 63.10011(d) indicates that the operating limit will be base d on the average of the PM filterable results of the three Method 5 performance test results, Table 4 indicates that the opera ting limit will be based on the highest 1-hr average measured during the test.

Response to Comment 21: Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrat e continuous compliance, you must install a PM CPMS and establish the operating limit during the ini tial compliance test for f ilterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals inclus ive of Hg for liquid oil-fired units). Under the final rule source s are allowed to establish differentoperating limits monitored with a PM CPMS if they believe there is variability due to va rying 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 preamble for further discussion).

Comment 22: Several commenters (17402, 17775, 17790) support us e of PM as a surrogate for non-Hg HAP metals. Other commenters (17402, 17675, 17716) requ est that the agency not require regulated units to install and use PM CEMS as the cont inuous compliance determination method. Several commenters (17402, 17716, 17775) support inclusion of PM CEMS as one option among others for an appropriate filterable PM limit, provided the EPA has considered and addressed all of the issues associated with use of PM CEMS for that purpos e. Commenter 17402 states that including PM CEMS as an option would be consistentwith recent revisions to NSPS Subpart Da. However, the following commenters do not believe th at the proposal accounts for the following issues relevant to the use of PM CEMS as a direct indicator of compli ance following periodic performance tests:

1. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17737, 17752, 17775, 17790, 17868, 18023) note the inaccuracy of PM CEMS at low concentrations; 2. Multiple commenters (17402, 17716, 17728, 17737, 17752, 17775, 17790, 17868, 17886, 18014, 18023) state there is a lack of data correlating PM CEMS respons e with actual emissions during startup and shutdown and across load ranges. Commenters (17775, 17737) state that the proposal’s explanations (that the proposed lim its were achievable during periods of startup and shutdown based on use of a 30-day averaging period and assumptions regarding the use of cleaner fuels) were not substantiated with data; 3. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17775, 17868, 18023) are concerned about the PM CEMS a llowed measurement error (i.e., hi gh degree of uncertainty within PS-11 tolerance interval); 4. Multiple commenters (17402, 17716, 17728, 17737, 17752, 17775, 18023) note the differences in measurement methods or conditions th at can affect monitor calibration; 5. Multiple commenters (17402, 17675, 17681, 17696, 17716, 17728, 17775, 17790, 17868, 18023) question the achievability of PS 11 performance cr iteria 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 cannotpass PS-11 criteria; 6. Commenters 17737 and 17775 claim there is a lack of compliance provisions allowing the operational flexibility necessary to develop strong PM CEMS correlations to the reference method 7. Several commenters (17696, 17737, 17752, 17775, 18023) ques tion the long-term re liability 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 PS11 testing; 9. Commenter 18023 states there is a lack of NIST traceable PM daily calibration standards: 10. Commenters 18023 and 17790 state the use of PM CEMS is cumbersome, expensive, and includes highly variable calibration procedures.

Response to Comment 22: PM CEMS are no longer required unde r 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 establis h the operating limit duri ng 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 op erating 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 c onduct 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 need150 to meet the requirements for a PM CEMS under PS 11. Th e 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 pream ble for further discussion).

Comment 23: Commenter 17737 states that the EPA should establish a separate stan dard for periods of startup and shutdown. According to the commenter, however, if the EPA promulgates a rule that requires use of PM CEMS as a compliance method during periods of startup and shutdown, the EPA cannot simply assume that averaging time or differ ences in fuel will compensate for these period.

Response to Comment 23: The comment is moot, as the rule no longer has emissions limits applicable during periods of startup or shutdown.

Comment 24: Commenter 17800 states that the EPA should re vise 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 workab le because the EPA does not clearly describe how compliance would be determined or how the proposed site-specific limit would be es tablished or how the limit would apply. Commenter is opposed to a site-specific limit. The commenter states th at a PM standard should apply consistently for all affected sources and compliance must be establ ished that accurately represents the actual emissions from the source and test me thods should be clarified and not combine different testing and measurement components.

Response to Comment 24: PM CEMS are no longer required unde r 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 establis h the operating limit duri ng 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 op erating 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 c onduct 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. Th e 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 pream ble for further discussion).

The establishment of an operational li mit is described in the final rule and is applied the same for all sources, thus representing the operation of control equipment for all affected sources.

Comment 25: Commenter 17820 states that the EPA should designate filterable PM and not total PM as a surrogate for the non-Hg metals standards. Acco rding to the commenter, however, if total PM is retained the EPA should allow an a lternative option to determine a unit- specific filterab le PM limit and the EPA should extend the option to us e filterable PM as a surrogate for metals to oil units and to allow compliance demonstrations through the use of CEMS.

Response to Comment 25: The rule has a filterable, not total, PM emissions limit.

Comment 26: Commenters 17812 and 17821 state that given the variability in testing and coal properties, the requirement to maintain PM concen tration at or below the highest 1-hour average measured during the most recent performance test as proposed imposes a de facto unjustified reduction in emission limit on those units using a PM CEMS. Commenter 17821 recommends deleting the requirement in its entirety.151 Response to Comment 26: Under the final rule sources are al lowed to establish different operating limits monitored with a PM CPMS if they believe ther e is variability due to va rying load conditions. The final rule no longer requires monitoring with a PM CE MS. 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 prea mble for further discussion).

5. Compliance costs if PM CEMS are not appr opriate monitors for non-Hg HAP metals.

Comment 27: Commenters 17728 and 17775 state that if PM CEMS are not a realistic option for monitoring PM as a surrogate, then the EPA must rec onsider its assumptions thatmost sources will opt to use PM as a surrogate, and should seriously cons ider the reasonableness a nd cost of the non-Hg HAP metals testing option, including the impact of control device parametric monitoring options.

Response to Comment 27: PM CEMS are no longer required unde r 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 establis h the operating limit duri ng 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-fire d 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 pr eamble for further discussion).

6. Concerns about the commercial readiness of PM CEMS.

Comment 28: Commenter 17818 states that itis their understanding thatcontinuous PM monitoring systems (PM CEMS) have been in operation for a numbe r of years in other countries, and that a number of PM monitors have been in operation in the U.S. for several years as a re sult of applicable state requirements. According to the commenter, there ar e a number of commercia lly available continuous PM monitoring technologies that are capable of meeting the EPA re quirements. The commenter states that information from the ICAC indi cates that they have prepared a guidance document to help potential purchasers of PM CEMS to prepare a bid specifica tion for the solicitation of bids from particulate monitor suppliers. Commenter agrees with the EPA th at PM CEMS are commercially available and are reasonable monitoring options for coal - and oil-fired units. It is the commenter’s opinion that PM CEMS are appropriate systems for monitoring compliance with the applicable provisions of the proposed rule.

Response to Comment 28: See response to comment 37.

Comment 29: Commenter 17796 supports the use of Hg CEMS but does not believe the use of PM CEMS is supportable. According to the commenter, the EPA supports the “feasib ility” 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. Accord ing 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 & Relate d Material portion of the Docket for the PM CEMS program and in over 3000 documents only found f our that clearly dealt with PM CEMS, from two facilities in Ohio and that simply reported th e hourly measurements. The docket should show more examples of facilities using PM CEMS and also th e QA steps necessary for good data. According to the commenter, the docket also needs to show that the PM CEMS equipment will be readily available and also be able to be installed and troubleshot in a timely manner. Th e 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 agen cies, that such informa tion can be relied upon to enforce in case of non-compliance.

Commenter 17796 also notes that th e EPA’s proposal to use CEMS as an option for PM compliance only affects the filterable portion of the PM and relies on the concep t that the condensable portion will be addressed though the demonstration of “equivalenc y” between the CEMS and the stack testing during the initial compliance tests. Accord ing to the commenter this is a ve ry tenuous position to rely upon to assure compliance with the total PM limits. The commenter notes that the New York SDEC has a longstanding policy of requiring that the condensable portion of PM emissions be addressed in the permitting process since this portion of the PM emissions are critical for the mitigation of health effects associated with PM 2.5 . Thus, the commenter believes the PM CEMS approach is not adequately rigorous to assure enforceability of the limits, nor allows fo r 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 companies in the U.S. have now installed or are planning to install PM CEMs. The commenter questions how many different type s of EGUs have PM CEMS (broken down by unit configuration and fuel type ). Finally the commenter notes that the costs of PM CEMS are equivalent to installing a Hg CEMS which is also required unless the source owner goes with sorbent traps which are estimated to have less upfront co sts but higher annualized costs.

Response to Comment 29: Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrat e continuous compliance, you must install a PM CPMS and establish the operating limit during the ini tial compliance test for f ilterable PM, total non-Hg HAP metals, or individual non-Hg HAP metals (or HAP metals inclus ive of Hg for liquid oil-fired units). The operating limit for demonstrating cont inuous shall be based on th e 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 annua lly 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 provi de 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 op tion to install and operate PM CEMS if the source chooses to comply with the filterable PM emissions limit. To apply th is option, the source would have to meet Performance Specification 11 and procedure 2 of 40 CFR part 60 appendice s B and F, respectively.

Comment 30: Commenter 17621 notes that there are almost 70 PM CEMS operating on EGUs in the U.S. Over 40 are installed on wet stacks (following FGD systems). According to the commenter, PS-11 requires a minimum of 15 Method 5 test runs to develop a calibration curve for the CEMS and as a practical matter, the lowest point on the calibrati on 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-sc ale readings to the instrument while conducting the Method 5 manual testing. The commenter states that while this appro ach has been demonstrated with some success on dry stacks by de-tuning the ESP, it has not been attempted on units equi pped with fabric filters. The commenter asserts that wet stack applications pr esent further challenges, since de-tuning an ESP upstream of a wet FGD has less eff ect on the outlet emissions and in creases the risk of producing offspecification gypsum. According to the commenter, in these cases, the calibration curve for the PM CEMS consists of the normal opera ting 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 inst alled on wet stacks have indicated some plugging problems. The commenter asserts that usually this has been handled by frequent cleaning of the probes. The commenter states that the expe rience at an EPRI demonstration project has shown similar issues, with some systems working better than others. Acco rding to the commenter, al l of the vendors continue to make improvements and try alternatives. The comm enter states that dry stack systems fare better, especially where cross-stack installations are possi ble, though one particular model had problems with data loss due to sunli ght interference at th e height of the day.

According to the commenter, the sensitivity of the PM CEMS is limited by the lowest filterable PM emission that can be accurately and precisely measur ed by Method 5. The commenter states that in EPRI sponsored PS-11 testing, the lowest range of PM emissions used for calibration was 2 to 5 milligrams per cubic meter (mg/m3), approximately 0.002 to 0.005 lb/MMBtu. According to the commenter, this level of sensitivity is adequate to measure filterable PM at the proposed total PM limits for existing coalfired EGUs (0.03 lb/MMBtu), but may not be sensit ive enough to measure at the proposed total PM limit for new coal-fired EGUs (approximately 0.005 lb /MMBtu). Commenter notes that while a lower detection limit for Method 5 can be obtained by exte nding the sampling time, longer sampling times will increase the time required to conduct the full 15 runs required by PS-11.

Response to Comment 30: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 31: Commenter 19033 is unaware of any PM CEMS that can measure both filterable and condensable PM. The commenter has PM CEMS on thr ee industrial boilers th at it owns and operates and they operate at a temperature of approximately 320 oF, in order to prevent water droplet interference. According to the co mmenter, if the EPA intends that a PM CEMS be used to assure compliance with the PM limit in Table 2, it needs to amend Table 2 to specify that the PM limit is filterable PM, not total. The commenter states that in that manner, output from a PM CEMS, coupled with the required part 75 flow and diluent monitors, can be used to provide PM emissions on a lb/mm Btu basis. According to the commenter the EPA s eems to be trying to control condensable PM by specifying that the PM emission limit be on a total, rather than-filterable basis. The commenter states that wet scrubber technology will provide condensable PM removal, in addition to acid gas removal, and there is thus no need for the EPA to regulate condensable PM as part of this regulation with a specific emission limit.

Response to Comment 31: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg154 HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 32: Commenter 17790 states that the accuracy of a PM CEMS should be considered when setting an emission limit. The commenter states that establishing the “accuracy ” of the PM CEMS is accomplished by conducting a three-level Method 5 test but that unlike gaseous monitors (e.g., SO 2 or NO X CEMS), PM CEMS are not capable of rout ine calibration checks us ing 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 requir e de-tuning of PM control devices, without a corresponding relief from current emission limitations and reporting requirements.

Response to Comment 32: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Although PM CEMS are not required under the final rule , we believe that PM CE MS with a successful correlation using PS-11, with the 95% confidence levels, will assure th at the PM CEMS would have the necessary certainty as a complian ce monitor. Most all su ccessful correlations achieve much tighter statistical criteria than the minimum allowed und er PS-11 and Procedure 2. Pr ocedure 2 describes the required audits to insure that subsequent measurem ents are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 33: Commenter 17790 states that the EPA must allow th e 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 st ack tests. The commenter states that the EPA did modify some of the requirements in Method 5 (filter temperature) whic h are consistent with Method 5B objectives and thus should allow the complete use of the method.

Response to Comment 33: PM CEMS are no longer required unde r the final rule. Method 5 is the reference compliance method in the final rule for th e 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 fo r further discussion).

Comment 34: Commenter 17790 states that there is insuffi cient reliability in PM CEMS to give accurate data for EGUs with low PM emissions (i.e ., EGUs with FGD). The commenter states that its Monroe Power Plant is currently ho sting an EPRI PM CEMS Demonstr ation Project. According to the commenter, the commenter’s experience so far sugge sts that PM CEMS may not be reliable and accurate monitors of stack gas particulates; the pr oject has accumulated limited run time, with substandard performance such as plugged monitors and extended down time.

Response to Comment 34: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet 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 matr ix 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 th e installation. We believe that PM CEMS with a successful correlation using PS-11, with the 95% conf idence levels, will assu re that the PM CEMS would have the necessary certainty as a compliance m onitor. Most all successf ul 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 subse quent measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 35: Several commenters (17681, 17638, 18831) di sagree with using PM CEMS for compliance for the following reasons. According to the commenters:

1. The commenters believe PM CEMS have not proven to be reliable for the el ectric utility industry, 2. The instruments are very expensive, 3. The instruments measure only filterable PM, and 4. The proposal to use a short-term to tal 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 requ est that the EPA requi re compliance for metals based on an annual filterable PM test because EGUs are accustomed to conducting annual PM stack tests for SIP and NSPS compliance.

Response to Comment 35: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this156 method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet 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 fina l rule, the EPA disagrees with the commenters that indicate a general concern that PM CEMS are not an ade quately reliable technology. PM CEMS have been demonstrated for a variety of applicat ions. 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 succe ssful installations in the United States and in other countries. A successful installation is obtained when a PM CE MS passes the PS-11 statis tical criteria, thereby demonstrating that an acceptable level of accuracyis 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 emissi on 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 subse quent measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 36: Commenter 19197 states that the PM CEMS ope rating limit is proposed to be set at the highest 1-hour average measured rate from the mo st recent performance test used to demonstrate compliance with the total PM emissions limits. A ccording to the commenter, the proposed methodology is likely non-representative because the time period nece ssary to perform the total PM performance test is relatively short, consisting of three 1- to 2-hour long simulta neous EPA Method 5 and Method 202 stack tests. According to the comme nter, the resultant operating limit is only representative of the 3 to 6 hour PM control system operating pe riod and consequently, the performa nce testing time period may not represent typical PM control effici encies. The commenter states that the testing might occur during a highly controlled period, resulting in an overly restrictive filterable PM emissions operating limit. The commenter offers an example of the potential subj ectivity of the proposal. The commenter states that during performance testing, hypothe tical “Facility A’s” baghouse particulate control system’s effectiveness might be very effective and the EPA Method 5 and Method 202 testing show very low filterable and total PM emission rates while converse ly, hypothetical “Facility B’s” baghouse particulate control effectiveness might be compromised dur ing the EPA Method 5 and Method 202 performance testing, barely showing compliance with the total PM limit. According to the commenter, consequently, setting the filterable PM CEMS lim it 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 determinati on methodology should not en courage operating with marginal baghouse control effectiven ess during performance testing.

Response to Comment 36: Under the final rule sources are al lowed to establish different operating limits monitored with a PM CPMS if they believe ther e is variability due to va rying 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 discussi on). Sources also may opt fo r quarterly testing with reference methods to determine compliance.

Comment 37: Commenter 17975 states that they have discussed with vendors, the ability of the two primary types of PM CEMS (light scattering or beta measurement) to measure high concentrations of PM, such as are and would be emitted during SSM events, especially for units with non-energized ESPs during such events. The commenter states that vendors have assured the commenter that if the specifications call for measurements of high concentra tions of PM then they can supply the appropriate instrument packages. Commenter notes that there is nothing inherently lim iting for either of these technologies that would preclude thei r ability to measure high concentrat ions of PM and the fact that reputable vendors confirm this makes it imperative th at PM CEMS be required at all times, including SSM time periods, when emissions are at their highe st, especially for units with ESPs. Commenter provides a short explanation of both types of CEMS.

Response to Comment 37: As mentioned elsewhere, the comment is moot, for the final rule no longer contains emissions limits applicable during startu p or shutdown periods and provides for affirmative defense in the event of excess emissi ons that occur during a malfunction.

Comment 38: Commenter 17696 states that because of bad performance of PM CE MS on two of their coal-fired units, they believe it is inappropriate for the EPA to require th e use of PM CEMS for compliance determinations without a reasonable alte rnative until reliable PM CEMS are commercially available. The commenter believes that a reasonable alternative is to require periodic PM emission tests when fuels change or when PM CEMS indicate, similar to a part 64 CAM approach. The commenter believes it is not necessary to require fuel an alyses or bimonthly Method 29 stack tests.

Response to Comment 38: Under the final rule sources are al lowed to establish different operating limits monitored with a PM CPMS if they believe ther e is variability due to va rying 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 discussi on). Sources also may opt fo r quarterly testing with reference methods to determine compliance.

Comment 39: Commenter 17705 states that the agency must address issues with PM CEMS technology before mandating its use as a compliance methodol ogy because PM CEMS are not yet widely deployed across the utility industry and b ecause the agency has made use of PM CEMS optional under 40 CFR part 60, subparts D and Da. The commenter has no dire ct experience with PM CEMS but is aware that the industry has ongoing concerns and st ates that the EPA shares at leas t some of these concerns based on text included by the agency in a consent decree that requires a 2-year de monstration period for PM CEMS. According to the commenter the language in the consent decree acknowledges that PM CEMS technology is still in development. The commenter st ates that the EPA must also commit to providing a simpler and more reliable way to calibrate PM CE MS because PS-11 can be difficult for sources with highly efficient PM controls. The commenter states that the PS-11 procedures place source operators at risk of exceeding permit limits, and the commenter requests that the EPA provide guidance to permitting authorities that it is inappropriate to subject sources to enforcement proceedings when trying to achieve the high dust loads required by PS-11. The commenter does not support the proposed alternative to PM CEMS of conducting bimonthly Method 29 tests.

Response to Comment 39: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this158 method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet 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 fina l rule, the EPA disagrees with the commenters that indicate a general concern that PM CEMS are not an ade quately reliable technology. PM CEMS have been demonstrated for a variety of applicat ions. 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 succe ssful installations in the United States and in other countries. A successful installation is obtained when a PM CE MS passes the PS-11 statis tical criteria, thereby demonstrating that an acceptable level of accuracyis 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 emissi on 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 subse quent measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 40: Multiple commenters (17402, 17681, 17716, 17737, 17758, 17820, 18014) characterize PM CEMS as not measuring PM directly, and se veral commenters (17402, 17758, 18014) state that PM CEMS calculate PM emissions based on reference me thod measurements that depend on the calibration procedures and the inherent limita tions of the measurement technology.

Response to Comment 40: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh the operating limit during each performance test. A PM CPMS does not need to m eet 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 fina l rule, the EPA disagrees with the commenters that indicate a general concern that PM CEMS are not an ade quately reliable technology. PM CEMS have been demonstrated for a variety of applicat ions. 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 succe ssful installations in the United States and in other countries. A successful installation is obtained when a PM CE MS passes the PS-11 statis tical criteria, thereby demonstrating that an acceptable level of accuracyis achieved. PS-11 provides the steps in obtaining a159 reliable successful correlation with reference methods, thereby ensuring compliance data that is sufficient to determine compliance with PM emissi on 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 subse quent measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 41: Multiple commenters (17402, 17716, 17725, 17758, 17790, 17820, 18014, 18498, 18023) believe that PS-11 creates a significant risk of “false positives” due to instrument error because of PS-11’s generous statistical performance criteri a. These commenters also express doubts that PM CEMS can produce representative measurements over the entire range of bo iler operations because calibration of the instrument does not occur across all load ranges . According to commenters, these periods of operation result in transient flue ga s conditions causing changes in particle density, morphology, size distribution or strati fication of PM within the flue that are not reflected in the correlation of the instrument. The commenters believe some of the preceding issues can be addressed in the final rule, but the commenters do not think the technology is usable as a direct indicator of compliance as proposed.

Response to Comment 41: Although PM CEMS are no longer requ ired under the final rule, section 2.4 of PS-11 stresses the importance of planning for the sp ecific effluent matrix and/or PM that might influence the correlation and describes the process required to enhance the pr obability 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% confiden ce levels, will assure that the PM CEMS would have the necessary certainty as a complian ce monitor. Most all successful correlations achieve much tighter statistical criteria than th e 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. Sec tion 2.4(1) of PS-11 states that you should select a PM CEMS that is appropriate for your source. Manufacturers of beta gauge instruments have demonstrated that the calibration curve does not change as the fuel mix changes or load changes. Vendors have guaranteed that their PM CEMS will meet the PS-11 criteria for multi-fuel boilers. PS-11 provides for situations where multiple correlatio ns may be needed for a PM CEMS technology (see Section 2.3 of PS-11). Based on this information, the fi nal rule does provide for the use of a PM CEMS to determine compliance with the filterable PM emissi on limit if the source elects to use this approach (see the final preamble fo r further discussion).

Comment 42: Several commenters (17402, 17681, 17716, 17740) st ate 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 reflec t the underlying uncertainty of the PM CEMS.

Response to Comment 42: The final rule no longer requires a PM CEMS for compliance monitoring. Under the final rule, you may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you mustinstall a PM CPMS and establish the operating limit during the initial compliance test for filterable PM, total non-Hg HA P metals, or individual non-Hg HAP metals (or HAP metals inclusive of Hg 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-establi sh 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 filterable160 PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Comment 43: Commenter 17761 states that if emission reduc tions are mandated, it must be recognized that PM CEMS have not been widely deployed an d their utilization has been largely limited to requirements imposed by the EPA in NSR consent de crees with escape clauses in place. The commenter submits that there is insufficient experience withPM CEMS being utilized for compliance purposes to make them a viable tool to judge co mpliance with these standards. To th e extent that stac k testing is an alternative, the commenter submits that there is current ly 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 pr ocedures after having experiences w ith failed PM stack test results that are due to human error.

Response to Comment 43: Although PM CEMS are no longer re quired under the final rule, the EPA disagrees with the commenters that indicate a genera l concern that PM CEMS are not an adequately reliable technology and are have no t been widely deployed. PM CEMS have been demonstrated for a variety of applications. PM CEMS performance sp ecifications and QA procedures have been around quite a while with PS-11 and Procedure 2 promul gated January 2004. There have been at least 65 successful installations in the United States and in other countries. A successful installation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby demonstrating that an acceptable level of accuracy is achieved. PS-11 provides the steps in obtaining a reliable successful correlation with reference methods, thereby ensuring compliance data th at is sufficient to determine compliance with PM emission limits. Most all successful correlations achieve much tighter statistical criteria than the minimum allowed under PS-11 and Procedure 2. Procedure 2 describes the required audits to insure that subsequent measurements are stable and within acceptable limits, thereby ensuring reliable compliance data.

Comment 44: Commenter 17871 states that PM CEMS are notyet advanced enough to provide reliable and accurate data at a reasonable cost. The commenter st ates that state agencies regularly determine that PM CEMS are not reasonably cost-effective monitori ng devices-a point with which the EPA has agreed. See 70 FR 7908 (Feb. 16, 2005) (justifying the use of COMS because CEMS are “significantly more expensive to purchase and maintain than COM ...”). The commenter states that the requirement for PM CEMS is particularly problematic for EGUs with very low mass emissions of filterable PM. The commenter states that the MACT requires develo ping 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 pr ecision of Method 5 at low PM concen trations, it will be very difficult to demonstrate the correlation coeffi cient (>0.85) required for the initial site specifi c certification of the PM CEMS. The commenter also assert s that it is also uncl ear how a range of PM concentrations can be created during performance testing when a fabric f ilter baghouse is used for particulate control.

Response to Comment 44: Although PM CEMS are no longer requ ired under the final rule, section 2.4 of PS-11 stresses the importance of planning for the sp ecific effluent matrix and/or PM that might influence the correlation and describes the process required to enhance the pr obability 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% confiden ce levels, will assure that the PM CEMS would have the necessary certainty as a complian ce monitor. Most all successful correlations achieve much tighter statistical criteria than th e 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 reliabl e compliance data. Precision of the Method 5 tests may be improved by employing paired trains for each run to sort out the imprecise test runs. PS-11 has a special correlation coefficient of >0.75 for low-em itting sources and section 8.6 of PS-11 allows sources to obtain zero point data to aid in achieving corre lation criteria.

Comment 45: Commenter 18447 is concerned about the accuracy and relia bility of a PM CEMS and under the proposed rule their units w ould require monthly stack tests thatare excessive and expensive.

Response to Comment 45: Although PM CEMS are no longer required under the final rule, EPA disagrees with the commenters who indicate a genera l concern that PM CEMS are not an adequately reliable technology. PM CEMS have been demonstr ated 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 b een at least 65 successful installations in the United States and in other countries. A successful in stallation is obtained when a PM CEMS passes the PS-11 statistical criteria, thereby de monstrating that an acceptable le vel of accuracy is achieved. PS-11 provides the steps in obtaining a re liable successful correlation with reference methods, thereby ensuring compliance data that is sufficient to determine co mpliance with PM emission limits. Most all successful correlations achieve much tighter statistical criteria than th e 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 reliabl e compliance data. Under the final rule we have dropped the requirement fo r monthly stack tests.

Comment 46: Commenter 18935 recommends that the EPA develop a guidance document for performance specification testing of PM CEMS that reflects recent experien ce with current control technologies and emission levels. The commenter also suggests that sources be allowed a phase in period for PM CEMS, perhaps allowing sources to conduct frequent periodic monitoring by conventional reference methods until a PM CEMS is installed. According to the commenter, it has assisted clients with the performance specification testing of part iculate 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 commen ter states that sophisticated particulate emission control systems perform consistentlyand reliably when matched to s ource characteristics – changing operations to produce alternate emissi on levels is not an easy matter. Ac cording to the commenter, while PS-11 allows for the generation of low level emissi on data by removing the probe, it is not clear if reference method testing using a Method 5, 5I, or 17 sampling train needs to be conducted during the same time (if so, these methods are not reallydesigned for ambient particulate monitoring).

Response to Comment 46: PM CEMS are no longer required unde r 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 establis h the operating limit duri ng the initial compliance test for filterable PM, total non-mercury HAP meta ls, or individual non-Hg HAP metals. The operating limit for demonstrating continuous shall be based on the highest 1-hour average measured during the most recent performance test. If you use a PM CP MS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and re-estab lish the operating limit during each performance test. A PM CPMS does not need to m eet the requirements for a PM CEMS under PS 11.

6. PM CEMS certification issues.162 Comment 47: Commenters 17800 and 17914 request clarificati on on the procedures to be used for certification of PM CEMS. In orde r to certify a PM CEMS using PS- 11 procedures, the PM CEMS must be correlated using a three point curve with the reference method data. According to the commenters, in order to generate the three PM loads required by PS- 11 (section 8.6) it is necessary to partially disable the particulate control device to increase/decrease th e PM mass loading to establish a valid correlation curve, but this may not be practical or possible for cer tain particulate control technologies, as there is no way to temporarily, partially disabl e fabric filters not equipped with flue gas bypass dampers to generate higher PM emissions. In addition, stat e the commenters, state or local regulatory permits may preclude a source from operating at PM levels in excess of th e permitted levels, and without an exemption, it would not be possible to pass the correl ation tests in PS-11. Commenter 17914 st ates that in addition, for IGCC there is no PM control device since the combustion turbine is burning synthetic gas fuel, and it may not be possible to establish an adequate correlation of PM as per PS-11 requirements for certain control devices/plant configurations.

Comment 48: Commenter 17801 states that PS-11 requires a correlation with reference method tests performed over the full range of the PM CEMS responses that corresponds to the normal operating conditions of the source and control device and that due to a lack of post combustion emissions control, IGCC syngas-fueled turbines are not able to vary PM emissions to achieve a valid correlation. The commenter states that PM spiking is an opti on (though it hasn’t yet been demonstrated and not recommended by GE on a combustion turbine), but thes e systems are still in development, and may not even be appropriate, safe or possible to inject PM into a combustion turbine. Commenter further notes that PS-11 requires that the confiden ce interval (CI) and the Tolerance Interval half range (TI) are both calculated as a percent of the emission limit; accordi ng to the proposed EGU MA CT, the limit would be set by the performance testing for in itial compliance and filterable PM is a surrogate for non-Hg metal HAP, and the particulate limit (which includes condens ables) would not apply to the correlation; and depending on the results, it may be im possible 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 methodologi es (Methods 5/202). The co mmenter suggests that opacity monitors can be used on a conti nuous basis as a compliance indicator.

Response to Comments 47 - 48: PM CEMS are no longer required under the final rule. You may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM CPMS and establis h the operating limit duri ng the initial compliance test for filterable PM, total non-Hg HAP metals, or individual non-mercury HAP metals. The operating limit for demonstrating continuous shall be based on the highest 1-hour average measured during the most recent performance test. If you use a PM CP MS and associated operating limit, you must conduct the applicable Method 5 or Method 29 test once annually and re-estab lish the operating limit during each performance test. A PM CPMS does not need to m eet 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. Pr ecision of the Method 5 tests may be improved by employing paired trains for each run to sort out the imprecise test r uns. PS-11 has a special correlation coefficient of >0.75 for low-emitting sources and s ection 8.6 of PS-11 allows sources to obtain zero point data to aid in achieving corr elation criteria. We recommend that sources operate their PM CEMS over a correlation test planning peri od of sufficient durat ion 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 emissi on limit if the source elects to use this approach (see the final preamble fo r further discussion).163 7. Problems with “floating limits.”

Comment 49: Commenters 17623 and 17774 conclude that the operating limits for PM CEMS will be “floating limits” in which a facilitywill be measuring filterable partic les with its CEMS, but its actual limit is based on the performance testing which m easures total PM. According to commenters, as proposed, the “floating limits” w ill create uncertainty in the re gulated community and will be detrimental to the application of the Utility MACT. In light of the measurement problems caused by a total PM limit, one commenter requests that the EPA ch ange the PM surrogate standard from a total PM standard to one based only on filterable PM because the commenter believes it will allow for a clearer target that will not change as operating conditions change.

Response to Comment 49: PM CEMS are no longer required unde r 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 establis h the operating limit duri ng the initial compliance test for filterable PM, total non-mercury HAP meta ls, or individual non-mercury HAP metals (or HAP metals inclusive of mercury for liquid oil-fired units ). The operating limit fo r demonstrating continuous shall be based on the highest 1-hour average measur ed during the most recent performance test. If you use a PM CPMS and associated operating limit, you must conduct the applicab le Method 5 or Method 29 test once annually and re-establish the operati ng 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 fi nal preamble for further discussion).

Comment 50: Commenters 17714 and 17756 state that under th e proposed rule each unit’s operating limit is confirmed or reestablished during subseque nt performance tests and this could result in progressively tighter limits over time based on the unit’s most recent test. Commenters believe it is inappropriate and inconsistent with the CAA to ti ghten a limit based on test results that show lower emissions from a previous test. Commenter 17756 states that their experience with PM CEMS data from well-controlled units show that compliance with a lim it 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 unde r 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 establis h the operating limit duri ng 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 op erating 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 c onduct 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 ru le 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 fo r further discussion).

Comment 51: Several commenters (17655, 17752, 18023) stat e 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 marg in (e.g., actual Method 5 re sults during performance test < 0.010 lb PM/MMBtu) but no matter how well the unit performs during performance tests, the proposal stipulates that the unit must continue to operate at the same filterable PM emissions rate (as determined by PM CEMS) indefinitely. The commenters state that the “operating limit” for filterable PM reflects a limit on the only fraction of total PM re moved by standard air emi ssion control equipment. Commenter 17655 believes that this is a radical depart ure from past agency standard-setting, which has consistently recognized that contro l equipment performance varies over time, especially in units like power generation equipment that must operate for extended periods between maintenance outages. The commenter conjectures that the “EPA apparently assumes that condensable PM is both an indeterminate and widely varying quantity that has the capability of throwing an affected EGU out of compliance....” The commenter contends that the agency offers no evidence that the condensable PM fraction can be determinative of compliance withthe non-Hg metals standard, a nd the commenter believes that condensable PM is instead a relatively fixe d increment during normal operation. Based on the commenter’s assumption that the condensable PM rate is relatively constant, the commenter recommends that the condensable PM emission ra te (lb condensable PM/ MMBtu) measured by the reference method in the most recent performance test should be utilized as a constant value in the following equation to determine the hourly emission rate in compliance calculations for the 0.03 lb PM/MMBtu MACT limit for existing sources:

Calculated tPM for comparison to standard = (cPM from most recent performance test ) + (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 calc ulated as follows after each performance test:

Operating Limit = 0.03 lb tPM/MMBtu - cPM from most recent performance test

Comment 52: Commenter 17716 acknowledges that their re commended 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 flaw s, 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 th e compliance process that better reflects normal operating conditions. Commenters 17716 and 17758 also st ate that establishing a fixed filterable PM operating limit value is necessary for determining th e acceptability of the tolerance interval and confidence interval results for PS-11.

Response to Comments 51 - 52: PM CEMS are no longer required under the final rule. You may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous compliance, you must install a PM CPMS and establis h the operating limit duri ng 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 op erating 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 c onduct 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. Th e 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 pream ble for further discussion).165 Comment 53: Commenter 17758 believes without a filterable PM emissions limit in the final rule, the PM CEMS compliance approach is unworkable and in consistent with the perf ormance criteria of PS-11. Commenter 17716 believes that allowing sources to subs titute a total PM limit for a filterable PM limit for PS-11 purposes is appropriate because the total PM limit would effectively represent the highest potential filterable PM limit where conde nsable emissions are reduced to zero.

Response to Comment 53: PM CEMS are no longer required unde r 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 de termine compliance with the filterable PM emission limit if the source elects to use this approach (s ee the final preamble for further discussion).

Comment 54: Commenters 17912 and 17798 state that the propos ed rule that establishes a long-term compliance limitation based upon only a few hours of test results fails to take in to account the court’s holdings that the EPA must establish MACT standard s which include all operating scenarios including variability which always occurs.

Response to Comment 54: The agency disagrees with the comme nters, for the PM emissions limit includes a variability co mponent determined using ICR Part II data and the UPL calculation.

Comment 55: Commenters 17913 and 19114 state that the propos ed approach punishes a unit that has low PM emissions because the performance test will es tablish the condensable emissions from each unit, and the subsequent “filterable PM limit” should be equal to the tota l PM limit in the regulation minus the measured condensable PM emissions. Commenters no te that the approach will reward facilities that are able to increase their emissions right up to the to tal PM limit during the performance test, so as to obtain the least restrictive subsequent “filterable PM limit.” Accord ing to the commenters, the goal of the regulation should be to ensure that facilities maintain emissions below the given emission standard in the regulation; this is achieve d by having a facility demonstrate th at filterable PM measured with a CEMS in combination with condensable PM meas ured during a performance test do not exceed the given total PM emission standard. Commenter 19114 not es that units that employ a baghouse will be out of compliance as often as units equipped with precip itators due to the tighter unit-specific PM limit that would be established as a result of the require d 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/mmB TU for condensable PM thereby passing the performance test; the unit woul d then have to meet a 0.008 lb/ MMBTU limit on its PM CEMS. The commenter states that a unit equipped with an ESP may have emissions during the performance test of 0.02 lb/MMBTU for filterable PM and 0.01 lb/MMBTU for condensable PM, thereby passing the performance test; this unit woul d then have a 0.02 lb/MMBTU lim it on its PM CEMS. The commenter states that the baghouse is doing a much better jo b of controlling PM, but the manner in which the proposed rule governs ongoing operations does not gi ve the unit with the ba ghouse 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/MMBTU, less the c ondensable fraction, 0.012 lb/MMBTU, to give the source its filterable PM CEMS limit of 0.018 lb/MMBTU ; this approach would meet the spirit of the proposed rule by limiting a source to the MACT floor, while giving the source credit for good performance.

Response to Comment 55: Monitoring of total PM is no longer re quired in the final rule. PM CEMS are no longer required under the fina l rule. You may elect to comply w ith an optional operating limit for PM. See the response to Comment 53 above.166 Comment 56: Multiple commenters (17655, 17716, 17725, 17752, 17881, 18498, 18023) oppose the proposed procedure for deriving an operating limit based strictly on the filterable PM emission rate during periodic performance tests, and provide the following reasons:

1. According to the commenters, an operational limit e qual to filterable PM at the time of testing would reflect an unrealistic expectation of future performance. For exampl e, 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 unreasonabl e to hold any equipment to the same level of performance after years of operation (even with frequent maintenance). 2. According to the commenters, the source’s margin of compliance may be completely lost depending on the vagaries of the situation at the time of a pe rformance test. According to the commenters, if the combination of normal operating conditions at the tim e of the performance test enables the unit to operate on the lower end of the normal operating range, the PM operating limit will be unattainably low during operating conditions on the higher end of the normal range. The commenters state that the proposed methodology eliminates the compliance margin for sources with very low emissions on the day of the performance test , yet the opposite result may occur for a unit that barely meets emissions limits due to challenging conditi ons 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 met hodology encourages operator s 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 c onditions. Commenters (18023, 17798, 17912) state that the proposed method provides a disincentive for inst alling controls, or oper ating 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 withthe MACT program’s goal of uniform standards. 6. According to the commenters, an exceedance of th e PM CEMS operating limit does not necessarily indicate actual emissions we re above the underlying PM stan dard or non-Hg HAP standard.

Response to Comment 56: The final rule requires the use of a PM CPMS for an operational limit and does not enforce a numeric PM limit. If you use this method to demonstrate continuous compliance, you must install a PM CPMS and establish the operating lim it 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 demons trating continuous shall be based on the highest 1- hour average measured during the most recent perf ormance 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 Me thod 5 or Method 29 testonce annually and reestablish the operating limit during each performance test. Any degradation of the control equipment will be accounted for in the yearly reestablishm ent of the PM operational limit and the compliance margin will change accordingly. A PM CPMS does not need to meet the requirements for a PM CEMS under PS 11. The final rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

Under the final rule, sources are allowed to estab lish different operating limits monitored with a PM CPMS if they believe there is variability due to vary ing load conditions. The final rule no longer requires monitoring with a PM CEMS. Establishment of the operating limit during the initial compliance test for filterable PM, total non-mercury HAP metals , or individual non-mercury HAP metals using the167 highest 1-hour average measured, along with allowing more than one operational limit for different load conditions, and a 30-day rolling aver age should provide certainty of co mpliance 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 E GUs in accordance with an operating limit, they could choose to use a PM CEMS or quarterly emissions testing.

Comment 57: Commenter 17808 recommends changing the tr eatment of condensable PM for units using PM CEMS to establish an operating limit on filterable PM. The commenter provides the following example of why the proposed treatm ent of condensable PM is inequitable with regard to emissions of metals: For instance, states the commenter, in the in itial compliance demonstration for Facility A, an existing coal-fired power plant with heat input >8,300 Btu/lb, shows to tal 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 esta blished. However, states the comme nter, 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, a nd could result in a facility havi ng a variable emissions target. Additionally, states the commenter, this method results in unfairly “ratcheting down” the standard on some units and introduces a new set of problems.

Response to Comment 57: PM CEMS are no longer required unde r the final rule. You may elect to comply with an optional operating limit for PM. . See the response to Comment 53.

Comment 58: Commenter 17774 states that the use of a tota l PM surrogate presents a host of problems including:

1. According to the commenter, the EPA’s use of a conde nsable PM standard has the effect of increasing the stringency of the PM rate, as compared to an emi ssion rate for PM that applies solely to filterable PM emissions.

2. According to the commenter, the total PM standard s 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 si mply cannot be used to measure compliance in conjunction with a rule imposing a limit on total PM without introduci ng considerable uncertainty into the compliance guidelines. The commenter states that the CEMS technology is quite different from the formula the EPA used to set the total PM standard . According to the commenter, a PM CEMS monitors only filterable PM emissions, not condensable emissions , and therefore cannot be used to set a total PM limit; because of this, the limits for PM will have to be established by PM performance tests, which are the only process that can measure both f ilterable 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 variab ility calculation is contrary to the requirements for setting a MACT standard; if the EPA retains a total PM standard, it mu st add a variability factor to the requirements to reflect the full range of conditions un der which sources are operating. The commenter states that it is not feasible to require numerous stack tests, as each is expensive and time-consuming, nor is it acceptable to base a standard on isolated stack testing conditions alone.

Response to Comment 58: Measurement of condensable PM is no longer required under the rule.168 8. Variability of reference meth od data from scrubbed units.

Comment 59: Commenter 17675 states that stack tests co mpleted since installation of scrubbers indicates filterable PM is very low and that annual condensable PM and filterable PM test data indicates there are no consistent ratios for condensable PM, filterable PM, or total PM from the commenter’s scrubbed units. Based on these highly variable and c onsistently low PM data, the commenter believes it will be nearly impossible to develop an accurate co rrelation curve for PM CEMS. In lieu of the PM CEMS option, the commenter requests that the fina l rule include an LEE te sting option for sources consistently performing at emission rates much lo wer than the PM standard. The commenter requests that such a PM LEE option preclude regular or additional Method 29 tests.

Response to Comment 59: Measurement of condensable PM is no longer required under the new rule. The final rule does include the LEE option w ith less frequent performance testing.

Comment 60: Commenters 17383 and 19121 state th at trying to use a PM CE MS 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 filt erable PM is highly vari able. According to the commenters, under these circumstances, correlati on 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 ma naged 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 requi red in the final rule.

Comment 61: Commenter 18443 states that the EPA cannot require sources to set filterable PM operating limits with no compliance margin and that for units that emit low concentrations of PM, this is an extremely onerous requirement with which it is likely impossible to comply. Units with wet FGDs, for example, typically emit filterable PM at or belo w detection levels. According to the commenter, a limit set at these levels would be below the dete ction level of a PM CEMS and allow no compliance margin. The commenter states that the EPA has not ju stified this type of requirement and it must be eliminated from the final rule.

Response to Comment 61: PM CEMS are no longer required in the final rule. PM CPMS should be able to operate at the low PM operational levels expected at s ources and should not be below the detection limits.

9. Need for PM CEMS availability criteria.

Comment 62: Commenters 17638 and 17681 state that the EP A must establish minimum CEMS data availability and deviation require ments and that the operating costs included in the proposal fail to account for all the maintenance costs associated withPM CEMS. One commenter requests that the EPA revise those operating cost estimates.

Response to Comment 62: PM CEMS are no longer requir ed in the final rule.

10. Table 4 requirement to convert PM CEMS readings to dry basis.

Comment 63: Several commenters (17716, 17725, 18014) advise th at the requirement in Table 4 of the proposed rule to convert PM CEMS data to a “mg/ dscm” basis cr eates unnecessary problems because169 most PM CEMS do not measure on a dry basis but ar e correlated to “mg/ws cm.” According to the commenters, switching to a mg/dscm is problematic be cause the current measurement must be converted to a dry basis which would require a source to monito r stack moisture or use a some type of default value. Notwithstanding the inadvisab ility of using the PM measured during the compliance test as an operating limit, state the commenters, if the final rule retains this provision, sources should be allowed to use either the average 30-day co rrelated analyzer response (mg/wa cm, mg/wscm, etc.) or lb/MMBtu values as an indicator.

Comment 64 : Commenter 17881 states that under sect ion 63.10021(a)(11)(ii) diluent data (O 2 /CO 2 ) is only needed for the lb/MMBtu rate calculation or con centration values corrected back to a diluents gas concentration (which is not the case, as the PM filte rable operating limit is mg/d scm and is not corrected back to a specific diluent level).

Response to Comments 63 - 64: PM CEMS are no longer required under the final rule. PM CPMS measurement data are to be in uni ts of raw instrument output and not necessarily on a concentration basis in the final rule. The fina l rule also does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion).

11. ESPs vs. fabric filters.

Comment 65 : Commenter 17705 has concerns because whil e ESPs are highly effective control technologies, they may not be as consistent in its day-to-day performance as fabric filter technology. According to the commenter, this difference is not a problem at currently permitted PM limits and under current compliance demonstration requirements (i.e., annual performa nce testing), but it could be a significant problem if the EPA retains the currentl y proposed requirements to establish PM operating limits, as such operating limits are expected to allow little, if any, operational variability in control equipment. The commenter doubts that even utilities with EGUs equipped with fabric filters can be confident they can demonstrate continuous compliance if the PM operating limit requirement is implemented as proposed by the EPA.

Response to Comment 65: While the rule no longer requires use of PM CEMS and associated operational limits, the rule retains establishing an operational limit and measur ing it using a PM CPMS. Should the owner or operator be un comfortable 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 appr oach (see the final preamble for further discussion). The source can also conduct quarterly performanc e testing in place of these continuous monitoring options.

12. Direct measurement.

Comment 66: Commenter 17747 states that direct monitoring of pollutants rather th an a surrogate (PM) will contribute to a better understanding of the healtheffects associated with each metal. According to the commenter, direct measurement for HAP by the EPA is a provision of the CAA Revisions of 1990 and best fit with the requirem ents and purpose of the law.

Response to Comment 66: Consistent with the CAA, the rule re quires monitoring sufficient to assure compliance with the emissions limits and that th e sources will maintain emissions reductions on a continuous basis. The rule applies continuous emissi ons 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, incl uding HAP metals, and continuous emissions monitoring will provide a significant increase in the amount of directly measured emissions data over the current database. The ru le also requires electr onic reporting of monitoring and testing data directly to the EPA so that we w ill have these data in hand for supporti ng subsequent regulatory reviews.

Comment 67: Commenter 17881 states that it makes litt le sense to have sections 63.10005(d)(1) through (d)(6), as well as secti on 63.10005(e), describe the averagi ng 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/M MBtu, lb/TBtu, lb/MWh or lb/GWh). Commenter further notes that section 63.10005(d)(5) currentlydiscusses the use of PM CEMS fo r demonstrating compliance with the applicable emission limits in Tables 1 and 2 of the pr oposed rule but that the re ference to the use of PM CEMS for demonstrating compliance with the emission limits is wholly inappropr iate, as the PM CEMS are to be used to verify compliance with an operati ng limit (in units of mg/dscm) consistent with Table 4 of the proposed rule, not PM emission limits expre ssed as lb/MMBtu or lb/MWh (and reckoned on a different basis, i.e., total PM versus filterable PM).

Response to Comment 67: We have edited the final rule so that the text is consistent with the format of the required measurements. Note also that measuremen t of condensable PM is notrequired in the final rule and PM CEMS are no longer required in the final rule. 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 pream ble for further discussion).

13. Clarification on use of parametric monitoring in lieu of CEMS.

Comment 68: Commenter 17914 requests clarification on the parametric monitoring approach described on page 25064. The commenter finds only an annual test requirement for the Parametric Monitoring option. The commenter notes that in the preamble (pages 25029 -31) both initial compliance and on-going compliance for IGCC or coal or solid oi l-derived fuels requirements are discussed and if an EGU elects to use total PM as a surrogate fo r 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 c ontrol 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 altern ate 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 e xpected that a change in coal characteristics, combustion system operation or AQCS system performa nce may cause the parametric correlation to PM emissions to change but it is no t clear why a PM CEMS would be immune to this same effect. According to the commenter, the use of PM CEMS re quires 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 canchange over time and with varying conditions. Monthly va riation of PM emissions vs. system operating parameters requires additional study to determine if any variation exists that may result inexceedance of th e total PM limit. The commenter states that this study should also include PM CEMS and the potentially variable relationship of filterable PM to Total PM over time. The commenter recommends the proposed rule be revised to reduce the testing requirem ents 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 comm enter further recommends that the text in section 63.1 0022 explicitly include wet ESP technology in the parametric monitoring options for PM.

Response to Comment 68: Measurement of condensable PM is notrequired 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 ra w output of the PM CPMS ) established during the previous test.

Comment 69: Commenter 19033 recommends that the operati ng requirements for ESP power input, as documented during performance tests, only be appli cable during periods of PM CEMS downtime, so that it can be demonstrated that the ESP is opera ting properly during such PM CEMS downtime events. The commenter states that such a provision would be patterned after the Part 75 requirements that address demonstration that the APCD is operating properly, so that SO 2 substitution values can be supported during periods of SO 2 CEMS downtime.

Response to Comment 69: Parameter monitoring of ESP parameters is not required in the final rule.

Comment 70: Commenter 19121 states that units with PM CE MS should not be required to install bag leak detectors.

Response to Comment 70: Parameter monitoring of baghouses, incl uding bag leak detectors, is not required in the final rule.

14. Corrections.

Comment 71: Commenter 18014 states that Table 8 erroneou sly references “QA Procedure 5” for the PM CEMS QA/QC requirements. According to the co mmenter, this reference should be changed to “Procedure 2.”

Response to Comment 71: This reference has been removed in the final rule.

Comment 72: Commenter 19121 states that part 63 Table 4 is setting ope rating limit averaging periods of 1 hour for outlet emissions is counter to the 30 boiler operating day averaging methodology.

Response to Comment 72: The final rule requires a 30-boiler ope rating day rolling average for the PM CPMS monitoring.

Comment 73: Commenter 17881 states that the PM CEMS should not be subject to the quality assurance tests required under sec tion 63.10021 (a)(11)(iv) because filter able PM is not the regulated pollutant and correlation testing will dictate operating inan abnormal manner for purposes of obtaining three different PM levels. Commen ter notes that this applies also to (a)(16)(vii) and (a)(17)).172 Response to Comment 73: The final rule does provide for the use of a PM CEMS to determine compliance with the filterable PM emission limit in the final rule if the source el ects to use this approach (see the final preamble for further di scussion). If this option is use d, the source must comply with the QA requirements in PS 11. However, PM CEMS are not required in the fina l rule. If the source uses the monitoring as a PM CPMS to demonstrate compliance w ith an operating limit, then the provisions of PS 11 do not apply, and the applicable QA/QC provisions will be as set forth in the monitoring plan required in the final rule.

Comment 74: Several commenters (19536, 19537, 19538) stat e the compliance provisions specify periodic performance testing in which the surrogate, regulated pollutants, and operating parameters are monitored for two cases: (1) no PM CEMS with PM controls and (2) no PM CEMS with no PM controls. The commenters state thatif a PM CEMS is used, regardle ss of whether the units is equipped with PM controls, no operational or non-Hg metal HAP monitoring is re quired except during an every 5- year performance test and that this is inadequate to determine con tinuous compliance. Further, it does not provide any testing for metals present as gase s or condensables. Thus, state the commenters, HAP such as selenium, which the EPA admits is frequently present in the gases, woul d not be measured either directly with Method 29 or indire ctly through a surrogate when PM CEMS is used to determine compliance. The commenters also state that initial performance compliance provisions are missing from Table 5 for PM CEMS.

Response to Comment 74: You may elect to comply with an optional operating limit for PM. If you use this method to demonstrate continuous complianc e, 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 (o r HAP metals inclusive of mercur y for liquid oil-fired units). The operating limit for demonstrating continuous complian ce 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 annua lly 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 provi de 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 me thod of compliance and no additional testing is required other than tests that are required as part of the QA requirements in PS 11.

15. Five-year test requirement.

Comment 75: Commenter 17798 states that stack testi ng once every 5 years to corroborate CEMS monitoring is a very long tim e period to rely on CEMS filterabl e PM data which may or may not relate to actual metals emissions. Therefore, the co mmenter feels this monitoring approach is overly complex, requires expensive CEMS monitoring, and ma y not demonstrate real metals emission levels for up to 5 years. The commenter requests that the EPA consider the following modifications: With the CEMS monitoring option, require stack testing every 2 years instead of 5 years to establish compliance with metal emission limits relative to filterable PM emissions. The commenter states that using a CEMS approach is premised on the EPA’s ability to estab lish a relationship between filterable PM and metals emissions on a sector-wide basis and sources with pa rticular control equipment may require adjustments to this method to account for wet conditions from wet scrubbers. The commenter asserts that under a CEMS monitoring approach the EP A should eliminate any requirementfor testing and setting of pollution control equipment operating parameters.173 Response to Comment 75: The comment is moot, as the rule doe s not require use of PM CEMS; PM CPMS are an alternative and annual testing is required to reassess th e operating parameter value. For those owners or operators who choose to use PM CEMS as an alternativ e, no additional operating parameter value monitoring or limit is necessary. Furthe rmore, in that case, the PM CEMS is used as the direct method of compliance and no additional testing is required other than test s that are required as part of the QA requirements in PS 11.

Comment 76: Commenter 17800 asserts that the EPA has not explained why there should be an independent filterable PM limitation that changes ev ery 5 years. According to the commenter, although it is reasonable to retest for comp liance every 5 years because of the innate variability of unit operation resetting emission limitation is not.

Response to Comment 76: The comment is moot, as the rule does not require the use of PM CEMS and PM emissions testing every 5 year s. Where a source uses a PM CP MS as part of its monitoring approach, annual testing is required to reassess the operating parameter value.

16. PM as surrogate Method 202.

Comment 77: Commenter 19114 states that using total PM as a surrogate has numerous technical challenges that demonstrating continuous comp liance using a filterable PM limit does not. The commenter states that filterable PM can be meas ured continuously througha PM CEMS monitor. According to the commenter, the variab ility of condensable PM in the fl ue gas is enormous and the test methods for condensable PM are still incapable of accurately measuring the c ondensate 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 unde rstand the limitations with the meas urement of condensables and to construct a test method that will be accurate and repeatable for in-stack measurements.

Response to Comment 77: While the agency disagrees with the suggestion that Method 202 is “incapable of accurately measuring the condensate in a replicable fashion routinely,” the comment is moot, as the final rule does not co ntain a total PM emissions limit.

17. Miscellaneous.

Comment 78: Commenter 17800 states that under section 63.10010(g)(3) the EPA is requiring a PM CEMS to “complete a minimum of one cycle of opera tion (sampling, analyzing, and data recording) for each successive 15-minute period.” According to th e commenter, depending on the PM CEMS used and the level of particulate emitted this may not be possible. For example, states the commenter, a system that uses a filter tape (dichotomous sampler) to measure filterable PM wh ere there is very low filterable PM levels emitted (similar to the proposed PM standa rd) may not be able to collect enough sample to adequately measure these emissions in this 15 mi nute timeframe. The commenter states that the EPA should allow some flexibility in this requirement to allow for m onitoring extremely low levels of filterable PM emissions.

Response to Comment 78: Measurement of condensable PM is not required in the final rule. PM CEMS are not required in the final rule.

Comment 79: Commenter 17752 questions, with respect to PS 11, whether it is possible to create or measure two PM levels between zero and the levels anticipated in the rule.174 Response to Comment 79: The rule now includes an option fo r using PM CPMS, whose use should alleviate the commenter’s concerns, as well as mainta ins the option for using PM CEMS. Note that other compliance options exist should an EGU owner or ope rator choose not to use PM CPMS or PM CEMS.

Comment 80: Commenter 17752 suggests that PM CEMS c ould be used 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 al so allows the use of PM CPMS, which involves establishing and maintaining a site-specific operating limit as an indicator of compliance, as another compliance demonstration option.

Comment 81: Commenters 17724 and 17876 state that the CEMS th e facility installed in preparation to CAMR have significant reliability and operationa l 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 me thodologies for demonstrating. Commenters 17724 and 17876 state the EPA purports to provide compliance flex ibility while in reality there is very little flexibility in light of the pr oblematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not commercially available to measure HCl emissions fr om coal-fired EGUs, and no HCl CEMS were used to collect the data the EPA used to establish the HCl standard.

Response to Comment 81: The agency disagrees with the comment ers. As mentioned elsewhere, the agency finds that the operation and maintenance issu es for the CEMS mentione d 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 w ith respect to compliance demonstra tion, containing numerous choices for compliance, including the use of em issions 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 continuousl y, that the HCl emissions limit was developed from emissions testing and has been adjusted to be ap propriate for measurement with HCl CEMS, and that emissions testing options to demonstrate complian ce exist for those EGU owners or operators who choose not to use CEMS.175 5A07b - Testing/Monitoring: Appl ication of multi-metals CEMS

Commenters : 17283, 17747, 19536, 19537, 19538

1. In favor of multi-metals CEMS.

Comment 1: Commenter 17283 recommends that multi-metal CEMS should be an allowed alternative for demonstrating compliance with the EPA proposed metals emissions limits. The commenter states that this recommendation is base d on the proven performance and commercial availability of multimetal CEMS, the fact that multi-metal CEMS repres ent substantially enhanced monitoring and PM is not an appropriate surrogate for HAP metals emissi ons in an increasingly complex energy extraction
process.

Response to Comment 1: In the final rule, facilities would be allowed to petition the Administrator under section 63.8(f) of subpart A of part 63for an a lternative to use of multi-m etal 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 re lationship of PM and non-Hg metal HAP.

Comment 2: Commenter 17747 states that multi-metals CEMS represent the highest level of monitoring for these sources (i.e., directly monitoring the HAP pollutant of concern on a continuous basis).

Response to Comment 2: Short term multi-metal CEMS demonstratio ns have historically shown, with appropriate QA/QC, that the data are accurate and re liable. Longer term operational information would be needed to support a proposal of performance speci fications. 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 incorpor ate language in the final rule expressly allowing the use multi-metals CEMS once a multi-metals performance specification has been promulgated. According to the commenter, the incor poration of this type la nguage would give source operators some assurance that monitoring with a mu lti-metals CEMS would be acceptable to the EPA, and it is also likely to encourage the use of multi-metal CEMS on sources, which is beneficial to the EPA’s understanding of the health effects associated with metal HAP. Finally, states the commenter, multi-metal CEMS would provide source operators with more feedback on control of metals and may allow them to optimize operations to minimize HAP metal emissions. The commenter provided information about the capabilities of their proprietary testing technology.

Response to Comment 3: We may in the future propose a multi -metal performance specification and QA/QC requirements but we have no immediate plan s to do so because we lack long term operational information and the resources to su pport a proposal. The final rule doe s reiterate the ability of a source to petition the Administrator under s ection 63.8(f) of subpart A of part 63for an alternative to use multimetal CEMS at a specific site in lieu of required m onitoring 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-me tal 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 monitori ng of all phases of all HAP metals is an enhancement over the monitoring of a surrogate (PM) for some urba n HAP metals. According to the176 commenter, periodic testing does not provide reas onable assurance of cont rol/prevention nor does monitoring PM provide reasonable assurance of urba n HAP metal control/prevention, and multi-metals CEMS is commercially available and accepted by the EP A. Thus, states the commenter, use of PM as a surrogate for HAP metals monitoring is no longer needed.

Response to Comment 4: We believe that the final rule doe s 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 co mparable 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 meta ls or PM. Should a source owner or operator elect not to use CEMS or the other instrumental methods, performance testing is required.

2. Individual metals.

Comment 5: Commenter 17283 states that monitoring onlythe vapor phase of Hg does not provide reasonable assurance of control/preve ntion under all conditions that are now to include SSM events. The commenter states that this is particularly the case when there is a proven and approved technology available that measures all phases of Hg. The commenter recommends the use of multi-metal CEMS as an alternative to Hg CEMS.

Comment 6: Commenter 17283 states that selenium does not meet two of the three court-defined criteria which must be met for PM to be a surro gate for HAP metals: “...HAP metals are invariably present in cement kiln PM...” (subsection 3.2.1); and “...PM control technology indiscriminately captures HAP metals along with other particulates.” (subsection 3.2.2.) According to the commenter, the addition of a condensable fraction to the definition of PM only complicat es this for other HAP metals.

Response 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 be low sulfur on the periodic table and is, chemically, very similar to sulfur. In the high temperature combustion environment, se lenium is likely to be present as gas phase SeO 2 (as, similarly, sulfur is like ly 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 com pounds in the fly ash effec tively neutralize the SeO 2 acid gas, forming a particulate that is easily remove d in the PM control device. Eastern bituminous coals typically 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 similarly to its sulfur analog, SO 2 , it can be expected to also be removed eff ectively 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 effectively 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 t echnologies. We specifically reviewed the Method 29 data from the utility boiler ICR where we had measured particul ate emissions, selenium emissions and selenium in the coal. In almost 90 percent of the facilities less than half of the estimated selenium was emitted. In the remaining facilities, we reviewed the location where selenium was collected in the Method 29 sampli ng train and found measureable am ounts 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 particulat e and/or acid gas controls.177 3. Concerns about use of PM as a surrogate.

Comment 7: Commenter 17283 states that reducing HAP metal concentrations from their current levels in feed and fuel to zero would essentially reduc e HAP metals to zero in the emissions (reducing HAP metals concentrations by many orders of magni tude) 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 th e case of scrubber soluti on bypassing demisters, or they may increase HAP metal emissions without increa sing PM, such as might be the case if trace HAP metal concentrations increase in an additive or other f eed material, or where an additive is injected into the process. The commenter states that without the direct monitoring of HAP metals, there will be no way to determine if the HAP metals are changing.

Response to Comment 7: While modifying the feed and fuel such that the HAP metal concentrations are zero would achieve essentially zero emissions, the EPA knows of no techniques which could achieve this end without transferring the emissions to another source. Also see responses to comments under Comment Code 4F01 for further discussion of relationship of PM and HAP metals.

Comment 8: Commenter 17283 states that Method 29 is co stly, dangerous, creates hazardous waste and is difficult to obtain accurate and reliable results at the low concen tration 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 us e plant operating parameters in CPMS. According to the commenter, as long as PM, fuel, and all contro l parameters remain relatively constant between Method 29 measurements, one might be able to assu me that HAP metals emissions have not changed dramatically since the last Method measurement, but it would be far less costly, far more informative and protective as well as more useful for plant oper ation if a multi-metals CEMS were used to measure HAP metals emissions directly and continuously.

Response to Comment 8: The EPA disagrees with the comment er’s opinion about EPA Method 29. We have found the method to provide reliable, low level, repeatable results whenproperly conducted in the field. The cost of using this method is actually much more economical, per analyte than many other test methods that the EPA employs to measure emissions.

Comment 9: Several commenters (19536, 19537, 19538) state th at total PM is not an appropriate surrogate for non-Hg metal HAP and those HAP can be accurately measured by CEMS. According to the commenter, if the EPA retains total PM as a su rrogate, 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 complia nce 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 tes ting using a manual PM method. The EP A also established an alternate equivalent standard for non-Hg metal HAPs, but the on-going monitoring w ith these metals is accomplished with a PM CPMS for an operational lim it or frequent testing with a metals manual method. Also see responses to comments in 4F01 of th is 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 discu ssion). 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 existing IGCC units to use SO 2 CEMS option.

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 mo nitoring 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 routin ely 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 Cro ss-State 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 rely on existing SO 2 monitors for acid gas compliance rather than incurring the cost of instal ling HCl monitors that have little or no long-term demonstrated “real world” reliability. The commenter requests that the SO 2 CEMS monitoring option be included for the existing IGCCs as a matter of equity and fairness. As these data are readily available to the EPA and interested public, there is no ba sis for the EPA’s preamble justific ation for not in cluding the option. While the commenter specifically references their IGCC unit, they do note that it is one of only two IGCC EGUs currently operating that are included in the existing IGCC category established by the proposed regulation.

Commenter 17191 requests that section 63.9991 be rewritte n 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 system upstream of the combustion of the syngas; the removed sulfur is captured and sold as molten sulfur for re use. According to the commenter, as the sulfur is removed prior to combustion no FGD technology is required for IGCC emissions. The commenter believes this Clean Coal Technol ogy should not be penalized (prevented from opting to use SO 2 monitors) because it uses an upstream technology for su lfur removal, eliminati ng 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 IGCC units can rely on the option of SO2 CEMS use. The commenter requests that the EPA amend other sections of the regulation, as necessar y, which may have been overlooked or that may be subject to revision before final rule i ssuance that would pr ohibit existing IGCC SO 2 CEM use.

The commenter suggests the followi ng modifications to section 63.9991:

“(a)(l)(i) You man not use the alternate SO 2 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 SO 2 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 insta lled on the unit at all times in order to qualify to use the alternated SO 2 limit. “ (Emphasis reflects propos ed 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 (SO 2 ) 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 clearly 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 allows for SO 2 monitoring in lieu of HCl monitoring of the exhaust of a wet or dry FGD unit is that the FGD pref erentially 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 wet or dry FGD. We are not aware that other sulfur control measures including pr e-control sulfur removal can be related to similar HCl emissions reduction. Further, the ru lemaking 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 certification.

Comment 3: Commenter 17677 states that section 63.10010( e) creates some confusion about certification of SO 2 CEMS. The commenter believes the prop osed 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 s ection 63.10010(e) add specific requirements to the general part 60 and part 75 requirements. No te 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 corre cted in the final rule.

Comment 4: Commenter 17402 objects to the lin earity test requirement for SO 2 monitoring. The commenter states that section 63.100 10(e)(6)(ii) of the proposed regul ations states that one “must perform the linearity check test requir ed in Appendix A to part 75 on the SO 2 CEMS whether or not it has a span of 30 ppm or less.” Acco rding 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 preamb le to the proposed 1998 revisions to 40 CFR Part 75, the EPA acknowledged that span at these low values loses its significance. Th e commenter believes the180 proposed requirements should be replaced with the Pa rt 75 exemption. According to the commenter part 75 requires EGUs to ensure that the analyzer span is set to obtain accurate and representative data. Part 75 also requires the owner or ope rator of an EGU to conduct an annual analyzer span and range evaluation to ensure that the majority of the analyzer readings are within 20 to 80% of span. According to the commenter, coupled with thes e requirements, the three linearity gas concentrations are more than sufficient to determine that the analyzer is linear. The commenter states that the proposed linearity requirement will add significant costs.

Response to Comment 4: The final rule has been amended to re move 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 confus ing why, despite using continuous SO 2 monitors successfully for more than 20 years, the EPA has proposed additional QA requirements. The commenter states that in proposed secti on 63.10010(e)(6) the EPA ha s added several problematic additional QA requirements for SO 2 CEMS that are not currently specified in Appendices A or B of 40 CFR part 75.

The commenter notes the following:

 Section 63.10010(e)(6)(i) – Accord ing to the commenter, the proposed Utility MACT rule would require the SO 2 CEMS to pass a 7-day calibra tion error test for units with spans less than or equal to 50 ppm and it is unclear whether the spec ifications 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 requir ement of 2.5 percent of span, and this will make passing the 7-day calibration erro r test significantly more burdensome. According to the commenter regardless of which specification is us ed, neither will improve the overall quality or accuracy of the collected data, since these are only implemented for initial certification or recertification even ts; in other words, there is litt le 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 addi tion of the linearity test will be an additional QA requirement for ma ny existing systems that have SO 2 CEMS installed downstream of a wet or dry scrubber, will add signi ficant cost to update software to integrate the new procedure, and potential costs to add the necessary hardware to existing systems to accommodate the new calibration gas cylinders, and will increase calibration gas costs, not only in the capital cost of purchasi ng 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 le vel equivalent to the applicable emission limit.” The commenter states that if a utility is requi red to include a fourth calibration gas level to the linearity check procedure, an additional cost in terms of hardwa re and software upgrades to integrate the fourth linearity calibration gas into the calibration syst em will be incurred by the utility. According to the commenter, this requirement is unnece ssary and will not improve the quality of SO 2 data being collected. The commenter states that curren t guidelines in 40 CFR Part 75 ensure that the majority of emission measurements made by an SO 2 CEMS fall within a ce rtain 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 ma intaining the ove rall integrity and accuracy of the SO 2 emissions being reported. At a minimum, st ates the commenter, the EPA should quantify the term “nominally” ( e.g ., a calibration gas within ±20 percen t of the equivalent concentration level).

Response to Comment 5 : The final rule will be amended to rem ove the 7-day calibration error test for units with spans less than or equal to 50 ppm and remove the four th calibration gas no minally 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 comply with HCl CEMS or peri odic HCl testing in lieu of updating their SO 2 CEMS system to check linearity quarterly.

3. Revisions to FGD applicability.

Comment 6: Commenters 17728 and 17775 support the EPA’s incl usion 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 th e option, wet or dry FGD technology must be operated “at all times.” The co mmenters state the EPA s hould clarify that this requirement is not intended to di squalify EGUs that experience SO 2 control device malfunctions or that must bypass controls during the init ial portions of startups or to pe rform maintenance (which generally require bypass of the entire control un it). The commenter states that fo r units without a bypass stack, any resulting emissions would be monitored in the main stack with the SO 2 CEMS; for units with a bypass stacks, temporary bypass might be necessary during a malfunction or to perform necessary maintenance to minimize periods of malfunction. According to the commenter, either way, as long as the SO 2 emissions are accounted for those em issions will reflect th e potential for higher HCl as well, and any unit complying with the 30-day rolling average SO 2 limit will achieve the necessary control for HCl (i.e., the acid gas HAP). Thus, the commenters belie ve the EPA should clarify that the “at all times” requirement does not apply to periods of malfuncti on, or to the temporary use of a bypass 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 states that the EPA should clarify that operation of FGD technology is only required for periods when the affected un it 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 start up/shutdown of the unit.

Commenter 17885 states thatfor the alternative SO 2 limit, the EPA should qualify that that “at all times” is not intended to disqualify units that e xperience control malfunctions or that bypass during startup/shutdown.

Comment 7: Commenters 18539 and 19120 note that section 63.9991(a)(1)(iii) indicates that the FGD must be operated at all times in orde r to qualify to use the alternate SO 2 limit to demonstrate compliance with the acid gas HAP emission limitation. The comm enters believe that if a unit can demonstrate compliance with the applicable SO 2 limit based on monitored emissions from the bypass and the182 scrubbed stack, a source shoul d be allowed to exhaust to the bypass stack, at least, on a limited basis, as many of these stacks are already equipped with SO 2 CEMS. One commenter note s that exhausting to the bypass stack is a necessary option in ma ny cases, and provides four examples.

Comment 8: Several commenters (17800, 17868, 18428) believe th e 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 maintena nce. The commenters note the higher SO 2 recorded by 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 existen ce of a bypass stack does not disqualify an EGU from co mplying 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 bypass stac k during startups or malf unctions as part of good engineering and maintenance should not disqua lify an EGU from this option. The commenter suggests the EPA could require sour ces to account for these periods as provided in 40 CFR section 75.16(c)(3), which requires use of a maximum potentia l value for each hour when the bypass stack is in

use.

Comment 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 belie ves that so long as a facility complies with SO 2 emissions limits, operators should have the flexibility to operate SO 2 controls in any mode to meet the compliance limit. The commenter recomme nds 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 th at demonstrates compliance with SO 2 limits, but whose SO 2 controls are not in co ntinuous operation, should not be consid ered in violation of the rule.

Comment 11: Commenter 17909 suggests the EPA s hould allow a 12-month rolling SO 2 limit and clarify that FGD bypass is allowed during times of FGD forced outage. The commenter believes these changes would allow very limited continued opera tion through the bypass during upset conditions.

Comment 12: Commenter 18023 believes that for PC units , the EPA should allow a scrubbed unit to bypass for a short time and allow the source to use the SO 2 monitors in the bypass stack. As written, the rule appears to require a unit withthe ability to bypass to install an HCl CEMS or otherwise monitor HCl on the bypass stack. If a unit that bypasses controls for a short period of time is capable of meeting the MACT SO 2 limit, then scrubber bypass should be al lowed. The commenter believes there is no environmental justification for penalizing these units.

Response to Comments 6-12: In the final rule, the EPA has clar ified the “at all times” language. The intent is that the FGD be operated during all boiler operations and not operated intermittently, seasonally, or on some other non-fulltime basis. Thus, this alternate limit is allowed even if bypass may occur during malfunction, but sources may be subjectto 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 shutdow n, as those terms are define d in the final rule, and the use of the FGD system must be in accordance w ith the work practice standards during those periods (i.e., the system must be engaged before coal or residual oil is bur ned in the boiler unit).183 4. SO 2 as surrogate.

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 gases cate gory of HAP. The commenter also appreciates the proposals reliance on the SO 2 CEMS as the basis of ongoing comp liance with the requirements. The commenter believes SO 2 emissions were well correlated with the acid gases in the analysis of the EPA ICR test data. SO 2 CEMS are used by the commenter to measure the emissions of SO 2 , and the commenter believes they produce accurate emission estimates.

Comment 14: Commenter 17758 believes there is no ba sis for testing of the surrogate SO 2 at a unit that is complying with the HCl standard or for HCl emi ssions testing at a unit with HCl CEMS. For example, states the commenter, proposed secti on 63.10006(h) requires EGUs “without SO 2 CEMS but with installed systems that use wet or dry flue gas desulfurization t echnology” 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 suggest s the EPA make clear thatthese 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 commenters (19536, 19537, 19538) endorses SO 2 CEMS methods to determine compliance, and believes they should be requi red, rather than presented as an option.

Comment 17: Commenter 17621 believes given the use of pulsed fluorescence analyzers, it is reasonable to expect that equipment will be available to measure SO 2 in the flue gas at the proposed alternative MACT limits for new and existing coal-fired EGUs (a pproximately 0.04 lb/MMBtu and 0.2 lb/MMBtu, respectively), even accounting for the d ilution extractive sampling systems. The commenter notes that at the emission levels typically found in power plants, the im pact of sample line losses has not been an issue and operators have minimal problem s meeting the 7.5% relativ e accuracy; however, when trying to measure very low concentrations, sample li ne losses may make the RAcriterion more difficult
to meet.

Comment 18: Commenter 17725 believes there is no value in performing Cylinde r Gas Audit (CGA) tests quarterly on SO 2 analyzers with span va lues less than 30 ppm SO 2 that are currently certified to report under 40 CFR part 75 rules. The commenter recommends the EPA add a subsection to section 63.10010(e) that clearly states that 40 CFR part 75 data substituti on 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 clarif y that provisions in section 63.10006(k) do not apply to EGUs with SO 2 CEMS that are used to meet requi rements 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 initia l 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 clearly 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 by 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 se ction 63.10006(j) requires EGUs “without HCl CEMS but with HCl emissions controls” to test for HCl at leas t every month, and proposed section 63.10006(k) requires EGUs “without HCl CEMS and without HCl emissions controls” to test for HC l 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 requireme nts applicable to EGUs “without HCl CEMS.” The commenter also notes proposed section 63.10005(a) also specifically requires HCl testing ini tially for any EGU that uses “a continuous monitoring system that meas ures 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.

Response to Comments 13 - 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 ag rees 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 concerns.

Comment 22: Commenter 17722 supports inclusion of 40 CF R part 75 monitoring provisions for SO 2 CEMS; however, the commenter does not support th e addition of new part 75 requirements. The commenter cites section 63.10010(e)(6), which requires additional provisions not currently needed for an SO 2 CEMS under part 75. The commenter notes that as a comprehensive monitoring rule, part 75 provides certified data within the means of the technology. The commenter notes these additional monitoring requirements were exempted from certainmonitor ranges because the monitoring technology is unable to perform the EPA method s either due to monitor limitations or due to protocol limitations. The commenter believes since current part 75 SO 2 collected data is accepted by the EPA as credible evidence of compliance with Acid Rain provisions , it should also be acceptable to the EPA for demonstration of compliance with the MACT standard without creating additional requirements as listed in section 63.10010(e)(6).

Comment 23: Several commenters (17725, 18014, 18498) suggest th at while the rule allows the use of Part 75 SO 2 CEMS, it includes additional QA/QC requi rements that will be problematic. The commenters reference section 63.10010( e)(6)(i), which states the ope rator “must perform the 7-day calibration error test required inAppendix A to part 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 part 75 affected sources has completed in itial certification years a go and has been collecting “quality-assured” data for years.

Comment 24: Commenters 17790 and 17820 have concerns w ith the linearity a nd 7-day calibration error test requirements contained in the proposal that are not required und er part 75. Commenter 17820 believes requiring these tests will complicate compliance for EGUs currently complying with part 75 and without providing any added accuracy to the measurement. Commenter 17790 suggests these requirements be removed for companies that plan to use their part 75 SO 2 CEMS. The commenter notes185 CEMS with a span less than 50 ppm are exempt from the 7-day calibration erro r and CEMS with a span less than 30 ppm are exempt from th e quarterly linearity testing and that CEMS are meeting the 7-day calibration error specification on a da ily basis during their daily calibra tion. The commenter also notes the EPA also determined that for CEMS with span s less than 30 ppm, the linearity testing was not significant at the lower emission leve l. 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 signi ficant cost and significant modifications to Data Acquisition and Handling Systems ( DAHS). In addition, the commenter notes part 75 already has existing requirements to ensure the monitor span valu e is set at a level to c over 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 requ ired in either 40 CFR parts 60 or 75 monitoring requirements, and the EPA does not provide adequa te justifications for increasing these QA/QC requirements beyond what part 75 requires. The commenter believes the fourth linearity calibration injec tion standard is overly burdensome to the industry.

Comment 26: Commenter 17775 believes no reason was provided for the requirements in the proposed section 63.10010(e)(6)(i) and (ii) that allows use of an SO 2 CEMS meeting part 75, but imposes linearity and 7-day calibration error test requirements not required under part 75. The commenter cites 67 FR 40394 and 40408-09 (June 12, 2002) in which the EPA speci fically exempted CEMS with spans of 50 ppm or less from the 7-day calib ration error requirem ent under part 75 because it was no longer necessary. The commenter also cites 63 FR 28032 and 28061/3 (May 21, 1998) where the EPA specifically exempted spans of 30 ppm or less from the linearity requirement in acknowledgment of the fact that the tests were no longe r significant at low emission levels . The commenter suggests if these tests are no longer relevant or sign ificant, there is no purpose in requiring them in this rule and that requiring the test will complicate compliance for E GUs currently complying with part 75 without providing any added accuracyto the measurement.

Comment 27: Commenters 17775 and 17820 believe the EPA pr ovides no rationale for this added requirement in proposed section 63.10010( e)(6)(iii) that require s a calibration gas at a level equivalent to the emission limit, even if that w ould result in a fourth calibration level. The commenters note part 75 already includes provisions to ensure that the analyzer span value is set at a le vel that will result in use of calibration gases that are consistent with the emissions range over which the unit operates, citing 40 CFR part 75, Appendix A section 2.1.1. The commenters believe there is nothing to be gained by potentially adding a fourth calib ration gas, and since existing SO 2 CEMS and the accompanying DAHS have not been certified using a f ourth calibration gas, and are not currently designed 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 requi rements, or issue for comment a proposal that provides some rationale for requiring these tests in this context.

Comment 28: Commenter 17821 strongly opposes the requireme nts in section 63.100 10(e)(6)(iii) to introduce a fourth concentration le vel of calibration gases during the initial and subsequent quarterly linearity audits. The commenter states the EPA app ears to be imply that more accurate measurements would be obtained by the SO 2 monitoring system if the fourth le vel of calibration gases was added; however, the commenter believes no additional accu racy 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 comme nter also believes it w ould also necessitate the invalidation of hourly data during the injection of the linearity ga ses. The commenter notes that by186 adding the fourth gas injection leve l, sources would be forced to inject gases for approximately 40 minutes (10 minutes for each of the four gas concentr ations); when the 5-7 minutes required to reach a stable stack gas reading are a dded to that total, sources w ould not collect enough valid stack measurement minutes within an hour to validate the hour. The commenter therefor e believes this process would result in approximately 2-3 hours of invalid data each and every quarter.

Commenter 17821 additionally states the alternative limit when using an 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 conc entration or percent concentration, not as a value expressed in lb/MMBtu. The commenter believes to require a s ource to evaluate an SO 2 or diluent monitor for linearity at a fourth concentr ation level “nominally at the concentration level equivalent to the applicable emission limit” would be extremely subjective. The commenter states that concentrations 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 inthe air excess flowwould result in a change to the nominal equiva lent values for the test.

Commenter 17821 continues to state that sources currently using SO 2 monitoring systems in compliance with 40 CFR 75 are required to develop span ranges that capture the majorityof 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 ma jority of nominal readings at approximately 50% of that span range. 40 CFR 60 and 40 CFR 75 cylinder ga s audits and linearity audits already require a source to inject a gas in the range of 50% to 60% of the span range of the monitor; therefore, an injection of audit gas in the “nominal” range of measurement is typically performed. Additionally, stat es the commenter, all sources equipped with SO 2 emission control systems utilize dual range SO 2 monitoring systems (as required by both 40 CFR 60 and 40 CFR 75). The commenter believes performing a linearity audit with a fourth injection level on the high range of the SO 2 monitor at the “nominal ly at the concentration level equivale nt to the applicable emission limit” would be meaningless as the hi gh range of the monitor is not intended to measure low level concentrations but is designed to m easure higher concentrations in the event of a malfunction or upset of the SO 2 emission control system. The commenter be lieves very low concentrations of SO 2 will dictate very low range measurement on these dual range analyz ers, which will make passi ng a linearity test very difficult. The commenter states thatthe standard is percent of the reference value, which may put the error limits inside the accuracy st andards for the reference gas. The commenter states that part 75 provides a waiver for linearity tes ting of ranges less than 50 ppm and an alternate standard for ranges less than 200 ppm. The commenter recomm ends that these be allowed for the SO 2 surrogate measurement as well, which will also serve to av oid maintaining separate databases for CSAPR and MACT purposes.

Comment 29: Commenter 17881 believes the restrictions an d caveats placed on the use of part 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 condu cted on low-level emissions monitoring systems (i.e., systems with span values of less than 50 ppm or 30 ppm, as applicable) make little sense, as the EPA has already evaluated the utility of conducting such tests under 40 CFR part 75 and concluded that these tests were not appropriate for level-level emissions monitoring systems.

Commenter 17881 believes the provisions of section 63.10010(e)(iii) which would also require that at least one calibration gas level used for the linearity tests have the same nominal concentration level equivalent to the applicable emission limit (and that a fourth such gas be usedif none of the required low, mid or high gases meet this requirement) are nonsensical, as the vast majority of part 75 SO 2187 CEMS installed on un its with add-on SO 2 control devices will be dual-range instruments. As such, states the commenter, the high level range of these in struments will generallybe 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 emission 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 sect ion 63.10010(e)(6)(iii)) would be a prohibition on the use of a default high range value as allowed unde r 40 CFR part 75, Appendix A, section 2.1.1.4(f) for those dual span units with SO 2 emissions controls. According to th e commenter, this would essentially ensure that any EGU which elects to comply with a surrogate SO 2 limit (which inherently requires addon 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 ga s with a concentration no minally 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 by boiler operating loads and the resulti ng diluent gas levels and electrical outputs. The commente r provides an example for a subbituminous boiler and questions that given the concentration e quivalent of a given SO 2 emission limit is influenced by boiler operating conditions, how could a nominally e quivalent concentration even be determined with any level of certainty. The commenter also questions what is no minally equivalent in th e context of the example provided.

Comment 30: Commenter 17902 believes section 63.10010(e)(6)(i) thru (iii) will require additional calibration error and linearity check tests that are not currently required under 40 CFR part 75 and are not necessary and may not even be feasible due to in stability of calibration gase s 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 guida nce in the existing federal regulations for 40 CFR part 75.

Comment 31: Commenter 17868 suggests the EPA allow all pa rt 75 exceptions. The commenter notes proposed section 63.10010(e) allows use of an SO 2 meeting part 75, but disa llows 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 63.10010(e), except this provision does not reference the part 75 option. One commenter suggests the EPA reference the part 75 alternative in this pr ovision as well, or consol idate the two provisions.

Comment 33: Commenters 17725 and 18498 note that section 63.10010(e)(6)(ii) states that one “must perform the linearity check test required in appendix A to part 75 on the SO 2 CEMS whether or not it has a span of 30 ppm or less”; how ever, this requirement ignores the EPA’s previous acknowledgement that a linearity check “begins to lose its significan ce” at span values less th an or equal to 30 ppm as discussed in the proposed 1998 revisions to 40 CFR part 75. One commenter provides an example and proposes the requirement should be removed a nd replaced with the part 75 exemption.

Comment 34: Several commenters (17725, 18014, 18498) refe rence section 63.10010(e)(6)(iii), which states “the initial and quarterly linearity checks required under Appe ndix B of Part 75 must include a188 calibration gas (at a fourth level, if necessary) nominally at a concen tration level equivalent to the applicable emission limit.” The commenters see no r eason to introduce a fourth calibration gas and the term “nominally” is not clearly defi ned. The commenters state that part 75 has requirements in place to ensure that the analyzer span is set to obtain accurate and repres entative data. Commenter 17725 notes this requirement will significantly increase SO 2 CEMS operating cost as th e system will need to be modified to include an additional regulator, the D AHS 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 wh at “if necessary” means in section 63.10010(e)(6)(iii) in regards to conducting linearity check s at a fourth level. Th e 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. According to the commenter, any emission limit will reside in the lower range of a dual range analyzer, which is typically a narrow range to begin with. The commenter believes this requirement is “ not necessary” and would only add complications and costs to an already accurate and sound system.

Comment 36: Commenter 17821 supports the EPA’s inclusion of the option to operate, maintain, and quality assure an SO 2 monitoring system under 40 CFR 75 if the source operates such a system for compliance with Acid Rain.

Comment 37: Commenter 17886 suggests the EPA harmonize the SO 2 CEMS requirements with part 75 as most if not all EGUs should already have thes e systems in place meeting part 75 requirements. The commenter believes failure to harmonize monito r 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 shoul d include the alternativ e to use Part 75 require ments for “installation”, “operate”, and “maintain CEMS.” ( See section 63.10010(e).) The comment er 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 part 75 monitoring systems to the data reduction procedures in section 63.10010( e)(4), as these procedures are in part inconsistent with the part 75 data reductions procedures at section 75.10(d). The commenter cites the re quirements from section 63.8(g)(2) and section 75.10(d)(2), noting that wh ile the language appears similar, itcould still result in different data validation cases where maintenance or quality activities are conducted in a given hour and only two data quadrants are used to validate the hour. For example, states the commenter, if an unit operated for 60 minutes in a given clock hour and collected valid 1-minute values at minutes 14 and 15 due to quality assurance activities, su ch an hour would be valid under the provisions of sec tion 63.10010(e)(4) but invalid under the 40 CFR 75.10(d)(1) provisions. Th e commenter believes forcing part 75 subject sources to maintain two separate sets of data based upon two diffe rent validation regimes is overly burdensome and unwarrante d, and suggests part 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 part 75 missing data shall not be used in calculating the 30 boiler operating day average SO 2 emission rate. According to the co mmenter, although this is discussed in Appendix A to subpart UUUUU for Hg CEMS (Ref erence 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 22 - 40: After reviewing the comments and assessing the need for a “nominal” gas for the linearity test, the EPA has removed this requirement from the fina l rule while retaining a requirement for a linearity check even for low SO 2 concentrations. Sources canalready report linearity tests for these units within the c ontext of the existing ECMPS reporti ng without triggering any critical errors regardless of the test results. This test can be accommodated within the current framework without causing issues for part 75 reporting. The 7-day calibration erro r test is removed as unnecessary. As noted elsewhere in this response to comments document, the final rule confirms that the bias adjustment and substitute data provisions under part 75 do not apply when using an 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, 17800, 17813, 17820, 17821, 17851, 17868, 17881, 17886, 18014, 18037, 18443, 18539, 19114, 18023

1. HCl CEMS is not proven technology.

Comment 1: Numerous commenters (17383, 17402, 17681, 17696, 17704, 17705, 17715, 17718, 17724, 17728, 17729, 17627, 17638, 17769, 17775, 17790, 17795, 17813, 17820, 17868, 18037, 18443, 18539, 19114, 18023) note concerns with HCl CEMS technology.

Comment 2: Commenter 17402 recommends that the EP A 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 HC l 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 comme nter 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 ar e in production and questions if there are any HCl CEMS that work.

Comment 5: Commenter 17696 states that while the EP A 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 consisten tly and reliably measuring HCl levels expected in the stack gas of EGUs.

Comment 6: Commenter 17704 believes the technology for HC l CEMS is not fully developed or proven for EGUs. The commenter understands that stack testing for HCl every month is offered as an alternative, but scheduling testing that often is difficult and not pr actical; therefore, that really only leaves the choice of HCl CEMS. The commenter believ es that HCl CEMS have been used to measure higher concentrations for other indus tries; 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 fo r use on wet stacks, noting concern that many EGUs plan to use wet FGD technology to comply with the proposed acid gas standards. In addition, states the commenter, information provided by EPRI indicates th at the proposed HCl standard may be lower than the quantitation limit of the two types of instruments currently available for HCl measurement. If the EPA retains a numeric HCl standard in the final ru le, the commenter encourages the EPA to take a leadership role in assuring that th e monitoring methodology that is requir ed is actually available for use across a broad range of plant config urations and can reliably demonstr ate compliance with the standard.

Comment 8: Several commenters (17718, 17627, 17715, 18037, 18539) state HCl CEMS currently are not commercially available or adequate for in-stack measurements and likely will not be available by the compliance date of the rule. The commenters believe sour ces will be forced to either take a fuel limit or191 an operating parameter limit. The commenters state the fu el analysis limit is impractical as it relates to a coal-fired facility because of the variability that is inherent in coal, and that it will be impossible to control fuel deliveries in such a manner as to negate the possibility of burning co al with chlorine content above that which was used during compliance testing.

Comment 9: Commenters 17715 and 19114 state HCl is not r outinely monitored by EGUs, and there is little stack test data beyond that collected by the EPA during the ICR pr ocess. The commenter states that no HCl continuous monitors were used to collect any of the data used by the EPA to establish the HCl standard, and there is no inform ation about HCl emissions at condi tions other than normal full load operations, but nevertheless, the EPA proposes to re ly on continuous HCl monitors as its preferred monitoring method for compliance. The commenter belie ves 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 deve loped. The commenter note s 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 unreliabl e in stack applications, especiallyat emission rates as low as the EPA has proposed. The commenter recommends the EPA should not dictate FTIR as the technology to be utilized.

Comment 10: Several commenters (17383, 17724, 17820) are conc erned that HCl monitors are not a proven option in the electric utility industry. According to the commenters, while these monitors exist and have operated on other sources, the electric utility sector presen ts distinct challenges. Commenter 17724 questions the need for SO 2 monitoring in addition to parame tric 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 abil ity of HCl CEMS to accurately measure compliance with the proposed standard.

Comment 12: Several commenters (17728, 17775, 17820) belie ve 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 comm enters believe that currently, HCl CEMS are not capable of measuring accurately atconcentrations below 2 ppm.

Comment 14: Several commenters (17775, 17868, 17820) are c oncerned about the ability of HCl CEMS to accurately measure compliance with the propos ed 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 sour ces with different temperatures, moisture and gas conditions. The commenter notes its own experience with si gnificant 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 r eactivity of HCl, makes obtaining reliable measurements a difficult task. Th e commenter identifies the three basic HCl CEMS192 configurations and discu sses technical issues with each. The co mmenter describes sample conditioning problems associated with extractive systems, diff iculties with representative measurements and operation and maintenance (O&M) problem s for in-situ instruments, and NH 3 interactions with HCl creating problems for dilution sampling systems. The commenter also discusses the MCS 100 E Multi Component Analyzers as the most widely employe d and presumably most advanced HCl CEMS and notes issues with detection limits associated with the use of the un it. The commenter believes there are substantial technical ques tions regarding the use of HCl CEMS, a nd the EPA should not require them as part of the EGU NESHAP.

Comment 17: Commenter 17795 believes that HCl CEMS are notan option at the proposed levels with a certification performance specification that has a known nega tive bias. For existing units, states the commenter, an HCl standard of 0.002 lb/MMBtu equa tes to 1.2 ppm (assuming a heat rate of 10,000 Btu/kW). The commenter believes while this valu e is above the detection limit it will be extremely challenging to demonstrate compliance through a c ontinuous HCl emissions monitor. For example, states the commenter, the lowest achievable emissi on 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 analysis. The commenter notes th eir industry has more than 30 years of experience monitoring NO X and limits of 2.0 ppm are challenging to dem onstrate on a continuous basis. According to the commenter, measuring a highly water soluble co mpound 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 accu racy of HCl CEMS do not justify the difference in emission reduction measurements produced by a performance test and continuous compliance metrics. The commenter suggests HCl CEMS were developed for sources with much greater HCl emissions than EGUs and as such do not provi de precision and accuracy at the range they are expected to operate. Additionally, states the commen ter, the HCl standard does not take into account chlorine variability in coal. The commenter reco mmends instead of effectively mandating HCl CEMS, EPA should allow sources to comply with HCl limits through an annual performance test, in conjunction with documented pr ocess metrics.

Comment 19: Commenter 19114 notes that HCl is not routin ely monitored by electric generating units, and there is little stack test da ta beyond that collected by the EPA during the ICR process. No HCl continuous monitors were used to co llect any of the data used by the EPA to establish the HCl standard, and there is no information about HCl emissions at c onditions other than the limited data available for normal full load operations. The commenter believe s 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 deve loped. The EPA states that FTIR has been shown to be adequate for in-stack measurements. However, FTIR has been shown to be unreliable in stack applications, especially at emission rates as lo w as the EPA has proposed. Given these (and other) uncertainties regarding FTIR performance, the commenter believes th e EPA should not dictate FTIR as the technology to be utilized. The commenter provides several exampl es of concerns expressed by agencies regarding the use of HCl CEMS, including ex cerpts from state agenci es in their Response to Comments document that supported th e 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 di ode laser (TDL) based device. The commenter states TDL is not the EPA’s preferred FTIR technology, so there is no performance sp ecification av ailable for it. The commenter states that this existing TDL de vice also uses the open path measurement approach193 and, as such, does not lend itself to daily QA/QC procedures typical of the power plant CEMS equipment that meets Part 75 requirements. Accord ing to the commenter, the current technology (FTIR) used for stack testing is not very rugged; sample tr ansport issues may require HCl CEMS analyzers to be stack mounted, which will provide a maintenance and availability challeng e. According to the commenter, most analyzers require stable temperatur e 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 stat es that NIST does not have any HCl standards, and the lowest concentration of EPA Protocol HCl gas advertised by a gas vendor is 25 ppm. The commenter states that that value is based on gravim etric (weight) traceability, and converted to ppm, the limit in the proposed rule is approximately 1 ppm. A ccording to the commenter, this limit may be below the quantitation limit (QL) of the available inst ruments and thus would not be measureable.

Response to Comments 1-21 : The EPA disagrees with commenters’ co ntention that continuous HCl monitoring is premature or not ava ilable for the measurement at the li mits set in the proposed standard. We understand from vendors of HCl CEMS that theyhave been used on sour ce categories such as municipal waste combustors, cement plants, and bi omass and other power generation units. We have reviewed HCl CEMS vendor technology claims and f ound sufficient capability to support this rule requirement. We are presently engaged with repr esentative stakeholders to develop a generic performance specification for HCl CEMS. The HC l Performance Specification is scheduled for completion in time to be responsive to this rule pr omulgation. To use the HCl CEMS option at the start of the program, the EPA has included a comparable performance specificati on PS 15, using a Fourier Transform Infrared (FTIR) analyzer , which could be employed in the event that the issuance of PS for HCl CEMS is delayed. Should an EGU owner or ope rator be concerned aboutusing HCl CEMS as a compliance demonstration method, other options exis t for acid gas HAP monito ring including: 1) using HCl CEMS for compliance, 2) se eking approval for an alternativ e 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. Including these options in the rule provides flexibility to adopt CEMS monitoring op tions as the technology continues to mature and EPA performance specifications become available.

Comment 22: Commenter 17622 states they recognize the reluct ance of the utility industry to proceed with plans to measure HCl because 1) They know it can be difficult to measure in low concentrations; 2) The technologies used for it such as FTIR, TDL or Perma Pure driers with GFC analyzers are unfamiliar to them; 3) The EPA has not published performance specifications for HCl measurement leading to some uncertainty. The commenter believes that if electric generating facilities can identify a reliable, low-maintenance, affordable option for low level HC l measurement (0-10 ppm), they will adopt it more readily. The EPA should help try to prove this point out over the coming months.

Response to Comment 22: The EPA acknowledges that certain app lications of HCl CEMS will require further demonstrations and advances for this technology and is currently working on HCl PS for technologies other than FTIR.

2. Concerns over lack of performance specification.

Comment 23: Multiple commenters (17402, 17638, 17681, 17696, 17716, 17728, 17729, 17769, 17800, 17820, 17821, 17851, 17868, 17881, 17868, 17881, 17886, 18014, 18023) express concern that the agency has not made available perf ormance specifications for HCl CEMS.194 Comment 24: Commenter 17402 states the absence of such re quirements makes it difficult for regulated units to comment on how they might comply with th e proposed QA/QC specifications in the context of the Utility MACT rule.

Comment 25: Commenter 17696 believes it is premature and inappropriate for the EGU NESHAP rule to specify the use of HCl CEMS given that the EPA has not yet promulgated a performance standard specific to HCl CEMS. Without the existence of an accepted performance sp ecification for HCl CEMS in advance of the compliance dates, the commenter believes EGUs cannot reas onably be expected to purchase and install HCl CEMS and rely on them for compliance determinations.

Comment 26: Several commenters (17716, 17820, 18014) state the EPA has developed no performance specification for non-FTIR based HCl CEMS. Table 5 lists PS 6, but the commenters believe PS 6 does not apply since it is for systems th at measure pollutant emissions in units of mass per unit of time. The commenters state the lack of a performance specifi cation for HCl CEMS (coupled with limited utility HCl CEMS operating experien ce, particularly for compliance near the detection limits of the systems) makes it difficult to provide meaningful comments.

Comment 27: Commenter 17729 recommends the EPA should not require compliance monitors for which an EPA performance sp ecification does not exist.

Comment 28: Several commenters (17775, 17795, 17800, 17868) note that the EPA proposes to require certification of HCl CEMS according to PS 15 or PS 6. The commenters state that as the EPA acknowledges in the preamble, PS 15 applies only to FTIR CEMS. PS 6 applies to continuous emission rate monitoring systems (“CERM”), which measur e mass emissions rate per unit of time, not conventional CEMS. The commenters note FTIR CEMS is not a viable option and sources need a well documented HCl performance specification well in advan ce of the compliance date in order to evaluate and procure appropriate instrumentat ion. The commenters state that in order to provide an HCl CEMS option, the EPA says “we expect to publish (a performance specification) prior to the compliance date of this proposed rule and to make it available to source owne rs and operators” (76 FR 25031). The commenters believe in the absence of an existing speci fication, the EPA should recognize in the rule that PS 15 does not apply to HCl CEMS.

Comment 29: Several commenters (17775, 17795, 17800, 17820, 17868) support the EPA’s decision to convene a workgroup of interested stakeholders to aid in development of an appropriate performance specification. The commenters suggest the EPA a llow EGUs to petition the EPA for use of an alternative specification if none ha s been promulgated by the time EGUs need to make decisions about their compliance options.

Comment 30: Commenter 17868 notes they supports the op tion for use of HCl CEMS and urges the EPA to complete work on a reason able performance specification.

Comment 31: Commenter 17886 recommends th at the EPA make HCl CEMS monitoring requirements contingent upon issuance of an HCl CEMS performance specificati on, as an HCl CEMS Performance specification is not currently available and the EPA has set the proposed HCl lim its near the detection level of current technology. The commenter also belie ves, since the proposed lim its are lower than the quantification limits of current technology, HCl CEMS should only be used for purposes of CAM.

Comment 32: Commenter 17881 has generally heard that the FT IR technology associated with PS 16 is not a viable option at this point in time due to concerns about detection limits in EGU exhaust gas195 matrices, potential measurement issues in wet stack environments, lack of low-level calibration standards, etc. The commenter sugge sts that until such time as th e 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 no tes it is possible that new EGUs may face a compliance date as early as 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 33: Commenter 17769 notes that there are no performance specifications or quality-assurance provisions for HCl CEMS and the co mmenter is not aware of any FTIR HCl CEMS currently in use in the U.S. on a coal-fired EGU. The commenter notes th at currently no federal regulations require the use of HCl CEMS without express exemptions, alternatives and caveats. The commenter provides examples including the Portland Cement NESHAP, CISWI NSPS and the proposed NESHAP for Polyvinyl Chloride and Copolymer Production. The commente r cites several rulemakings in which the EPA expressed various reasons for its he sitation to require the use of HC l CEMS, including lack of data, significant costs, and lack of performance specifi cations. The commenter believes the EPA’s rationale for not adopting performance specifi cations (specifically, PS-13) is th at the EPA could not demonstrate that an HCl CEMS would meet the specificati ons, citing 64 FR 52828, 52930. The commenter believes there is no certainty over the suitab ility and reliability of HCl CEMS and that the EPA must provide public notice and an opportunity fo r comment on any specifications prio r to EPA requiring them as part of any rule.

Comment 34: Commenter 17821 encourages the EPA to a llow the use of alternate HCl CEMS performance specifications so the choice of HCl CEMS is not limited to FTIR monitoring systems. The commenter believes that because the FTIR is not a practical monitoring option, using an HCl CEMS is not a realistic option for companies to consider 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 frequenc y. The commenter believes FTIR CE MS are difficult to calibrate and maintain. They typically require a le vel of expertise to set up, operate, an d maintain that is far above the typical CEMS technician found at a power generati on facility. The commenter notes that some states, including Indiana and Pennsylvania, have approved the use of altern ate performance specifications for HCl CEMS on hazardous waste incinerators allowing the use of HCl CEMS other than those based on FTIR methods.

Comment 35: Commenter 17851 believes the EPA should not apply PS 15 to HCl CEMS, but should promulgate a PS specifically designed for these in struments. The commenter notes most commercial HCl CEMS use some form of infrared light atte nuation to measure HCl concentrations and that requiring HCI CEMS to use PS 15 is simply not a ppropriate. The commenter believes the EPA should promulgate a performance specifi cation 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 HC l CEMS. The commenter s uggests that these CEMS should not be required until a performance specifica tion for these types of units is promulgated. However, if the agency decides to require these CEMS , the commenter believes th ere is a better interim solution than PS 15. The EPA has alr eady approved two preliminary ot her test methods for HCl CEMS, OTM 22 and 23. The commenter believes that it makes more sense to te mporarily use a preliminary test method already approved for HCl CEMs than to use an already promulgated performance specification that may not apply. The commenter s uggests that the EPA modify the final rule to allow the use of OTM 22 and 23 instead of PS 15.196 Comment 36: Commenter 18023 believes it is inappropriate to require HC l CEMS without appropriate industry practice demonstrating their availability and without a relevant Pe rformance Specification.

Commenter 17775 states that the EPA must provide a reasonable perf ormance specification for HCl and HF CEMS in time for EGUs to make decisions regarding compliance options.

Response to Comments 23 - 36: See Response to Comments 1-21 under 5A09 of this document.

3. Proposed alternatives.

Comment 37: Commenter 17704 believes as an alternative, a stack test emission factor based on an annual stack test would be more appropriate for their Powder River Basin (PRB) subbituminous coal units. According to the commenter, the amount of chlo rine in the PRB coal th e 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 addi ng an option that would have an alternative for using a stack test emission factor in stead of HCl CEMS, as long as, the fuel utilized by the unit does not change during the year. The commenter states that if a new fuel is intr oduced a new stack test could be required.

Response to Comment 37: The rule provides an alte rnative to an HCl CEMS based on periodic stack testing. See section 63.1006(j) and (k ). The required testing frequenc y is more frequent than the suggestion made by the commenter.

Comment 38: Commenter 17728 recommends that if no perf ormance specification is forthcoming by the time decisions about complian ce options need to be made, the EPA should allow EGUs to petition for use of an alternative specification.

Response to Comment 38: Sources may petition for an alternativ e specification consistent with the provisions of section 63.7.

Comment 39: 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 analysis as a continuous compliance option, and that the EPA should notcategorically create secondary compliance monitoring.

Response to Comment 39: If an SO 2 CEMS is used consistent with the alternative SO 2 limit included in the rule, no parameter m onitoring 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 41: Commenter 17402 suggests in the alternative th at facilities be permitted to utilize monthly fuel sampling coupled withperiodic stack testi ng to meet monitoring compliance obligations.

Response to Comment 41: The final rule eliminates the fuel sampling option. A source may use an SO 2 CEMS where an FGD is installed, may use HC l CEMS, or may conduct periodic testing to demonstrate compliance.197 Comment 42: Commenter 17696 believes until the EPA de velops 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 a lternative monitoring method in accordance with 40 CFR 63.8(f).

Response to Comment 42: The EPA has set forth PS 15, which uses a Fourier Transform Infrared (FTIR) analyzer as an acceptable alternative fo r HCl CEMS performance sp ecifications. Sources may seek alternative specific ations through section 63.7. See also Response to Comments 1-21 under 5A09.

Comment 43: Commenter 17775 suggests that in the absenc e 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 sp ecification if none has been promulgated by the time EGUs need to make decisions about their compliance options.

Response to Comment 43: See response to Comment 42, directly above.

Comment 44: Commenter 17621 believes there are three likely candidate technologies for continuous measurement of gas-phase HCl: FTIR, tunable diode laser (TDL), and gas filter correlation (GFC); however, there is little or no experience with any of these technologies on EGUs, although all three have been used in Europe on municipal waste incinerators. The commenter states that the EPA has approved a reference method using FTIR for HCl in cement pl ant 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 th e commenter, all of these technologies operate in the near infr ared range and are to some extent subject to interference from water vapor, but both FTIR and TDL systems ar e able to resolve this interference.

The commenter notes with increasing measurement path there is a tradeoff between increased sensitivity and loss of signal strength. Accordin g to the commenter, particulate and entrained droplets in the flue gas can degrade the signal strengths in an in situ a pplication in wet stacks, and demonstration of in situ techniques in a wet stack environment needs to be c onducted. An alternative appr oach is to extract a gas sample and measure HCl. The commenter states th at sample transport in a hot, wet flue gas is problematic and would require multipass measurement cells to achieve sufficient path length for the required sensitivity. Currently, states the commenter, the only installation on a U.S. EGU is an in situ TDL on a dry stack, and in that app lication, there was sufficient intensit y to measure HCl and to identify process variations. The commenter st ates 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 pr oblems 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 in clude: (1) Determine detection and quantitation limits; (2) Quantify interferences of likely species in flue gas; (3) Validate CEMS in a wet stack; (4) Develop alternative extractive sampling techniques; (5 ) Develop low-level calibration standards; and (6) Develop and validate an EPA performance specification.

Comment 45: Commenter 17725 suggests HCl CEMS should not be limited to FTIR monitoring methodology as HCl CEMS based on FTIR technology te nd to be very expensive to maintain and are labor intensive. The commenter suggests newer tec hnologies such as Tunable Diode Laser Spectroscopy (TDLS) and Ion Mobility Spectroscopy (IMS) are showing great promise as a suitable replacement for selective gas components such as HCl and HF.198 Response to Comments 44 - 45: The EPA acknowledges that certain applications of HCl CEMS will require further demonstrations and advances for this technology. The agen cy 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 detecti on 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 sugge sts 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 ope rators setting injection limits based on performance testing with a higher reactivity sorb ent and later substituting a lesser quality sorbent, compliance with the HAP limit could be jeopardized. To avoid this pot ential issue the commenter recommends the use of CEMS technology to facilitate ongoi ng HCl emissions compliance. The commenter also recommends at a minimum, if injection rate limits are utili zed, reagent reactivity s hould also be specified.

Comment 47: Commenter 17756 supports the EPA’s selection of HCl as a surrogate for the other acid gas HAP. The commenter also agrees with the EPA’s proposal to allow EGUs the option of meeting an alternative SO 2 limit, if a unit uses a CEMS devi ce to demonstrate compliance with SO 2 limits. According to the commenter, as drafted, proposed section 63.9991(a)(1)(i) lim its 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 46 - 47: The EPA notes the commenter’s support for use of an HCl CEMS. As for the reagent reactivity concern, the general requirements for testing require that the tests be conducted under normal conditions, which would include using the same quality sorbent duri ng testing as is used during operations. This type of deliber ate violation of the regulations is considered unlikely as a general concern, and will be best handled through effective co mpliance 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 concerns.

Comment 48: Commenter 16513 notes that PSEG Bridgeport Har bor 3 is required to comply 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 Indone sian coal. As a result, states the commenter, PSEG Bridgeport Harbor 3 currently meets the Utility NESHAP’s SO 2 limit of 0.20 lb/MMBtu for coalfired EGUs. The commenter states that under the Utili ty 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 th e installation of HCl CEMS.

Response to Comment 48: The use of the SO 2 alternate equivalent standa rd 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 c ontrol device. In the situation de scribed, 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 49: Commenter 17718 believes that within the proposed regulatory language of 40 CFR 63.10006, there does not appear to be an option for reduced HCl perf ormance testing requirements on coal-fired units with non-HCl c ontrolled bypass stacks. The commenter identifies a facility that is currently configured to send its em issions to a common wet FGD shared with Unit 1 and 3 at the same facility. The common emissions are then emitted thr ough a common stack. The commenter states that all three units are affected coal-fired units designed to burn greater than 8,300 BTU/lb coal, but Unit 2 is also configured and permitted to utilize a bypass stack. According to the commenter, within the proposed language of 40 CFR 63.10010(a)(4), it appears th e facility’s bypass stack would be required to install similar monitoring systems as the ma in common stack, but without FGD technology on the bypass stack, it appears that the current 40 CFR part 75 SO 2 CEMS located on the bypass stack could not be used for compliance determin ations as a surrogate for HCl. Fu rthermore, states the commenter, even if the company desired to install an HCl mon itor on the dry stack to m onitor emissions, it would still be required to conduct performa nce testing every month because there apparently is not an option to allow HCl monitoring under 40 CFR 63.10006(i)-(k) to cover a non-HCl controlled unit/stack.

Response to Comment 49: The EPA has modified the require ments for monitoring a bypass stack. Under the final rule, the inst allation of a monitor on a bypa ss stack is not required.

Comment 50: Commenter 17881 suggests section 63.10011 (b)(1), relating to establishment of a maximum chlorine fuel input, s hould only apply to units which are not complying with the SO 2 surrogate or are not re lying on an HCl CEMS.

Response to Comment 50: Under the final rule, no fu el input operating limits apply. The source may be required to conduct a new performance test where ther e is a significant change in fuel use that could result in emission increases.

Comment 51: Commenters 17724 and 17876 state that the CEMS th e facility installed in preparation to CAMR have significant reliability and operationa l 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 me thodologies for demonstrating. Commenters 17724 and 17876 state the EPA purports to provide compliance flex ibility while in reality there is very little flexibility in light of the pr oblematic and unproven nature of these monitoring technologies.

Commenter 17736 states the EPA cannot rely on unproven HCl CEMS, that HCl CEMS are not commercially available to measure HCl emissions fr om coal-fired EGUs, and no HCl CEMS were used to collect the data the EPA used to establish the HCl standard.

Response to Comment 51: The agency disagrees with the comment ers. As mentioned elsewhere, the agency finds that the operation and maintenance issu es for the CEMS mentione d 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 w ith respect to compliance demonstra tion, containing numerous choices for compliance, including the use of em issions 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 continuousl y, that the HCl emissions limit was developed from emissions testing and has been adjusted to be ap propriate for measurement with HCl CEMS, and that emissions testing options to demonstrate complian ce 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, 17856, 17871, 17873, 17877, 17881, 17885, 17902, 17913, 17928, 18014, 18015, 18031, 18037, 18428, 18443, 18449, 18539, 19032, 19033, 19041, 19114, 19120, 19121, 19122, 19536, 19537, 19538, 18023

1. Support for the PM CEMS, HCl CEMS and Hg CEM S.

Comment 1: Several commenters (15678, 17722, 19032) support the EPA requirements of installing PM CEMS, HCl CEMS and Hg CEMS to demons trate continuous compliance with the emission standards.

Comment 2: Commenter 17283 supports the EPA that monito ring is an integral part of emission controls and that enhanced monitoring should be encouraged.

Comment 3: Commenters 17402 and 17620 support electronic re porting 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 appropria te 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 sour ce 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 promulgate d, source owners or operators wanting to request their use should consider having their applications consistent with the draft multiple metals CEMS method and performance specifi cations located at the follo wing internet address: < http://epa.gov/ttn/emc/prelim/otm19.pdf >.

Given the low non-Hg metals and PM emissions limits and possible difficulties in using PS 11 to certify PM CEMS at those low levels, th e 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 co llected and reported to the agency’s central data exchange. The final rule also does provide for the us e of a PM CEMS to determine compliance with the filterable PM emission limit if the source elects to use this approach (see the final preamble for further discussion). In that case, the PM CEMS is used as the direct method of compliance and no additional testing is required other than tests that are required as part of the QA requirements in PS 11.

2. Opposition based on testing requirements.

Comment 5: Commenter 16849 states that the proposed rule does not include provisions to use the 40 CFR Part 75 “conditionally valid data procedures.” For example, states the comm enter, if a CEMS fails a linearity check, the CEMS remains out-of-control until the successful completion of a subsequent linearity check, and this would require the operator to invalidate the 40 CFR part 75 conditionally valid data (for SO 2 , CO 2 , O 2 , or flow monitors) for 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 part 75 to be used for compliance with the exception of bias-adjusted and missing data.

Response to Comment 5: For the CEMS data that will be re ported 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 excep tions are that no missing data or bias provisions in part 75 are applied for purposes of complying with these standards.

3. Opposition based on limitat ions to the technologies.

Comment 6: Commenter 16849 states that there are known lim itations to the technologies available to monitor the surrogate HAP and provides the following details:

According to the commenter, Hg CEMS are difficult to maintain and accuracy is questionable at low Hg levels in conditions seen at utility plants. The commenter states that th e NSPS limit is so restrictive that utility plants cannot meet the proposed limits a nd 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. Th e 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 averag e of 1-hour readings and does not rely on a set maximum limit over 30 days as the proposed limit. According to the commenter, Hg analyzer performance has been so unpredictabl e that utility companies that have continued the use of the CEMS for state requirements are contemplating the replacem ent of CEMS with sorben t traps for the NESHAP. The commenter states that the EPA has not publicly released NIST Traceabilityprotocols, and early elemental Hg Vendor Prime calibrator certificat ions 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 ro lling basis would be more readil y monitored than a 30-day rolling average emission limit. In addition, as stated elsewh ere, 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 wa s legally available. Sorbent trap monitoring is allowed if a source owner or operator chooses to use that monitoring option. The interim NIST traceability protocols have been publically released and repres ent the results of a co llaborative process for establishing protocols amongst the affected stakeholde rs for Hg CEMS monitoring.

Comment 7: Commenter 16849 states that there are known lim itations to the technologies available to monitor the surrogate HAPS and provides the following details:

According to the commenter, PM CEMS are diffi cult to maintain and the NESHAP proposes a hybridized reference method, mixing EPA Method 5 and 5B. The commenter states that using total PM for the MACT metals limit surrogate and then setti ng the filterable PM limit based on the performance test does not work nor allow for a compliance marg in. The commenter states that the NESHAP requires maintenance of the PM concentration at or below the highest 1-hour average measured during the most recent performance test demonstrating compliance with the total PM emissions limitation, and the performance testing for total PM includes both filter able and condensable PM which would establish the plant or unit limit. The commenter states that si nce the PM CEMS only meas ures filterable PM, the margin of compliance for the unit or plant woul d be the amount of total condensable PM. The commenter states that the EPA identifies that EG Us using PRB as a fuel without wet FGD technology202 have very low condensable PM emissions. Accordi ng to the commenter, this method establishes an enforceable limit but does not provide a reasonable margin of compliance and artificially changes the limit established in the rule. The commenter states that low limits set during initial performance testing reflect capabilities of new equipmen t running at steady-state, maximum efficiency, and these conditions will not be achievable as equipment begins to age. Commenter 16849 requests that the performance test requirement be removed, using the RATA to verify the CEMS and the CEMS be the compliance measure based on the 12-month average. According to the commenter, the limit should be set at 0.03 lb/MMBtu, not based on performance testing. Comme nter 16849 states that with the addition of PM CEMS on all units, the requirement for opacity CE MS 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 filt erable PM as an operating limit for non-Hg metals. The rule establishes emissions testing based on filterable PM only, not to tal PM. The rule also provides for use of PM instruments as CPMS. The final rule also does pr ovide 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 me thod of compliance and no additional testing is required other than tests that are required as part of the QA requirements in PS 11. As for opacity requirements, the EPA disagr ees that these MACT st andards 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 source s 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 lim itations to the technologies available to monitor the surrogate HAPS and provides the following details:

According to the commenter, vendors are not assuri ng the abilities of HCl CEMS, and these monitors have no record in the utility i ndustry. The commenter states that currently no performance test is available for HCl.

Comment 9: Commenter 17191 states that Table 15 of the docket entry EPA-HQ-OAR-2009-0234 of the regulation shows that there is no alternative option of using 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 b een proven in the field, like SO 2 monitors and Hg sorbent traps, and unlike filterable PM monitors, con tinuous Hg monitors, and HCl CEMS.

Comment 11: Commenter 17677 disagrees with the EPA re garding high frequency emission testing requirements or PM CEMS due to difficulties incertification at very low emission levels.

Comment 12: Commenter 17757 states that there is no e ffective CEMS for Hg. According to the commenter, the HCl CEMS are not commercially avai lable 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 th at it is unclear whether inst alling and operating CEMS for the regulated HAP and HAP surroga tes eliminates the obligation to also monitor compliance with operating limits/parameters on control equipment base d on a performance stack test. According to the commenters, a properly installed and calibrated CEMS should suffice. Cl arification on this point is
necessary.

Comment 13: Commenter 18023 states that the EPA must provide reasonable continuous compliance requirements for Hg and other HAP and eliminat e requirements for undemonstrated or unreliable technologies such as HCl CEMS and PM CEMS.

Comment 14: Commenters 17800 and 17902 state that while CEMS for Hg and PM are available commercially, EGUs do not have experience in their operation and maintenance on a long term basis. Hg CEMS are not reliable and require two to three times the effort to maintain as typical SO 2 or NO X CEMS. According to the commenters, further testi ng and verification of the of the required CEMS equipment at utility sites need to be conducted before they should be used.

Response to Comments 8 - 14: These brief comments raise a variety of issues that generally have been addressed in response to other more detailed comments. The EPA is maintaining the proposed requirements to use CEMS where appropriate. If a s ource 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 testi ng 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 exis t in the rule. The EPA disagree s that Hg CEMS and PM CEMS are unproven technologies. See response to more deta iled comments in other sections of this document on those issues.

4. Opposition based on operating limit requirements.

Comment 15: Numerous commenters (17197, 17623, 17627, 17716, 17722, 17725, 17731, 17740, 17757, 17770, 17774, 17775, 17776, 17800, 17805, 17816 17820, 17871, 17877, 17885, 17902, 18023, 17913, 18014, 18015, 18031, 18037, 18443, 18539, 19033, 19114, 19122, 19536, 19537, 19538) request that the EPA remove the operating limit requirements fo r facilities that utili ze CEMS to demonstrate compliance. According to the commenters, this w ill reduce the cost and administrative burden of the rule without sacrificing human health or enviro nmental 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 comme nters, the EPA should remove requirements to test for the underlying pollutants being contro lled through a surrogate because such tests are redundant and unnecessary for compliance withthe proposed utility MACT.

Comment 16: Commenters 19120 and 17881 request clarification of the applicability of monitoring and operating limits to units using CEMS for compliance monitoring.

Comment 17: Several commenters (17730, 17758, 17775) disagree with the EPA requirements for sources to establish compliance w ith the non-Hg metal limits using total PM as a surrogate and PM CEMS as the measurement tool, with the HCl limit using HCl CEMS or an SO 2 CEMS for ongoing compliance, or with the Hg limit using a Hg CEMS or a sorbent trap system to also comply with an operating load limit or with contro l device operating parameter limits for PM, HCl, or Hg controls.204 Comment 18: Commenter 17775 states that th e EPA provides no data or discussion to justify chosen control device operating parameters, which are not in most cases sufficiently connected to emissions to justify imposing enforceable limits.

Comment 19: Multiple commenters (17627, 17740, 17770, 17776, 17816, 18014, 18015) state that the EPA should amend the regulatory language in secti on 63.10007(c) to make it clear that fuel sampling and operating parameter limits do not apply when eitherall of the regulated HAP or their surrogates are continuously monitored by a CEMS.

Comment 20: Commenter 19033 recommends that secti on 63.1008(a) be amended to require performance fuel analysis tests, if the regulated pollutant or specified surrogate emissions are not continuously measured by a CEMS.

Comment 21: Commenter 18023 proposes that operating limits should be a trigger for maintenance or inspection only.

Comment 22: Commenter 17877 states that operating limits or parameters should not be required on emission control devices where compliance is dem onstrated by CEMS and that operating limits should not be established based on initial performance testing.

Comment 23: Commenter 17928 states that stack testing is unnecessary to assure compliance if a unit installs or uses CEMS.

Response to Comments 15 - 23: The final rule clarifies that wh ere a CEMS is used for a given pollutant (including an alternate equi valent standard in the case 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 clarifie s that sources do not have to test for a pollutant where the source is meeting a surrogate emission standard (such as filte rable PM for non-Hg HAP). As mentioned in other responses, with the exception of PM CPMS and in lim ited cases, site-specific parameters for liquid oilfired units, the remaining fuel analysis, operating limit and parameter monitoring comments, are moot, for the rule no longer requires operating limits. Fo r the EPA’s response to those comments which oppose the manner in which operating parameter limits are set, please see responses to comments under section 5A05 in this document. As noted elsewher e, no operating parameter requirements apply when a CEMS is used to demonstrate compliance for an applicable pollutant.

5. Opposition based on averaging times.

Comment 24: Commenter 16849 recommends that averaging times for demonstrating compliance with the Hg limits be increased to a 365-day rolling aver age due to variability incoal quality, varying Hg content, removal equipment, a nd Hg CEMS monitor accuracy.

Comment 25: Commenter 17197 supports the proposed “30- boiler operating day rolling average” calculation methodology based on averag ing all of the valid hourly averaged measurements during the preceding 30 boiler operating days. According to the commenter, if compliance is based on daily periods rather than hourly periods, a single (abnormally high or low) hourly measurement could be the basis of a daily period that could improperly bi as the resulting 30-day average. The commenter states that using hourly averages as the basis for the 30-day boiler operating day rolling averages removes the potential for skewed results from days containing only a few unit operating hours and consequently yields representative emission rates for the 30-day compliance demonstration period.205 Comment 26: Commenter 17740 does not support compliance demonstration with the tested average PM value using a 30-boiler operating day PM average.

Comment 27: Commenter 17402 states that since the rule do es not propose a cap-and-trade program, units should not be required to collec t a monitored value for each operating hour.

Response to Comments 24 - 27: The final rule maintains the 30- day rolling average using hourly 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 aver aging 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 di scussion of alternative averaging times.

6. Opposition based on bias adjustments.

Comment 28: Several commenters (17881, 17796, 18023) support e liminating the bias adjustment for mercury, HCl, and PM CEMS since it is believed that bias adjustment of data has only been utilized with trading system based rules wher e mass emissions are being totaled.

Comment 29: Commenter 18023 states that bias can cause both over-and-under reporting. The longer averaging time should alleviate the need for bias adjustment.

Comment 30: Commenter 17767 states that unless the EPA is prepared to allow for the low bias of emissions data as well as high, it is best to follow the proposed rule a nd remove the Part 75 Bias Test for Hg, HCl, and PM CEMS.

Response to Comments 28 - 30: There is no bias adjustment factor applied for purposes of this rule.

7. Opposition based on compliance requirements.

Comment 31: Commenter 16849 disagrees with the EPA aboutthe ability of Hg CEMS to reach compliance within the first 30 days of operation. According to the commenter, with the needed adjustments and repairs to Hg CEMS and the add itional operation of multiple control devices, plant personnel will need at least 180 days to op timize control and monitoring equipment.

Response to Comment 31: For existing units, the final rule requi res sources to demonstrate compliance within 180 days after the date 3 year s after the effective date of the final rule. Such an extended period provides ample opportunity for the ty pes of adjustments suggested by the commenter. For new units, the rule likewise provides up to 180 days for demonstrating initial compliance.

Comment 32: Commenter 17716 disagrees with the EPA about showing on-going compliance by combining CEMS data with non-CEMS data to demonstrate compliance.

Response to Comment 32: The comment is moot, as the rule no longer contains a total PM limit, no longer requires use of PM CEMS for filterable PM, and no longer requires use of Method 202 to determine condensable PM.206 Comment 33: Commenter 17758 states that the purpose of the fu el input limits is to ensure that EGUs that are not using CEMS or sorbent trap monitoring sy stems repeat the relevant performance test if their fuel characteristics change such that compliance with the applicable limit at the current level of control is no longer assured. According to the commenter, since all EGUs are required to demonstrate initial compliance with each emissions limit through performance testing, and the proposed rule defines performance testing to incl ude the first 30 operating days of CEMS data, the proposal appears to require that EGUs meet fuel input limits regardless of th e 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 with the Hg limit using Hg CEMS or a sorbent trap system to also comply with fuel input limits for metals, chlorine or Hg.

Response to Comment 33: The comments are moot because the rule no longer requires fuel analysis or operating limits.

Comment 34: Commenter 17775 notes that the EPA does not propose separate continuous compliance requirements for HF CEMS.

Response to Comment 34: Section 63.10010(d) addresses operat ing requirements for HF CEMS.

Comment 35: Several commenters (17800, 18015, 18037) state th at compliance testing and monitoring requirements that include periodic emission te sting, other performance testing and CEMS are unnecessarily restrictive and expensive to impl ement, perform and operate. According to the commenters, the regulations for Hg CEMS had nu merous unresolved issues related to accuracy, calibration standards, and quality assurance provisi ons, and the EPA should allow time for development of performance specifications a nd, field testing and verification of the accuracy and precision of HCl monitoring equipment at utility sites be fore they are required for compliance purposes.

Response to Comment 35: For comments on technical aspects of HCl and Hg monitoring, see the specific responses to comments on those technologies in other sections of this document. The EPA disagrees with granting states flexibility to establis h compliance plans for sources. This is a federal rule, which provides flexibility to sources to select appropriate monitoring fo r their facility. In the event the source believes an alternative m onitoring method should apply, the part 63 provisions establish a method to request alternative monitoring, and the EPA and the states have established procedures for handling such requests in the event implementation of a specific NESHAP is delegated to a state agency.

Comment 36: Commenters 17805 and 17816 state that ther e is no logical reasoning for requiring sources to establish parametric limits for comp liance at units already demonstrating compliance with CEMS.

Response to Comment 36: The comments are moot because the rule no longer requires fuel analysis or operating limits.

Comment 37: Commenter 17856 states that due to the very low concentrati ons of Hg in stack gases, any little flaw in the precision or accuracy of th e monitor could lead to an inaccurate compliance determination. The commenter states that the uncertain ty associated with the use of these technologies further illustrates the need for provisions within th e 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 pl ans, such as fuel sampling and analysis, emission207 control monitoring, and the installati on of CEMS, to provide sufficient assurance that actual emissions limits are being met.

Response to Comment 37: For comments on technical aspects of HCl and Hg monitoring, see the specific responses to comments on those technologies in other sections of this document. The EPA disagrees with granting states flexibility to establis h compliance plans for sources. This is a federal rule, which provides flexibility to sources to select appropriate monitoring fo r their facility. In the event the source believes an alternative m onitoring method should apply, the part 63 provisions establish a method to request alternative monitoring, and the EPA and the states have established procedures for handling such requests in the event implementation of a specific NESHAP is delegated to a state agency.

Comment 38: Commenter 17881 states that the EPA needs to clarify whether fuel analysis and/or the establishment of operating limits ap ply in those cases where a CEMS is used to directly measure the HAP or an associated surrogate.

Response to Comment 38: The comments are moot because the rule no longer requires fuel analysis or operating limits.

8. Opposition based on monitoring requirements.

Comment 39: Commenter 17740 recommends that the EPA eliminate fuel sampling and parameter monitoring for an EGU which meets the specified em ission limits as demonstrated through use of a CEMS and states the following:

a. The EPA has not provided a rational justific ation 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 le ss 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 mon itors. The commenter states that table 5 of the docket entry EPAHQ-OAR-2009-0234 lists PS 6 as an applicable performa nce 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 prot ocol gases are not wide ly available and are expensive relative to traditional CEMS calibration gases. According to th e commenter, lowest available concentrations are significantly 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 parameters for meeting fuel input levels and that there is no discussion at all of the proposed fuel input levels in the docket entry EPA-HQ-OAR-2009-0234.

Response to Comments 39 - 41: As stated elsewhere in response to more detailed comments, source owners or operators who use CEMS to demonstrate continuous compliance are not required to monitor operating parameters or fuel for the same pollutant, as fuel analysis is no longe r required and, apart from PM CPMS, operating limits are no longer requ ired. A source can opt to use an SO 2 CEMS instead of an208 HCl CEMS in specific circumstan ces, and can use emissions testing in lieu of an HCl CEMS. The EPA also intends to promulgate a perf ormance specification for HCl CEMS prior to the compliance date of this rule, at least with respect to the compliance date for existing sources.

Comment 42: Commenters 17716 and 18449 state that sectio n 63.10021(a)(10)(ii) do es not include a reference to CO 2 contrary to the requirements in s ection 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 dilutionextractive CEMS which are equipped with CO 2 analyzers, and dilution-extractive CEMS cannot measure O 2 as a diluent.

Response to Comment 42: The final rule addresses this oversight.

Comment 43: Commenter 17881 states that in cases wher e an EGU elects to calculate annual Hg emissions based upon the average measured Hg concen tration and measured exhaust flow rate, the EPA has already granted the use of the default moisture content values fo r the determination of exhaust gas moisture content in 40 CFR pa rt 75, section 75.11(b)(1).

Response to Comment 43: The final rule allows for moisture de faults as proposed. Given the lack of defaults for oil-fired units, we have added an opt ion for sources to petitio n for an alternative unitspecific default in those cases.

Comment 44: Commenters 17881 and 19114 state that the pr oposed regulation referring to “fuelspecific CO 2 concentration” in section 63.10005(l) has following flaws:

a. According to the commenters, the proposed rule does not contai n any such default CO 2 concentration values and does not reference another regulation contai ning 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 bo ilers and the combustion turbines used in IGCC technologies; boilers and combustion turbines are fundamentally different combustion processes and operate at very differentlevels of excess air (w hich in turn impacts the diluent gas concentrations).

c. According to the commenters, the proposed rule la nguage is not clear on when the diluent cap values should be applied; it simply states that they should be applied duri ng periods of startup and shutdown (which are not defined in the proposed rule, and are only generically defined in section 63.2). The commenters state that under 40 CFR Part 75, the diluen t cap values are simply applied whenever the 1- hour average diluent con centrations 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, thes e provisions are no longer relevant and do not appear in the final rule.

Comment 45: Commenter 18014 states that EGUs that in stall a CEMS should not be required to provide further assurance of comp liance with the emissions standards. According to the commenter,209 such additional monitoring is redund ant and creates an unnecessary burde n on these sources and as such should be removed from the rule.

Response to Comment 45 : The EPA agrees, and the final rule clarifies this approach.

9. Opposition based on QA/QC requirements.

Comment 46: Several commenters (17716, 17881, 18014) state that the O 2 and CO 2 CEMS requirements in section 60.10010(b) shoul d refer to 40 CFR Part 75 in lieuof the alternate requirements specified in Appendix A to s ubpart UUUUU of the docket entr y EPA-HQ-OAR-2009-0234. According to the commenters, the following text should be added to Table 5 of the docket entry EPA-HQ-OAR2009-0234, as applicable: “Alternatively, for an aff ected source that is also subject to the O 2 or CO 2 monitoring requirements of 40 CFR Part75 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 46: The final rule includes language comp arable 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 47: Commenter 17716 disagrees with the EPA aboutadditional QA/QC requirements for use of SO 2 CEMS. The commenter states that although use of SO 2 CEMS is allowed for compliance demonstration, the requirements stat e 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 ma jority of 40 CFR Part 75 affected sources have completed initial certification year s ago and have been collecting “qua lity-assured” data for years, the benefit to this requireme nt is not apparent.

Response to Comment 47: This requirement has been removed in the final rule based on comments, and we do not think it is appropria te to include the provision pending further review of the technical issue by EPA’s monitoring groups.

Comment 48: Commenters 17820 and 17821 state that there ar e already other monitoring requirements for units required to report under Part 60, and ther e have been attempts to harmonize those rules to reduce confusion and cost. According to the commenters, the Part 60 rules, like these proposed rules, are not as detailed as Part 75 and c ould lead to inconsistencies in da ta quality between operators. Adding additional, different, and possibly co nflicting requirements for this ru le will cause additional confusion, increase downtime, and increase cost s with no evidence of any benefit.

Response to Comment 48: The EPA has attempted to harmonize the CEMS requirements under this rule primarily with the Part 75 CEMS requirements th at already apply to most of the affected EGUs under this rule.

10. Opposition based on sampling.

Comment 49: Commenter 17316 states that the outlet location for CEMS Probe is not the best location for these probes. The commenter states that the “outlet location” defined as the immediate exit of the boiler, just downstream of the combustion process, is not an appropriate locati on where a “representative210 sample” can be collected. Commenter 17316 recommends that “representative samples” should be obtained by locating the probe in the dow nstream ductwork or in the stack.

Comment 50: Commenter 17655 states that the monitori ng requirement for three new monitoring devices in existing smoke stacks thr eatens stack integrity and adds thatthe EPA did not consider safety issues associated with drilling additional holes in existing stacks and chimney liners.

Comment 51: Commenters 17775 and 17928 disagr ee with the EPA requirement for HAP stack testing for EGUs using surrogates, surrogate stack testin g for EGUs using CEMS, and surrogate testing for EGUs not relying on surrogates for compliance demonstration.

Response to Comments 49 - 51: In response to comments, the fina l rule has removed all requirements for duplicative testing of a HAP and the applicable surrogate. Facil ities complying with a surrogate standard will conduct the performance test for that standard, and not for the corresponding HAP emission limit (and vice versa).

Comment 52: Commenter 18014 states that it is unclear as to whether EGUs that fire a single type of fuel are exempt from all fuel sampling and analysis requirements.

Response to Comment 52: This comment is moot because the fuel analysis requirements are not included in the final rule.

Comment 53: Commenter 17902 states that installation of additional CEMS for PM and HCl requires significant structural mo difications, such as:

a. Installation of additional ports (to install the sampling probe);

b. Stack platforms (additions or modifications to existing platforms to access new monitoring equipment);

c. Shelters (to house climate controlled equipment);

d. Electrical instrumentation (to power shelters, heat probes, etc); and,

e. Communications systems (needed fiber optics, Ethernet to communicate with existing computer programs).

Response to Comment 53: The addition of new monitoring equipment may require additional modifications to existing CEMS infrastructure, although the EPA questions whether the changes are significant structural modifications in light of the emission control re quirements of this rule. To the extent a source believes these cha nges are too significant, the source can conduct periodic stack testing as an alternative to either a PM CPMS or an HCl CEMS.

11. Need clarification on operational limitations.

Comment 54: Commenter 17800 states that th e compliance with MACT sta ndards 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 precl ude operational limits. According to the commenter, the operational requirements in Table 4 of part 63 subpart UUUUU ar e unnecessary, requiring unn eeded record keeping211 that does not improve compliance and should be eliminat ed from this rule. The commenter states that if the unit chooses to install and prope rly operate and maintain CEMS for filterable PM, Hg and HCl, these operating limits are unnecessary. According to the commenter, once the CEMS are certified and recording quality assured data, these systems determine the unit’s compliance status. The commenter states that the EPA should clarify when CEMS are being used for compliance, operational limitations on unit load and the applicable control equipment are unnecessary as well as the reporting requirements in section 63.10031 pertaining to thos e operational requirements.

Response to Comment 54: 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 w ith a PM CPMS, and in limited cases, site-specific parameters for liquid oil-fired units. In consid eration 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 othe r rules. The highest hourly average of the PM CPMS signal produced over three test runs is us ed as the operating limit, and that value becomes averaged over a rolling 30 boiler operating day average. The final ru le 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 th at case, the PM CEMS is used as the direct method of compliance and no additional testing is required other than te sts that are required as part of the QA requirements in PS 11.

12. Requirements for bypass stacks.

Comment 55: Commenter 17718 states that within the proposed regulatory language of section 63.10006, there does not appear to be anoption for reduced HCl performance testing requirements on coal-fired units with non-HCl contro lled bypass stacks. The commenter states that within the proposed language of section 63.10010(a)(4), it appears that a bypass stack would be required to install similar monitoring systems as the main common stack. According to the commenter, without flue grade sulphurization technolog y on the bypass stack, it appears th at 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 woul d still be required to conduct pe rformance testing every month.

Comment 56: Commenters 17772 and 17873 state that PM CEMS do not operate properly during startups and shutdowns. According to the commenter s, PM CEMS are not calibrated under startup or shutdown conditions, nor are they calibrated using the changing fuel mix (e.g., moving from 100 percent oil to 100 percent coal) associated with start-up, and values during these times are not valid for compliance purposes. If a bypass stack is predominat ely used during startup and shutdown, state the commenters, there should be no requirement to inst all a PM CEMS. The commenters state that the EPA has the discretion necessary to regulate PM through a work practice standard; in stead of requiring costly and duplicative monitoring equipment to measure inte rmittent emissions that occasionally flow through bypass stacks, the EPA should develop work place standards that would put parameters around how often and when bypass stacks can be employed.

Comment 57: Commenter 17781 states that the periods of EGU startup and shutdown resulting in FGD bypass, as well as reasonab le periods of FGD malfunction whic h 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 bypass stack or to treat any hour in which the unit bypasses the main stack and fa ils to collect quality-assu red data as an hour of monitoring downtime. The EGU owner or operator rema ins subject to the 30 boiler operating day rolling average during bypass operations.

13. Opposition based on maintenance requirements.

Comment 58: Commenters 17775 and 17800 state that the EPA did not account for the fact that EGUs need to perform maintenance, in addi tion to required QA/QC, in order to keep monitoring systems running properly. The commenters state that the EPA should recognize this in the 40 CFR part 63 general provisions, which requ ire sources to maintain their monitoring systems and exempts “maintenance periods” from operating requirements.

Response to Comment 58: Normal maintenance activities associat ed with quality control (not quality assurance) procedures in a source’s monitoring plan are exempt as partof the QC exemption provided in the final rule. No additional exemption is necessary.

14. Need for clarification on monitorin g, recordkeeping and reporting requirements.

Comment 59: Commenter 17776 states that the EPA needs to clarify the proposed rule that monitoring, recordkeeping, and reporti ng requirements do not apply for facili ties equipped with CEMS. According to the commenter, facilities which use CEMS for mon itoring of a regulated pollutant or surrogate should not require fuel sampling, parameter monitoring, or compliance with fuel or operational limits.

Response to Comment 59: The rule does not require monitoring operating limits where a CEMS is used for the applicable standar d. If a source has PM control equi pment and uses a PM CPMS-based operational limit, no control device monitori ng is required. The same is true for SO 2 / HCl controls.

Comment 60: Commenter 17776 states that for PM (Item 1) a nd 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 certificat ion and ongoing monitoring requirements for PM and HCl CEMS.

Response to Comment 60: These cross references have b een corrected in the final rule.

Comment 61: Commenter 17725 states that the EGU MACT Rule does not include provisions to use the Part 75 “conditionally valid data procedures.” The commenter states that if a CEMS fails a linearity check, the CEMS remains out-of- control until th e successful completion of a subsequent linearity check, and this would require the op erator to invalidate the Part 75 conditionally valid data (for SO 2 , CO 2 , O 2 or flow monitors) for the EGU MACT record keeping and reporting purposes. According to the commenter, a clearer approach would be to allow quality-assured data froma CEMS certified and operated in accordance to Part 75 to be used for EGU MACT compliance.

Response to Comment 61: The final rule provides for certain Part 75 procedures for the CEMS and sorbent trap monitoring systems used to comply with this rule, including th e use of the conditionally valid data procedures.

15. Lack of variability.213 Comment 62: Commenter 18014 states that the snapshot natu re of performance test data means the results will provide little insight on the true range of boiler variabil ity and the associated effects on emission controls. According to the commenter, th e EPA should address the additional variability introduced by the CEMS within the rule. The commenter states that the “apples-t o-oranges” contrast of the CEMS versus reference method data (particularl y 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 averag e) to address for the CEMS/operating variability issue.

Response to Comment 62: The PM monitoring will be used as a PM CPMS and not as a direct compliance method with an emission limit. For the Hg CEMS or sorbent trap monitoring system, and the HCl CEMS, the EPA disagrees. This issue is discussed in more detail in the comment sections directly related to Hg CEMS and HCl CEMS.

16. Missing information.

Comment 63: Commenter 18014 states that the rule does no t include the equations for calculating PM or HCl mass emissions; Appendix A onl y includes equations for Hg.

Response to Comment 63: There is no requirement to calculat e PM mass emissions; PM monitoring is a parameter-based approach to ensure compliance w ith an operating limit. For HCl, section 9 of Appendix B to the final rule provid es the appropriate method for calcu lating emissions in terms of the emission standard.

17. Recommendations.

Comment 64: Commenter 15678 recommends that CEMS need to be certified and r ecertified 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 certificati on tests and performance specifications for Hg CEMS.

Comment 65: Commenter 16849 recommends that further testi ng 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 thata footnote be added to Table 5 of the docket entry EPA-HQ-OAR-2009-0234 that states “Daily calculate a new 30-boiler operating day rolling average of all of the hourly CEMs emissions data fo r the preceding 30-boiler operating days.”

Comment 68: Commenter 17265 is requesting cl arification of whether CEMS are warranted across-theboard for the HCl source category, and supports reta ining a source’s option to select CEMS as the monitoring method, but recommends that the QA pr ovisions be further developed to ensure the credibility and accura cy of the data.214 Comment 69: Commenter 17283 recommends proposed alterna tive standards for total or individual metals, including specific language in the final rule allowing enhanced monitori ng of these metals with multi-metals CEMS as an alternative to Reference Method 29 measurements and/or PM CEMS and/or Hg CEMS.

Comment 70: Commenter 17283 states that cycle time equal to or less than 15 minutes is currently required for CEMS in various places (Table A- 1, Table A-2, and pages 25110-25113) of the docket entry EPA-HQ-OAR-2009-0234 and 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 limits,

b. Reference methods require sampling times of about 4 hours at these low concentrations, and

c. The proposed cycle time is not consiste nt with PS12 A or Cement MACT rules.

Comment 71: Commenter 17283 recommends that units em ploying PM CEMS should be exempted from federal and state opac ity monitoring requirements.

Comment 72: Commenter 17677 recommends thatthe EPA must have certifiable methods for source CEMS in order to determine accuracy. Accord ing to the commenter, without certifiable methods/procedures, data accuracy cannot be relied upon for compliance determinations.

Comment 73: Commenter 17677 recommends that the EPA cl arify the language relating to initial compliance demonstrations for CEMS.

Comment 74: Commenter 17730 recommends that the EPA s hould provide procedures for averaging actual emissions data from CEMS to determine m onthly average weighted em issions and revision of section 63.10009 to include procedures for units usi ng 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 allo w compliance to be demonstrated based on stack tests and CAM plans other than PM and HCl CEMS.

Comment 77: Commenters (17716, 18014) recommend that th e 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 performan ce stack testing requirements set out in Table 5 (part 76 CFR 25129-31) should not be required of those EGUs that use CEMS for continuous compliance because the requirements are redundant and burdensome without providing added benefit.

Comment 79: Commenters (17767, 17881, 18428) recommend that it is appropriate that the proposed rule does not require the generation and submittal of missing data substitutions, as the emissions limitations are rate-based and not mass-based.215 Comment 80: Commenter 17775 recommends that the EP A should allow use of 40 CFR Part 75 provisions as an alternativ e 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 (includingthe option of stack tes ting with monitoring of operating parameters and, fuel analysis for liquid oil-fi red units), or limit applicab ility of the section to those circumstances where an EGU opts to, or is requ ired to install a CEMS or sorbent trap system.

Comment 82: Commenter 17775 recommends that the EPA should eliminate the redundancy between section 63.10010(a)(4) and Appendix A section 2.

Comment 83: Commenter 17775 recommends that the EPA incl ude provisions similar to 40 CFR Part 75 that allow EGUs that are otherwise using CEMS to report a site-specific default value during bypass in lieu of installing and main taining CEMS on the bypass stack.

Comment 84: Commenter 17776 recommends that the EPA should revise the requirement to use PM CEMS for demonstrating continuous complian ce with the total PM limit. PM CEMS can only analyze for filterable PM per EPA PS 11.

Comment 85: Commenter 17776 recommends that the EPA should allow the use of sorbent trap monitoring systems as another means for continuous monitoring of Hg emissions. Commenter also recommends that the EPA allow annual perfor mance tests for HCl until HCl CEMS technology advances further.

Comment 86: Several commenters (17725, 17820, 18014, 19033) recommend that section 63.10010(b)(5) should be revised to include CO 2 , for example, “the average of all of the hourly oxygen or carbon dioxide emissions data for the precedin g 30 boiler operating days,” and that section 63.10021(a)(10)(ii) should in clude a reference to CO 2 records.

Comment 87: Commenters (17718, 18037, 18539) recommend th at performance testing should be conducted annually for each of the stacks instead of every other mont h as currently proposed. According to the commenters, it may not be feasible to complete testing at all units with in a monthly or 2-month period due to lack of test crew s, unit scheduling, scheduled mainte nance, and other considerations.

Comment 88: Commenter 17722 states that the EPA s hould allow “to-be-approved” monitoring techniques and technologies as part of the final rule. As one ex ample, Commenter is aware of a novel sorbent tube technology that is under developm ent by the University of North Dakota’s Energy and Environmental Research Center (“EERC”), wher e 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 late r this year, and if these sorbent tubes prove viable, lik e Hg sorbent tubes, the final EGU NESHAP rule should allow use of this new approved monitoring technology.

Comment 89: Commenters 17821 and 17881 recommend remova l 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 data are typically used as a diluent gas when using CEMS measurement data to calculate emission rates in terms of lb/MMBtu. According to the commenter s, the diluent ga s components of these equations under 40 CFR 60 are not averaged into long-term aver ages; 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 usi ng the hourly diluent gas values.

Comment 90: Commenter 17821 recommends that the EPA a llow the use of certif ied flow monitoring systems to calculate emissions rates when volumetric flow rate is needed. The commenter states that volumetric flow CEMS certified in accordance with 40 CFR 75 are used for re porting purposes already and allowing these data to also be used to calc ulate mass emissions would provide consistent data.

Comment 91: Commenter 17881 states that the provision s at section 63.10010(b)(4) require that CEMS data be reduced to 1-hour averages according to the requirements in s ection 63.8(g)(2) and (4). According to the commenter, these data reduction procedures are not fullyconsistent with the procedures specified at section 60.13(h) and sec tion 75.10(d)(1), and commenter suggests that the preceding data reduction procedures be allowed as al ternatives to those which are currently specified.

Response to Comments 64 - 91: The EPA has considered all of these various recommendations in finalizing the proposed monitoring requirements. In general, the final rule builds on the proposed requirements by providing for monitoring continuous compliance with specific standards through the use of an applicable CEMS, or a sorbent trap for Hg, or a PM CPMS for non-Hg metals or PM. Should a source owner or operator elect not to use CEMS or the other instrume ntal methods, performance testing is required. In revising the proposed rule, the EPA ha s finalized an approach that builds off the Part 75 requirements wherever possible for CEMS. The EPA believes that the initia l and ongoing certification and QA procedures for applicable CEMS are appropr iate for ensuring the co llection and reporting of quality data. The final rule includes a variety of speci fic changes to help clarif y the use of CEMS versus operating parameter monitoring, calculation of 30-day ro lling averages, and other specific issues with the monitoring requirements raised in these brie f 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 owne r or operator may propose such a method under the general provisions in se ction 63.8(f) of subpart A of part 63.

18. Need for clarifications of rule.

Comment 92: Commenters 17718 and 17881 request that the EPA clarify when the 30-day operating period begins if the systems are already certified (e.g., current SO 2 or PM CEMS being used for 40 CFR Part 75 and/or 40 CFR Part 60 monitoring programs).

Response to Comment 92: The 30-day period will begin on su ch 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 pe riod specified in the rule.

Comment 93: Commenter 17718 states that the EPA should cl arify whether initial testing of the bypass emissions needs to be tested within the 180-day ti meframe described in the proposed language and that alternatively, setting a firm testing timefram e on bypass stack emissions seems overly burdensome. According to the commenter, creating emissions (and incurring costs) by sw itching a unit into bypass mode that would not otherwise have been used simply in order to perform emission testing appears to create unnecessary burden.

Response to Comment 93: Under the final rule, you may elect to monitor the bypass stack or treat hours in which the bypass is used as monitor downtime. The EGU owner or operator remains subject to the 30 boiler operating day rolling average duri ng bypass operations. To report data from any217 monitoring on a bypass stack, you do need to have a certified monitoring system. Because you can decide to not monitor the stack, there is no requirement that the certification occur in the first 180 operating day period.

Comment 94: Commenters 17718 and 19121 states that in th e proposed regulatory language seen in section 63.10005(l), it is mentioned th at a “default diluents gas con centration value of 10.0 percent O 2 or the corresponding fuel-specific CO 2 concentration” are to be used dur ing 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 94: Because of the revisions related to startup and shutdown provisions, the cited language is no longer applicable.

Comment 95: Commenter 17820 cites that Table 8 states that the source is to convert “hourly emissions concentrations to 30 individual boiler operating mg/d scm values,” which suggests that compliance is assessed based on the average of 30 individual daily values but that sectio n 63.10010(g)(5) states that 30-day rolling average is calculated as “the average of all of the hourly particulate emissions data for the preceding 30 boiler operating days.” The commenter states that this requirement needs to be clarified.

Response to Comment 95: The referenced language in the proposed rule is not used in the final rule. Provisions in Appendix A and Appendi x B to the final rule describe the procedure for calculating 30-day averages where an Hg CEMS, sorbent trap monitoring system, or HCl CEMS are used for compliance. Overall, the language in the final rule ensures a un iform approach for calculating averages 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 eliminating bias tests.

Comment 1: Multiple commenters (17718, 17740, 17816, 17820, 17873, 17877, 17909) recommend that the EPA disable the ECMPS Pa rt 75 bias test for Hg, HCl, a nd PM CEMS. The commenters state that bias adjustment may be appropriate for emissions trading programs to ensure that companies are not under-reporting their emissions and, he nce, failing to surrender an ad equate 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, re porting, and recordkeeping and urge the EPA to remain open to additional accommodations that ar e identified in the cour se of implementing the
program.

Comment 3: Commenter 17877 states that eliminating the bias test for these monitors will also reduce the file size, complexity, and time required to maintain and report quality assured data.

2. Other bias test comments.

Comment 4: Commenter 17881 states that the proposed EGU MACT rule appears to be silent on the concept of whether 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 adjustme nt factors (BAFs) under 40 CFR Part 75 does not appear to be addressed. According to the co mmenter, in other cases where the EPA has allowed the use of Part 75 CEMS for co mpliance 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, th e final rule does not require any bias adjustment when reporting data under this rule. Fo r missing data related comments, see responses to comments under Comment Code 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 no need fo r missing data substitution.

Comment 1: Several commenters (17655, 17877, 17904) agree with the EPA th at there is no need for missing data substitution procedures in this moni toring 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 monito rs are not considered instruments of commerce, normal monitoring downtime provisions should apply.

Comment 2: Commenter 17877 notes that hours when a monito r is out of service should be counted as monitor down time against the percent monitor avai lability, but substituti ng data is unnecessary. According to the commenter, maintaining a consistent set of rules to govern mon itors that are only used to demonstrate compliance with an emission limit not tied to trading, simplifies the assurance of ongoing compliance for both the regulated community and the regulators. The commenter states that eliminating missing data substitution for these monito rs will also reduce the f ile size, complexity, and time required to maintain and report quality assured data.

2. Options for missing data substitution.

Comment 3: Commenter 17620 suggests that sources shou ld be required to infer emissions during monitor downtime at the highest daily rate over the pa st 90 days during each hour that a monitor is not in service.

Comment 4: Commenter 17818 disagrees with the EPA’s pr oposal to not require data substitution during monitor downtime for Hg, HCl, or PM CEMS . The commenter understands that under the Acid Rain Program the data substitution is essential to properly account for all mass emissions for the pollutant in question, but for the proposed rule, compliance with HAP emissi ons limitations takes place over a relatively long period of time. The commenter’s opi nion is that it is appr opriate to require data substitution for compliance with long -term emission rate limits to he lp ensure that a more accurate indication of unit emissions is developed during all pe riods of unit operation in order to assess the unit’s compliance with the applicable emissions limitation. The commenter also notes that a requirement for data substitution will also help encourage the owner/operator to maintain the related CEMS in a high state of accuracy and availability.

Comment 5: Several commenters (17316, 17821, 17881) state that there are conditions other than those listed in section 63.10020(b) that are legitimate reasons for monitoring system data loss and should also be excluded from downtime reporting. The commenters state that these conditi ons include: planned and unplanned preventive maintenance, corrective action ma intenance, diagnostic ch ecks, linearity tests, system integrity checks, cylinder gas audits, QA/QC , system purges, installation of system upgrades, etc. The commenters request that th e EPA revise section 63.10020 to refl ect 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 comme nter states that if th e EPA believes monitoring system data loss to be a significant issue then th e rule might establish a minimum data recovery220 threshold, such as 95 percent data availability per quarter, exclus ive of calibrations, preventive maintenance and QA testing, as is done in many permits.

Comment 7: Commenter 18023 states that a penalty should not be associated with Hg system availability or monitor downtime. Th e commenter states that this is be cause: (1) Hg monitor repairs take much longer to recover and settle once the system is returned to service than current CEMS analyzers for NO X and SO 2 , (2) QA/QC activities take longer to perfor m, especially with the required calibrator checks, and (3) the sorbent trap vers us continuous monitor issue is almost an apples to oranges argument regarding availability with mi ssing days/weeks for sorbent traps versus missing hours for monitors. According to the commenter, section 6.1.3 will only increase the amount of monitor downtime; total availability should be calculated and recorded for tracking purposes but penalties should not be associated with them, especially with the limite d experience performing QA/QC with these devices.

Comment 8: Commenter 18023 states that under section 6.1.3 Data Reduction and Calculations, the rule should allow the use of valid Part 75 substituted data for these parameters since those substituted values are acceptable to the EPA for other emission monitoring programs.

Comment 9: Commenter 17886 states that section 63.10020(c), should exclude preventative maintenance and corrective action main tenance 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 fina l 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 polluti on control practices and to provide data sufficient to demonstrate compliance with a relatively long-term emissions rate limit (e.g., lb/MMBtu or lb/MWh). We agree that data quality certainty associated with any calculated value decreases with the collection of fewer data such as would occur with extended peri ods of monitoring system downtime. Even so, we believe also that it is necessary and critical to compliance with the regulati on that a source uses all measured data collected during an averaging period to assess compliance rega rdless of any periods of missing data. Sources should not disqualify any data otherwise meeting required data quality requirements simply because there were data missing for other hours or days of the averaging period.

Instead of a minimum data availability threshold that would invalidate data colle cted for some averaging periods because one did not co llect data for at least “x ” percent of an averaging time, the final rule requires that a source report as devi ations to the rule failure to colle ct data during requ ired periods and that are not covered by exceptions allowed in the final rule.

On the issue of applying a data substitution procedur e 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 secti on 63.6(f)(3) during periods of monitoring downtime to assure compliance with the applicable emissions limitations and standards.

We believe that enforcement authorities also can and should determine whether a source is meeting any monitoring system operating requirements. Should the source or the enforcement authority be concerned about the representativeness of data such as dur ing periods of missing data, either may consider collecting information through other means (e.g., supplemental emissions testing) to fill data gaps not only because such gaps are deviations from the ru le 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 specify ing that failure to collect require d or otherwise excepted data is a deviation from the rule will provide the necessary in centive 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, fluorine or non

‐ Hg total Metals content is greater than that measured in the fuel combusted during performan ce testing (unless the unit is equi pped 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 deli veries (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 difficu lt compliance issues, as the HAP cont ent 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 com busted during performance te sting 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 it self, and (b) because it is reasonable to assume that the fraction of HAP in the fuel emitted as stack emissions should be relatively constant, so long as any add

‐ on controls are operating proper ly, it would seem reasonable and appropriate to proportion up the HAP content of the fuel combusted during performance testing, by the ratio of HAP emission standard to the measured HAP emissions, in or der 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 unfai r compliance (fuel) restriction on the site.

Response to Comment 1: The comment is moot because the rule no longer requires fuel analysis or operating limits based on non-Hg metals content of fuel. The only fuel monitoring provision in the final rule is an option for liquid fuel units to use fuel moisture monitoring. If you combust liquid fuels and you wish to demonstrate ongoing compliance with HC l and HF emissions limits by measuring fuel moisture content of fuel in pl ace of quarterly stack testing.

Comment 2: Commenter 17316 states that in regard to requirements that if a source demonstrates compliance with HAP limits “based on fuel analysis, you must conduct monthly fuel analysis for each type of fuel burned.” The commenter notes that oil is a homogeneous fuel that is relatively consistent (from shipment to shipment), and therefore such fre quent fuel sampling and anal ysis for oil-fired EGUs is not warranted.

Comment 3: Commenter 17316 states that the monthly fuel analysis requiredin section 63.10006(s) contradicts the discussion of this topic in the pr eamble (FR page 25053 column1) which specifies that (after the initial compliance dem onstration by fuel analysis)], th e EPA “is proposing a source be required to recalculate the fuel pollutant content only if it burns a new fuel type or fuel mixture.” The commenter is concerned that this requirement is unj ustified for sites that receive oil deliveries less frequently than monthly. The commenter proposes thatfuel 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 sampling; however, the agency agrees that fuel moisture sampling (if that option is selected by a source) need only occur on delivery of a new shipment of fuel oil.

Comment 4: Commenter 17870 asks for clarification of the ru le allowing fuel analyses to demonstrate initial and continuous compliance withapplicable emission limitations, as an alternative to performance stack testing and continuous compliance. The commenter states that in the rule, owners/ operato rs of all affected liquid oil-fired units may perform fuel analyses to demonstrat e initial and continuous compliance, but in the preamble (F R page 25031) limited-use liquid oil combustion units are allowed “to demonstrate compliance with the Hg emission limit, the HAP metals, or the HCl and HF emissions limits separately or in combination based on fuel an alysis rather than perf ormance stack testing, upon request by you and approval by the Administrator.” The commenter asks for clarification on whether this applies to limited-use or all liquid oil-fired units.

Response to Comment 4: In large part, this comment is moot, as the rule no longer allows metals or hydrogen halide sampling of fuel oil. As mentione d elsewhere, in reviewing comments on monitoring frequency and burden, the agency dropped fuel an alyses and operating limits based on those fuel analyses, reduced stack testing fr equency to quarterly for both units with and withoutcontrols, and developed a stack testing exemption in quarters with limited operating hours. Inparticular, units that exhibit limited use – less than seven days of boiler operation per quarter – are exempt from testing for that quarter; however, each unit mu st perform a stack test at leas t annually. The limited use provision gives relief to sources while maintaining expected em issions performance. In addition, if an EGU has an oil-fired capacity factor of less th an 8 percent evaluated on a 24 month block average, then the only standard that applies is the performance tune -up requirement (see Comment Code 4D02 of this document). Should an owner or operator of a liquid oi l-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 dem onstrating compliance. In addition, the rule will still co ntain 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 wi ll allow moisture content sampling of the fuel oil as an alternative means of demonstrating compliance fo r units that have fuel moisture content no greater than 1.0 percent. The rule no longe r requires establishment of operati ng parameters for control devices for these pollutants. See more discussion of the EPA’s responses to operating parameter monitoring under Comment Code 5A06 in this document.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, 17873, 17880, 17881, 17886, 17902, 17909, 17925, 17927, 17928, 18014, 18024, 18025, 18031, 18034, 18039, 18428, 18444, 18477, 18487, 18498, 18502, 18539, 18963, 19033, 19114, 19120, 19121, 19536/19537/19538, 18023

1. Commenters concerned about the propos ed frequency of performance tests.

Comment 1: Numerous commenters (17402, 17627, 17638, 17681, 17696, 17704, 17716, 17718, 17725, 17737, 17740, 17758, 17760, 17775, 17796, 17800, 17803, 17804, 17807, 17816, 17820, 17821, 17838, 17856, 17867, 17870, 17881, 17902, 17909, 17925, 18014, 18025, 18031, 18428, 18444, 18477, 18963, 19033, 19114, 19120) believe that the proposed fre quency of performance testing under section 63.10006 is excessive or overly burdensome.

Comment 2: Commenters 16513 and17804 state th at the rule would significan tly increase the workload of state agencies by as much as 50 percent as a result of observing emission tests and/or reviewing emission test protocols, and updatin g AFS. Commenters recommend revi sing the testing to quarterly or biannually. .

Comment 3 : Several commenters (17402, 17627, 17704, 17716, 17718, 17760) state that the EPA should allow facilities to comply with the performan ce testing requirements on an annual basis similar to their current permit requirements. Commenter 17402 be lieves that less frequent stack testing coupled with more frequent fuel sampling can ensure conti nuous compliance because data in the docket indicate that over the long term, emissions are fairly consis tent despite potential variability in fuels and operations. Commenter 17402 believes that annual Me thod 29 stack testing co mbined with existing permit requirements (to properly oper ate 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. Co mmenters (17402, 17718) believe this suggested combination is preferable to the logistical and cost concerns implic it in monthly or bi-monthly testing requirements, and the commenters cite the limited availa bility 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 electr icity demand when natural gas may not be available (due to residential heating demand) and states that rece nt natural gas prices make fuel is concerned that the monthly or bimonthly testing requirements will force dual. The comm enter states that first, the proposed frequency of testing will impose a significant cost burden on pl ant operators. For example, all of commenter 17803’s units are gas capable and, with the current differen ce in oil and gas prices, oil is consumed only during periods of gas unavailability or as required by the New York Independe nt System Operator to ensure reliability during periods of high electric demand. According to the commenter, monthly testing would result in significant economic burdens. For exam ple, commenter 17803’s cost of the uneconomic oil consumed during the 2010 ICR testing last year was approximately $2-3 million. Second, states the225 commenter, inflexible testing schedules may induce units to run solely for testing purposes, leading to increased emissions. According to the commenter, any oil-fired units are operate d as peakers or cycling units, and may spend a significant portion of the y ear off-line and the proposed testing requirements would require these units to run even if ther e were no demand for additional power. Commenter 17316 adds that for dual fuel (oil/gas) units, the proposed testing regimen is even more environmentally counter- productive because these units tend to operate on natural gas during the ozone season, but proposed section 63.10007(c) would require the firing of oil during ozone season.

Comment 5: Several commenters (17316, 17627, 17716, 17718, 17725, 17760) state that the proposed performance testing requirements for sources with out CEMS are cumbersome and expensive for units with low annual capacity factors (e.g., oil-fired un its) 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) st ate that in some cases the prop osed testing frequency for oilfired units with low annual capacity factors will resu lt in an increase in annual HAP emissions that could exceed any reduction in hourly emission rates achieve d by the rule. Commenter 17760 adds that if the EPA does not agree with annual testing of oil-fired units with low annual capacity factors, then the testing frequency should be a f unction of “fuel operating” hours.

Comment 6: Several commenters (17627, 17718, 19114) believe that the EPA’s assertion that most units will choose to install CEMS rather than the burdensome stack testing option may be faulty because HCl CEMS technology is not yet available, PM CEMS are still quite unproven, and other CEMS systems may be incapable of measuring emissions as low as the EPA has proposed. Commenter 19114 further states that for low capacity units they have de termined 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. Accordin g to the commenter, the EPA should consider the frequency and types of monitoring appropriate for various subcategor ies, including an exemption for low capacity factor and LEE units.

Comment 7: Several commenters (17638, 17681, 17725, 17740, 17758) state that the proposed monthly or bi-monthly testing frequency is excessive, unn ecessary, and cost prohibitive. Commenters (17638, 17681, 17758) note that the EPA established the limits based on single tests from multiple units, and conclude that there is no ba sis for the proposed frequency.

Comment 8: Commenter 18477 states that to conduct sour ce 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 expe rtise and equipment. The commenter states that any upset that occurs during the source testing schedu le, a common phenomenon when testing multiple units within a relatively short time fram e, further strains commenter’s gene ration 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 ev ery other month equates to 84 source tests annually. If the four units commenter has identified for potentia l retirement were not equi pped 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 sour ce testing regime would be a severe burden to our already overburdened ratepayers. The commenter notes that th e cost of source testing in significantly higher than in the continental U.S. and that the commen ter paid a 20 percent prem ium to perform the ICR testing.226 Comment 9: Several commenters (17760, 17881, 18477) note that annual testing would be consistent with the industrial boiler MACT (DDDDD), stationary combustion turbine MACT (YYYY), and the RICE MACT (ZZZZ) that provides semi-annual to annual testing.

Comment 10: Commenters 17870 and 17881 state that the propos ed testing frequency is impractical to conduct especially in the northern climates where temperatures in many months (about 5) of the year are too cold. According to the commenters, severe w eather events can postpone stack access for safety reasons (ice, lightening), thus reducing the margin of maintaini ng 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 sugge sts that annual testing is more reasonable for units without CEMS but with controls and operating limits an d semi-annually for units with CEMS. Commenter 17870 suggests the all stack testing requirements governing coal-fired EGUs should be no more frequently than quarterly under stan dard operation (i.e., unle ss boiler operations or characteristics are substantially altered, in which case initial testing should be repeated). According to the commenter, quarterly stack testing in combin ation with parameter mon itoring (discussed below) should be enough to ensure that a unit is operating w ithin the required limits, and quarterly testing would capture seasonal variations in operation while not unnecessarily repeati ng testing of the same conditions.

Comment 11: Commenter 18502 recommends that the EPA re duce the compliance testing requirements based on the relatively small size and emissions a nd remoteness of non-continental EGUs burning liquid oil.

Response to Comments 1 - 11 : In response to these comments, th e final rule includes a number of changes from the proposed rule that will reduce the overall testing required under the final rule. First, the final rule establishes a separate subcategory for an EGU with an annual oil-fired capacity factor of less than 8 percent. These units are subject only to the performance tune-up work practice standard in the final rule. Second, the optional periodic testing requirements have been made consistent between controlled and uncontrolled sources, with a reduced frequency of qua rterly performance testing. In addition, the final rule has removed all requiremen ts for duplicative testing of a HAP and surrogate standard (such as filterable PM and HAP metals).

Comment 12: Commenter 17856 questions the need for such frequent stack testing for units with CEMS because of the extensive opera tional and parametric monitoring.

Response to Comment 12: The final rule has been amended to not require additional performance testing if complying with Hg, HCl or SO 2 CEMs. For sources electi ng to use PM CPMS, the performance testing frequency has been reduced to annual testing.

Comment 13: Multiple commenters (17638, 17681, 17690, 17716, 17725, 155, 156, 17758, 17760, 17803, 17820, 17870, 17902, 17909, 18014, 18025, 18428, 18498) believe that the testing frequency for units opting to comply with the non-Hg HAP metal or HCl emission limits should be once every four unit operating quarters (not calendar quarters), but no less frequently than once every eight calendar quarters following the required frequency for RATA ’s at 40 CFR Part 75, Appendix B, section 2.3.1.1 and using the definition for “opera ting quarter” under part 72.2 (i.e., 168 or more unit operating hours). Commenters 17820 and 17881 state that testing guid elines under section 63.10006(n) should use the operating days and quarter s approach of Part 75.

Response to Comment 13 : As previously explained, the optiona l periodic testing requirements have been made consistent between controlled and unc ontrolled sources, with a reduced frequency of227 quarterly performance testing. In addition, the fina l rule has removed all requirements for duplicative testing of a HAP and a separate alternate equivalent standard (such as filterable PM and HAP metals).

Comment 14 : Multiple commenters (17716, 17725, 155, 17820, 18498, 17775, 17800) request that the testing provisions in the final rule incorporate a gr ace period similar to the Part 75 provisions. According to the commenters, such a grace period allows a s ource time to complete testing after coming back online and would benefit sources an d the EPA by eliminating the need for submission of source specific petitions to seek minor extens ions 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 commenters (17716, 17821, 17881) state th at the specific testing deadlines that are provided in section 63.10006(n) will be overly burdensome not only for limited operation units, but also for units in extended planned or unplanned main tenance outages. The commenters note that section 63.10006(n) does provide windows for testing, they may be inadequate for planned unit maintenance outages. Commenter 17821 suggests esta blishing guidelines and allow so urces to work with state and local permitting agencies to schedule tests.

Comment 16: Commenter 18025 recommends that a unit opera ting hour be defined as a clock hour during which a unit combusts any regulated fuel, eith er for part of the hour or for the entire hour. Commenter is recommending that th is definition apply specifically to the regulated fuels under the Utility Toxics Rule (e.g., coal and liquid oil). By requiring a minimum level of operation to trigger stack testing requirements, states the comme nter, this approach would ensure that no unit is run simply for the sake of testing

Response to Comments 15 - 16: As previously explained, the opti onal periodic testing requirements have been made consistent between controlled an d uncontrolled sources, witha reduced frequency of quarterly performance testing. In addition, the fina l 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 sche dule, instead of annual testing on a 13- month timescale, be revised to “or ev ery other federal fiscal year” or something along those lines so that facilities may coordinate testing with thei r state required permits for consistency.

Comment 18: Commenter 19033 recommends that the HCl sa mpling frequency be reduced from every other month to quarterly in the second year, and bi annual the third year if HC l emissions are measured to be non-detectable for all test s conducted. Accordingly, the comme nter recommends that section 63.10006(j) be amended, as follows: (j ) For solid oil-derived fuel- a nd 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. Prov ided 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 sec tion 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 compa ny’s cost to operate its generation resources. According to the commenter, existing tests such as periodic RATAs are le ss frequent, of shorter duration, and/or allow much more operational fl exibility, and the proposed Utility MACT tests by comparison are far more frequent, of longer dur ation, and demand more ope rational restrictions requiring operators to focus on making their generati ng units available for te sting conditions to the detriment of the primary function of generating electricity. The commente r states that the proposed rule is too prescriptive in telling sources how they are to operate their faci lities. According to the commenter the EPA fails to recognize that re quiring a single unit to satisfy testi ng conditions also constrains other units in the system.

Comment 20: Commenter 17796 questions the proposed fr equency of stack tests in section 63.10006(d). As an alternative to the requirement fo r monthly or bimonthly stack tests (depending on the use of control devices), the commenter recomme nds that once the initial performance test is conducted for PM (filterable and condensable) and non-HAP metals, and fuel sampling procedures and operating parameters are established, compliance will be assured by the use of such fuel sampling and operating data combined with less fre quent (semiannual) stack testing.

Comment 21: Commenter 17925 recommends that continuou s compliance source testing should be required no more frequent than annu ally. The commenter states that th e 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 inst ance, at some coal fired units in the past, opacity monitors couldn’t be applied on we t plumes after scrubbers. As a result, states the commenter, the EPA required annual total particulat e testing by Method 5 inlieu of requiring the operator to make an opacity monitor perform on th e wet plume. The commenter requests the EPA to apply the same sound judgment now with respect to frequency of source testing for demonstrating continuous compliance with metals emissions and HCl.

Comment 22: Commenter 17316 suggests that performance testing for oil-fired units should be conducted every 3 years rather thanthe schedule proposed in section 63.10006(f),(g),(l) and (m) because the proposed schedule is unjustified and a very substantial economic burde n for smaller utilities. Commenters (17316, 17725, 17760) indicate that the total expenditures for such a test program include the direct monthly costs of contr acted testing services and the signi ficant costs of operating oil-fired units strictly for monthly tests when other more ec onomical generating units are available to meet the demand for electricity or requiring du al fired units to burn fuel oil fo r testing purposes when natural gas prices are lower than residual fu el oil. According to commenter 17725, performance testing of a unit without metals or acid gas controls requires a mini mum of 4 full load hours per month; an additional 2 hours at full load for boiler stabiliz ation; potential additional runs if the test crew has problems; and time for calibrations between test runs . The commenter estimates such a unit would operate for 72 hours per year just for testing, not including th e time to start-up the unit, ramp th e unit to full load and then ramp down the unit. Commenter 17725 states that review of published data for 2008, 2009, and 2010 shows at least 34 residual oil-fired units whose 3-year annual capacity factors are 5 percent or less.

Comment 23: Several commenters (17316, 17870, 18428) state that oil is a homogeneous and reasonably consistent fuel, so that variations in the metals, chlorine, and fluorine contents should not be significant and therefore monthly or bimonthly testing is not warra nted. Commenter 17870 states that fuel analysis on each shipment of oil should be sufficient to demonstrate compliance. Commenter 18428 states that in the preamble, the EPA states that additional performance tests for Hg are conducted “at least annually.” However, there is no reference to this annual testi ng in the proposed rule. Given the229 extremely low level of Hg in oil, states the comme nter, any requirement or re ference 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 al ternative to the use of PM CEMS for monitoring non-Hg metals emissions, but the commenter st ates that the bi-monthly stack testing alternative is not practical because the effected source opera tor does not have resident stack testing crews, and the scheduling of tests with contract testing crews and the scheduling of testing loads with the grid reliability control center would be difficult to do every two months. Commenter 17704 states that the amount of metals in the PRB coal utilized at the effected source does not change significantly and annual testi ng should be sufficient for m onitoring the non-Hg metals.

Comment 25: Several commenters (17716, 17725, 17758, 18014) st ate that the proposed frequency of performance testing is not consistent with the exp ected variability in emissions because units without add-on control systems are required to complete stack test less frequently than units with add-on control systems, but for units without add-on control system s, the emissions of HCl, HF, and non-Hg metals are most closely tied to fuel characte ristics. These commenters and comme nter 17402 suggest that in lieu of the proposed monthly or bi-monthly fr equency, periodic fuel analyses sh ould be used to determine if a significant change has occurred since the a nnual performance test. Commenter 17402 provides suggested revisions to proposed section 63.10006 and section 63.10021 outlining a methodology for using monthly fuel analyses and performance te sts conducted every 4 unit operating quarters; the suggested methodology includes criter ia for using monthly fuel samples to determine when higher frequency stack testing is require d. Commenters (17716, 17725) cite statements in the preamble to the proposal indicating that for liquid oil-fired units, no correlation was found between non-Hg metallic HAP emissions and PM emissions or the operation of PM control devices. These commenters conclude that the emissions of HCl, HF, and non-Hg metals are most closely tied to fuel characteristics and that periodic assessment of fuel characteristics should be used to determine whether additional emission testing is needed. This commenter also believes that the source’s expected re moval efficiency should also be taken into considerati on to minimize unnecessary testing.

Comment 26: Commenter 17718 encourages the EPA to ma ximize 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 appr oved test methods, data variability, and short deadlines for testing. The commenter suggest s that the EPA should extend the testing frequencies to at least a quarterly basis to allo w more substantial analysis of gathered data and to reduce potential burdens resulting fro m more frequent laboratory anal yses and test report submittals.

Comment 27: Commenter 17737 states that a monthly testin g frequency is unmanageable for units that do not have SO 2 control technology or HCl CEMS, and the co mmenter states that proposal provide no explanation for this unprecedented frequency. Acco rding to the commenter all plausible operating scenarios that could utilize the co mpliance option for sources without SO 2 controls require use of fuel with very low chlorine content. Insuch cases, states the commenter, fuel analyses provide assurance of compliance at a fraction of the cost. This commente r believes the final rule should allow operators to maintain records of the type of fuel being burned and to perform monthly fuel analyses to demonstrate that the fuel chlorine content is within acceptable limits.

Comment 28 : Commenter 17718 is concerned that the mont hly or bi-monthly performance testing option may be incompatible with timely submissi on of test reports under proposed section 63.10006(t) because historically, testing firms and labs have not handled the high volumes of work implicit in this compliance option.230 Comment 29: Commenter 17821 states that the proposed ini tial 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 d eadlines and will force init ial testing into very compressed schedules.

Comment 30: Commenter 17807 states that the proposed tes ting frequency is not practicable and not justified. The commenter suggests annual stack testi ng and a CAM plan instead of bimonthly testing.

Comment 31 : Commenter 17880 supports the requiring of li quid oil-fired units to conduct additional performance testing for Hg on an annual basis; conduc t additional performance te sts for HAP metals and acid gasses every 2 months for units that have emi ssions controls, and monthly for units that do not.

Comment 32: Commenter 17867 notes that several MACTs allow for less frequent testing given consecutive passing results as follows:

 40 CFR 63 subpart DDDD (Boiler MACT) section 63.7515 – testing frequency is annual until compliance is demonstrated for 3 consecutive years, then frequency is relaxed to every 3 years.

 40 CFR 60 subpart KKKK (Combustion Turbine N SPS) section 60.4340 – testing frequency is annual unless emission are less than 75 percent of the standard, then frequency is relaxed to every 2 years.

 40 CFR 60 subpart DDDD (CISWI MACT) section 60.2720 – testing frequency is annual unless emissions are less than the standard or 75 perc ent less than the standard (depending on the pollutant), then frequency is relaxed to every 3 years.

 40 CFR 60 subpart CCCC (CISWI MACT) section 60.2155 – testing frequency is annual unless emissions are less than the standard or 75 perc ent less than the standard (depending on the pollutant), then frequency is relaxed to every 3 years

According to the commenter, metals and HCI st ack testing every other month is unnecessarily burdensome. Commenter suggests the frequency s hould be extended to ev ery 6 months if two consecutive tests demonstrate compliance with th e standard. The commenter states that if two consecutive semi-annual tests demonstrate compliance, frequency should be ex tended to annual testing, and frequency should be increased if a subsequent pe rformance test indicates the emission standard is not being met or if more than 50 percent of the fuel has been switched to a di fferent type of coal (e.g., subbituminous/bituminous, supply from different basin).

Comment 33: Several commenters (17681, 17870, 18034, 18428) question whether, because of the prescriptive testing deadlines, if a unit is not oper ated 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 th e start date of the performance tests under section 63.10005 should be flexible to allow for monitor certi fication to be complete d, operating conditions to be established, and shakedown of co ntrol devices to be performed.

Response to Comment 34 : The Agency finds that the rule’s st art dates of the performance tests are flexible and will allow for monitor certif ication and similar activities to occur.231 General Response to Comments 1 - 34: For stack test frequency, the EP A has modified the final rule to require quarterly testing if used to demonstrate continuous compliance and included an exemption for testing in quarters with low u tilization (<168 operating hours). In addition, EPA agrees that testing should be required only for the emi ssion limit that the source is comply ing with, and thus the final rule does not require testing of both the HAP and a separate surrogate standard (such as filterable PM for HAP metals).

2. HCl testing section 63.10006(j).

Comment 35 : Commenter 17821 requests that the EPA clarif y this section of th e rule to indicate whether sources choosing to use th e alternate method of compliance w ith 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 conduc t 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 should not require so urces using this alternative to conduct performance testing for HCl every 2 months. Rather, the commenter recommends th at the frequency of perf ormance 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 require ments 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 tes ting 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 pote ntial HCl emissions is the maximum coal chlorine input. For coal-fired EGUs with HCl control devices, states the co mmenter, 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 mon itored to assure complian ce, and as long as there is no change in coal type or coal mixture (or change in emission c ontrol device operations), there is no need to perform HCl stack testing every month or every other month - simply keeping the coal chlorine input below maximum allowable levels (and, as a pplicable, keeping the co ntrol device’s operating parameters within allowed ranges) is su fficient to ensure continuous compliance.

Response to Comment 36: The final rule has removed most of the options for fuel sampling and analysis as a compliance option. Sources choosing to not use HCl CEMS for uncontrolled sources must perform periodic performance testing. However, if you combust liquid fuels and you wish to demonstrate ongoing compliance with HCl and HF emi ssions limits by measuring fuel moisture content of each shipment of fuel in place of quarterly st ack testing, you may develop a unit-specific approach utilizing fuel moisture content measurements, co llect data necessary to support your approach, and petition the Administrator under 40 CF R section 63.7(f) for an alternative compliance testing approach.

Comment 37: Commenter 17725 requests that the final rule clarify that testi ng for HCl is not required if the site operator has instituted the alternate comp liance method of percent wa ter in fuel deliveries.

Response to Comment 37: The final rule has removed most of the options for fuel sampling and analysis as a compliance option. However, if you combust liquid fuels and you wish to demonstrate ongoing compliance with HCl and HF emissions limits by measuring fuel moisture content of each shipment of fuel in place of quarterly stack test ing, you may develop a unit-sp ecific approach utilizing232 fuel moisture content measurements, collect data necessary to support your a pproach, and petition the Administrator under 40 CFR section 63.7(f) for analternative compliance testing approach.

3. Reduced frequency criteria.

Comment 38: Commenter 17821 states that the reduced stac k 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 b ecause the EPA is also re quiring worst-case fuel conditions, full load, and other requirements intended to provide the absolute worst case test conditions for what are relatively short-term periods. In the r eal operating world, states the commenter, a unit will simply not continue to operate in worst-case conditi ons, rather, the average fuel concentration will be less, load will decrease, etc.

Comment 39: Commenter 17821 asserts that the requireme nt that a source must demonstrate compliance for 3 years is far too burdensome. Th e commenter notes that the EPA states “If a performance test shows emissions in excess of 50 percent of the emission limit, you must conduct performance tests at the appropriate frequency given in section (c) throug h (m) of this paragraph for that pollutant until all performance test s over a consecutive 3-year period show compliance”; in other words for the parameters where the EPA is requiring sour ces to test every mont h, or every other month, sources will have to conduct 18-36 individual test before they canqualify for reduced frequency. According to the commenter, this imposes a bur den 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 fre quency of its required reference method testing: first, the EPA should requi re reference method testing that is no more often than quarterly for any pollutant and equipment c onfiguration, and second, once a unit has successfully demonstrated emission levels that are at no more th an 80% to 90% of an applicable standard for 2 consecutive quarters, the testing fr equency 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 detec tion 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 th e removal of prescriptive parameter and fuel monitoring.

Comment 40: Commenters 1775 and 17800 state that the EP A should remove the 50% criterion for reduced testing as the EPA provided no reason for th is restriction. According to the commenters, the EPA has not provided any data suggesting that any source could achieve 50% of the proposed limits some of which are at or near the detection limits.

Response to Comment 40: The EPA disagrees with the commenter and will retain the 50% criteria. The emission standards in th e final rule are at least three times the RDL, so any source below a typical detection limit would meet these criteria. In addition, the quart erly periodic performance testing is an option for sources choosing to not install CEMS or PM CPMS.

Comment 41: Commenters 17881 and 19033 state that sectio n 63.10006(q) is unclear. According to the commenters, it seems the intent is to require that the more frequent testing frequencies must be met if a233 performance test shows emissions greater than 50% of an allowable limit, yet the increased testing frequency is required until all perf ormance tests over a consecutive 3-year period show compliance.

Response to Comment 41: The reduced frequency option is only av ailable to sources that meet the 50% criteria during the 3 year s 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 year s (i.e., no more than 37 months) after the previous performance test. The commenter stat es that in order to qualify for th is reduced testing frequency, 3 consecutive years of testing must show that emissi ons are at or below 50% of the applicable emission limit. In light of the very stringent emission limits, the commenter questions why results have to be less than 50% of threshold. For comparison, states the commenter, in the Boiler MACT, to qualify for reduced frequency, units had to de monstrate emissions at or below 75% of the emission limit. Also, states the commenter, it seems disproportional for units that are testing bi-monthly or monthly to have to conduct 18-36 tests to establish a patte rn of compliance versus units te sting annually to conduct as little as three discrete tests. According to the commente r, reduced frequency should be based on the number of passing consecutive tests; the RICE MACT util izes this concept in that after compliance is demonstrated for two consecutive semi-annual tests, the testing frequency can be reduced to annually. The commenter suggests that for non-CEMS units there should be a tiered approach in regards to the number of passing tests based upon th e 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 quarter ly testing. Also, the quar terly periodic performance testing is an option for sources not choosing to install and operate CEMS.

Comment 43: Several commenters (19536, 19537, 19538) assert th at the frequency of testing should depend upon the variability of each parameter. Acco rding to the commenter, when a parameter is variable, more frequent monitori ng 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 regulate d emissions are very highl y variable and the EPA uses this justification in establishing extraordinaril y aggressive statistical adjustments. The commenter states that the EPA’s calculations predict emissions from existing sources which range from 2 to 56 times greater than the average data yielded from a test. For new sources, states the commenter, the EPA’s calculations predict emissions from 2 to 6 times greater than the average, and according to the EPA’s beyond-the-floor analysis (or lack thereof) there are no operati onal methods available to reduce that variability. Given the unavoi dable variation, states the comme nter, continuous compliance cannot be determined using the periodic testing proposed in the rule. Accord ing 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 complia nce 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 exempti on provide adequate a le vel of assurance with compliance for better performing units. For non Hg HA P, the sources must show levels below the threshold for quarterly performance tests over a 3-y ear period. In addition, a ny 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 ot her rules containing provisions for parameter monitoring as discussed in section 5A05.

Comment 44: Commenter 17718 requests that the final rule include a cl arification to the proposed language at section 63.10006(o) regard ing the criteria for reducing the fr equency of performance testing; the final rule should clarify what constitutes “no ch ange” and what information would be needed to successfully pass these criteria. For example, stat es the commenter, it is unclear whether the “no change” provision applies to the affected unit and is not inclusive of the entire facility.

Response to Comment 44 : ”No change” would apply to the affected unit.

4. Comments related to “highest content” of HAP.

Comment 45: Commenters 17731 and 17881 state that the require ment to use worst case coal with the “highest content” of HAP in performance testing is not reasonably possible in part due to natural variability. According to the commenter s, there is a very real possibilitythat even if the worst case coal could be identified, that co al very well may not be available for purchase. The commenters state that the proposed rule also fails to distinguish emissions testing requirements among regulated parameters. According to the commenters, the worst case coal is not likely to be the same relative to each of the regulated parameters under the proposed rules. T hus, according to the commenters, EGUs would have a nigh-impossible task of identifying a suite of worst case coals and proc uring each of those in order to conduct the required testing. Comm enter 17881 suggests defining a primary fuel and retesting on changes to the primary fuel. According to the comme nter 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 exp ected fuel(s), it is entirely possible that the actual HAP input will increase beyo nd the levels observed during the initial performance tests/fuel sampling and analysis simply due to fuel variability al one (and not a change in fuel type(s) or blends).

Comment 46: Commenter 17718 states that the proposed regulatory language (40 CFR 63.10007(c)) provides that performance tests must be conducted “wh ile burning the type of fuel or mixture of fuels that has the highest content...” The commenter belie ves the EPA should clarify whether reference to “type of fuel” simply means that if bituminous coal is typically burned then b ituminous 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) co ntent bituminous coal be used during the test. The commenter also suggests clarifica tion that “special fuels” are not required or expected for the performance test.

Comment 47: Commenter 17781 states that for performan ce testing under sect ion 63.10007(c) the EPA should specify that fluorine content is only relevant for liquid oil-fi red EGUs, as no other category of EGUs are subject to HF emission limits.

Comment 48: Commenter 19121 states that placing testing cr iteria on multiple fuels is burdensome, and close to impossible to include a ll 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 a nd based upon pricing, availability and access.

Response to Comments 45 - 48: Periodic performance tests must be conducted using the fuel type or blending that would represent the highest HAP loading to the control devices for th at period of testing. If235 the source is unsure which fuel would result in the highest HAP loading, they may perform multiple tests within that test period or opt to use CEMS to ensure conti nuous compliance with the standard.

5. Testing deadlines.

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 minimu m amount of time since the la st 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 a pplicable deadline, the future test schedule is simply adjusted based on the completion date of the test.

Response to Comment 49: The final rule will be amended in order to remove the minimum amount time since the last test requirement.

6. Comments regarding performance te sting and maximum operating load.

Comment 50: Commenters 17730 and 17886 state that the propos ed 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. Th e commenters state that for EGUs using CEMS the performance test will run for 30 operating days. Accord ing to the commenters, it may not be possible for sources to maintain a “maximum” normal operati ng load for a full 30 operating days. The commenters believe that the EPA should simply require representative operation of the unit duri ng performance testing.

Comment 51: Commenter 17316 states that section 63.10007 indi cates that performan ce testing must be conducted at “maximum normal operati ng load”; however this term is not defined. Commenter suggests that the rule allow sources to a pply the Part 75 Appendix A, secti on 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 commente r, such an approach allows a source to test at a representative load, but ensures te sting is conducted at a high load, and hopefully such an approach would reduce the need to perform multiple stack te sts, 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 lo ad has little significant impact on HAP emissions (FR Page 25037).

Comment 52: Commenter 17881 states that specifying that the performance tests be conducted at maximum routine operating load is not appropriate, as the EGU should have the flexibility of conducting the test at whatever load is desired with the understanding that in those cases where compliance is demonstrated through performance testing, the averag e load observed during th e performance tests will be used to set a maximum load restriction for all future operation (at 110 per cent of the average load during the tests).

Comment 53: Commenter 18024 recommends that if complian ce can be achieved by co-firing natural gas and oil at the same time, then a liquid fuel-o nly compliance demonstration would not be necessary or appropriate so long as enfor ceable co-firing operating restric tions were implemented. Commenter states that low load operation shou ld be allowed as compliant operati on if the mass emission rate of any HAP is maintained below the equivalent full load HAP emission level calculated as the MACT Floor. The commenter requests that the EP A develop a compliance option that represents normal operation of a facility and eliminate testing in modes of operation that are rarely or never utilized.236 Comment 54: Commenter 18444 states that the EPA should re quire that states set maximum allowable hourly heat inputs for each unit and that testi ng 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 test ed infrequently (such as particulate HAP). The commenter notes that the proposed rule language on main taining heat input within10 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 percent fuel gas flow rate increase through an ESP. According to the commenter, air pollution control systems are designed for a maximum flue gas flow rate which is directly relate d to heat input; ESPs are very sens itive to higher amounts of fuel being burned, and scrubbers are also affected as well. The commenter recommends testing within 5 percent of the maximum allowabl e hourly heat input.

Comment 55: Commenter 18023 states that notonly do individual units see significant variability in steady-state full load stack test results, these measurem ents are not representative of the variability that a unit may experience on a continuous ba sis through all modes of operati on, including startup, shutdown, and malfunction, as may be measured by a PM CEMS.

Comment 56: Commenter 17881 states that it may not be po ssible to meet operating limits set at the maximum routine operating load at other reduced lo ads and therefore the con cept of conducting multiple sets of performance tests at different operating loads under sec tion 63.10007(c) is unworkable. The commenter appreciates the EPA’s attempt at recogni zing that it may not be po ssible 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 per cent of rated capacity and establish separate sets of operating limits, wh ich set of operating limits would a pply 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 betw een to two test conditions) or ≤ 100 percent capacity?

Comment 57 : Commenter 17881 suggests that a more realistic approach is to specify that the operating limits only apply during those period s when the EGU is operating withina certain percentage of the average load condition associated wi th the performance test. The commenter states that this approach would be consistent with that taken by the EPA in 40 CFR 63, subpart ZZZZ – NESHAP for RICE. The preceding rule requires that performance testing be conducted at 100±10 percent of rated load (see Table 1a of subpart ZZZZ), and the operating limits establis hed during testing (i.e., pr essure drop for oxidation catalysts) only applies when th e unit operates at loads of 100±10 percent (see Tables 1b and 2b of subpart ZZZZ). Thus, states the commenter, this approach avoids the possi bility of applying an operating limit established at a specific operating lo ad to loads not evaluate d during the concurrent performance test.

Comment 58: Commenter 17881 suggests another potential appr oach would be to use the performance test and associated opera ting 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 se t at a minimum pressure drop of 35” w.c., and the performance test could be used to verify that PM emission rates an d or non-Hg HAP Metals emission rates at pressure drops at or above the vendor reco mmendation comply with the applicab le 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 conduc ting the stack testing, four parameters indicative of NO X emissions, along237 with the vendor recommended values or ranges fo r these parameters across the expected operating range, are identified. During testing, states the co mmenter, the actual parame ter values must be consistent with the vendor recommended valu es or ranges, and the EGU must conduct ongoing monitoring of the parameters followi ng 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 to be completed, beyond wh at is already proposed in other sections of the regulatory language. The comme nter states that other sections of the proposed regulatory language specify when, how and under what conditions the performance testing is to be conducted, and therefore, the proposed secti on 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 th an 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 performan ce testing could literally take months to perform. As an example, states th e commenter, the commenter enjoys high availability due to redundancy of systems. For instance, states th e commenter, the scrubber for each unit consists of six modules; four modules are required for full load, two or three modules for start-up and low loads. The commenter states that completing a performance te st 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 te sts to meet the rule would be incredibly arduous and costly.

Response to Comments 50 - 60: We agree with commenters on the n eed for the regulation to define more clearly what constitutes re presentative process operating load during performance testing. There are generally three testing scenarios each with di fferent definitions of representative operating conditions. First, if the sour ce uses CEMS (Hg, HCl, or SO 2 ) to determine compliance with the limit that applies over a 30-day averaging pe riod, the rule need not specifyany minimum process operating conditions. Compliance is based on a di rect measure of emissions in unit s of the standard for the entire 30-day averaging time for all periods the proc ess 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 conti nuous compliance with an operating limit based on measurements from the PM CPMS rather than an em issions limit. That operating limit is derived from data collected during a short term (three test run) performa nce test for either filterable PM measured with Method 5 or non-Hg metals measured wi th Method 29. For the purpo ses of establishing a representative operating limit, the rule will spec ify that the unit be operated at maximum normal operating load conditions during th e performance test period. We understand that actual maximum normal operating load for a particular facility is un it dependent but we expect it will be generally between 90 and 110 percent of desi gn capacity. The rule will requ ire 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 pe riod that extends over more than one day.

The third scenario applies if the so urce owner elects to conduct frequent performance testing in lieu of continuous monitoring. In such cases, the rule will sp ecify that the unit be operated at maximum normal238 operating load conditions during eachperiodic (e.g., quarterly) performance test period. As noted above, actual maximum normal operating load for a particular f acility is unit dependent but we expect it will be generally between 90 and 110 percent of design capaci ty. Maintaining this high load operating condition need not be continuous during the time it takes to comp lete all of the performanc e testing but is required only during each test run.

7. SO 2 CEMS issues.

a. Comments related to LEE (testing/monitoring).

Comment 61: Commenter 17800 states that in proposed s ection 63.10021(a)(11)(iv) and (v), the EPA proposes to require sources using PM CEMS to report “performance test data, except opacity data” and “relative accuracy test au dit data” electronically using ERT starting January 1, 2012 (FR Vol.76, No. 85, p. 25,117) and section also requires the reporting of “performance test data, except opacity data” and “relative accuracy test audit data” for LEEs (FR Vol. 76, No. 85, p. 25,117-18). According to the commenter these provisions do not make sense b ecause 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 a pplicability with emission tests and thereafter by fuel analysis and therefore LEEs have no monitoring systems upon which to conduct RATAs; and 4) with respect to “performance test data,” the provisi ons are duplicative of a mo re 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 th e cited text. The recordkeeping and reporting provisions in the final ru le 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 requireme nts (i.e., CEMS) and therefore if not equipped with a CEMS how would one su bmit 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 qualificati ons for the Hg LEE status are egregiously 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 th e sorbent traps at week-long sampling durations. The commenter strongly suggests the EPA revisit this portion of the proposed rule in consultation with experienced outside experts.

Response to Comment 63: Under the final rule, all Method 30B te sts are to be run on a 30 day basis. The maximum run length for a sorbent trap is se t at 15 operating days for both Method 30B and a sorbent trap monitoring system. As long as the crit eria for sampling within the calibration range of Method 30B are met, the source may reduce the sampli ng 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 itis unclear whether the EPA intended the fuel input limit on Hg, and additional operating limits on Hg controls and load apply to LEEs. The commenter states that they should not.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 commenters (17808, 17870, 18025, 18031) support the LEE approach but recommend continuous compliance methods the comme nters feel are less bur densome. Commenters 17870 and 18031 recommend instead of monthly fuel te sts provide an option to conduct annual Method 30B test to demonstrate emissions are less than 10 % or the applicable lim it or less than 22.0 pounds per year. If a LEE unit exceeds LEE limits, commenters pr opose that it revert b ack to more frequent performance tests (e.g., quarterly, as recommended be low); the subsequent year , if the unit can, again, demonstrate LEE status through reducedutilization 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 proce ss similar to that suggested by this commenter. If a unit qualifies as an LEE for Hg, th en annual testing is the only ongoing requirement. However, if the unit tests at above 10% of the standard, the LEE status is lost and the source must move to install, certify, operate and maintain an Hg CEMS or sorbent trap monitoring system. Specific testing requirements will apply in the interim prior to th e CEMS or sorbent trap monitoring system being certified.

Comment 67: Several commenters (17808, 17870, 18025) also recommend allowing sources to schedule their annual performance test s at any time during a 12-month cy cle. 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 th ese units operating well below the proposed sta ndards. 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 co nducted 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 con centration 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 demonstrat e that emissions are less than 50 percent of the relevant emissions standard.

Comment 70: Commenter 18025 states that the rule should cl arify the requirements for oil-fired and coal-fired LEEs. The commenter believes this will help reveal where gaps may be occurring.240 Response to Comments 69 - 70: The final rule eliminates the fu el 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 once per year for that pollutant but must revert to quarterly testing or other monitoring options if a performance test exceeds that 50 percent threshold.

Comment 71: Commenters 17808 and 179227 request clarification that LEE status is available to all subcategories and all HAP, not just Hg from coal un its. 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 mon itoring requirements for other HAP and fuels are not specified in Table 5.

Response to Comment 71: The EPA will clarify that the LEE stat us 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 app licable pollutants (e.g., PM, HCl, Hg).

Response to Comment 72: For Hg, the answer is no, assuming the source maintains its LEE status. For PM and HCl, a CPMS or CEMS is not required under any condition. It is an option, but a source can instead opt for quarterly testing.

8. LEE Applicability Threshold

Comment 73: Commenter 17785 recommends that for LEEs th e EPA set fuel concentration standards for Hg that are, based on the demonstrated Hg control efficiency in complianc e test, equivalent to 22 lb/year of Hg emissions. According to the commenter , it does not seem appropriate to apply the fuel sampling criteria for determination of compliance of LEE units, if these fuel limits would represent emission lower than the LEE Hg threshold of 22 lb/year. The commenter believes their waste coal plants are expected to continue to emit less than 5 lb/year, so it is likely that the imposition of a fuel Hg limit based on average Hg or 90 thpercentile Hg would set an effective Hg emission limit that is likely less than 10 lb/year. According to the commenter, this is an unnecessa rily 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 require ments for operational limits and fuel sampling and analysis for LEE units. Compliance w ith LEE status will be achieved through annual performance tests.

Comment 74: Commenter 17620 agrees that units that have de monstrated an ability to consistently limit emissions substantially below applicable limits shoul d 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 pr otective levels. The commenter stat es that the EPA has proposed to allow reduced testing for sources ba sed 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 re duced testing for Hg if the source’ s emissions were either less than 25% of the applicable limit or less than 22 lb/year. Incontrast, states the comme nter, in calculating the241 Hg MACT floor, the EPA asserts th at even the best performing units can reasonably expect year-overyear stack test results to vary by a factor of 50 because of statistical variability, operational variability, measuring system variability and variability in fuel. The commenter states it is convinced that year-overyear compliance testing of well-performing units will de monstrate 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 Agen cy’s desire to provide incentives for owners or operators to provide additional emi ssions reductions. The provisions offer easy entry, as the initial performance testing results can be the basis for qualifying, but strenuous maintenance requirements, for the results of every test conducted for any reason must meet the qualifying requirements. Should those requirements not be met by ju st 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 ach ieved through a 30-day performan ce test repeated annually, that documents emissions are less than 10% of the standard or less than 29 lb/year. If results from a single test are above that threshold, the source will have to use Hg CEMS or a sorbent trap monitoring system. For non-Hg LEE status, the source mu st demonstrate that test result s 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 vari ability – 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, th e proposed limit of 0.12 lb/MMBtu is near or below the in-stack method detection limit, and it will be very difficult to confidently prove compliance under any testing regimen. The commenter states that th e 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 standa rd 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 with in QA/QC criteria of the method. With increased time as allowed in LEE testing, Method 30B is technically capable of demonstrating emissions at the LEE threshold. In addition, the mass alternative provides an other 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). Co mmenter presumes that, in light of the Hg calculation errors discovered in th e proposed rule’s foundational data si nce its publication in the Federal Register, the agency will revisit the lb/yr cut-off calculation at the reasonabl e fifth percentile level.

Response to Comment 76 : The agency disagrees with the co mment, for the Hg LEE threshold was determined independently from the proposed rule’s Hg limit. The rule contains no change to the Hg LEE threshold.

Comment 77: Several commenters (17754, 17812, 17838, 18963) st ate that LEEs with Hg emissions below 50% of either of the pr oposed LEE thresholds should be pr ovided an option to demonstrate continuous compliance through annual stack testing, and should not be re quired to conduct monthly fuel analyses so long as the fuel supplier does not change . According to the comment ers, annual testing could consist of three 120-minute test runs performed using EPA Method 30B. Sources emitting at very low Hg emission rates are highly unlikely to show em issions 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. In lieu of fuel sampling, annual LEE performance testing will be required.

Comment 78: Several commenters (17754, 17838, 18963) state thatan alternative to LEE compliance is to use a fuel-factor based approac h. According to the commenters, th e EPA could revise the specific fuel-factor based approach currentlyrequired under the proposed rule. Th e commenters believes that the requirement to use the 90 thpercentile 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 th e 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 pe rformance test (for demonstrati ng LEE status) would be conducted over a 28-30 day period; subsequent perf ormance testing, on a 5 year cycl e, should consis t of three 120- minute test runs, performed using Method 30B.

Step 2: Determine the Hg content in the fuel on a monthly basis.

Step 3: Calculate the average Hg content in the fuel on a quarterly basis (i.e., by averaging the Hg content levels measured during the 3 months comprising the quarter).

Step 4: Apply the control efficiency determined duri ng the stack test to the quarterly average Hg fuel content. If the projected annual emission rate (calculated by multiplying the control efficiency determined during the performance test by the Hg fuel content) is less than or equal to 50 percent of the 22 lb/yr LEE threshold (i.e., 11 lb/yr), then the ow ner/operator remains subject to this process for demonstrating that the facility conti nues 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 dem onstrate 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 conti nues 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 demonstrati on 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 tes ting 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 st ack testing result suggest s that the facility’s annualized Hg emissions could exceed 11 lb/yr, the fac ility should not be perpetually precluded from reestablishing very low emitting status.

Response to Comment 78: The final rule has been amended to remove the fuel sampling and analysis requirement of the LEE option. In lieu of fuel sampling, annual LEE performance testing will be required.

Comment 79: Commenter 17927 questions whether an EGU that fires coal or solid-oil derived fuel that has not determined if it qualifies for LEE EGU status pe r the proposed rule have the option of any of the243 testing options listed in Table 5 (p erformance testing, Hg CEMs, sorbent trap monitoring system, or 28- 30 day LEE testing) for the initial performance test.

Response to Comment 79: Initial compliance for coal or solid -oil derived fuel may only use the Hg CEMS, sorbent trap monitoring system or LEE testing options.

Comment 80 : Commenter 17927 requests that the EPA clarif y whether an existing coal or solid-oil derived fuel-fired unit the performs a 1-day performance test per Table 5 after the final rule is published and within the 3-year compliance de adline for affected units have th e option of complying with the LEE requirements.

Response to Comment 80: LEE requirements for Hg must be met with a 30 day Hg performance test. For other pollutants, LEE status re quires a series of periodic tests that show emissions are routinely below 50% of the standard fo r the applicable pollutant.

Comment 81: Commenters 17627 and 17718 believe that the EPA should reconsider the frequency and types of monitoring that are appropriate for variou s 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 th resholds for Hg (10%) and all other HAP emission limits (50%).

Response to Comment 82: Because of the evidence of widespr ead contamination with a risk of significant adverse health and environmental effects a ssociated 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 source conduct periodic em issions testing in lieu of monito ring continuously for compliance with the Hg emissions limit.

As mentioned elsewhere in this document and rule preamble, merc ury is a powerful neurotoxin that persists in the environment indefinitely and its emissions warra nt special attention.

Comment 83: Several commenters (17781, 17838, 17902) state LEE units that operating outside the operating limits established during the most recent pe rformance 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 recentperformance test should trigger a requirement to conduct a timely LEE qualification re-test based upon anexpanded operating limit (consiste nt with the original operating limit excursion). Commenter 17781 states that if the re sults of the LEE qualificati on re-test indicate that the unit continues to qualify fo r LEE status (i.e., meets section 63.10005(k)(1) and (2)), then the EGU should maintain its LEE status; if th e testing does not show that the EGU continues to meet LEE status, then the EGU should be subjected to enhanced monito ring (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 fi nal monitoring requirements do not provide for this suggestion. The only parameter m onitoring that applies is a PM CPMS, and the expectation if that I used is thata source is unlikely to opt for LEE st atus after the 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 ru le does not require the establishment of a fuel input operating limit. According to the commenter, the requirements do not address single-fuel units, changes in fuel type, or units that burn or co -fire multiple fuels, and presumably, LEE units would follow an analogous procedure to non-LEE units and r eassess the ability to meet LEE status based on the new fuel type/blend. According to the commenter, this would require sources that burn multiple fuel types or blends to establish a fuel-input operatin g limit during the initial co mpliance demonstration. The commenter recommends that consistent with th e non-LEE requirements, the EPA should remove the arbitrary monthly sampling requireme nt and allow sources to conduct fu el sampling only when there is a change in the fuel type and that for single-fuel units, the EPA should specify that these units are not required to comply with any of the fuel sampling requirements.

Response to Comment 84: The final rule has been amended to remove the fuel sampling and analysis requirement of the LEE option. In lieu of fuel sampling, annual LEE performance testing will be required.

Comment 85: Several commenters (19536, 19537, 19538) stat e that the EPA should discard the proposed “Low Emitting Units” monitoring protocols. According to the commenter, because the EPA’s standards are based upon a 99% UPL a majority of plants should be able to genera te test data sufficient to claim such “low emitting” status. The commenter st ates that as summarized in Table X-1, the EPA’s proposed MACT standards exceed the tested emissions of the plants for which the EPA has data by the ratio greater than 2 for all non-Hg HAP (i.e., the test ed emissions are below 50% of the standard), and greater than 10 for Hg (i.e., tested emissions are less than 10% of the st andard). As a result, states the commenter, almost all existing and new units will likely be able to exempt themselves as LEEs; in combination, the EPA’s variability adjustments and LEE exemption allow mostunits to avoid any significant monitoring of emissions.

Comment 86: Commenter 18487 urges the agency to either discard its “Low Emitting EGU” provisions, or to substantia lly revise them; if the emissions variab ility asserted by the agency exists, the threshold conditions required for qualification as a “low emitting” unit provide no significant assurance that emissions will remain below the proposed standards.

Response to Comments 85 - 86: The agency disagrees with the comment to discard the incentive for an EGU owner or operator to seek LEE status. While emi ssions data collected as a result of the ICR and adjusted using the UPL calculation shows an EGU’s potential variability, well-operated EGUs – such as those qualifying for LEE status - are expected to have much less variable emissions. The Agency believes that the requirement to revert to the orig inal 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 alternativ e compliance with some modifications. The commenter recommends that any facility that ei ther significantly over-complies with the emissions standards, or is overall a low emitte r by mass in the case of Hg, should be afforded significant leeway in terms of performance testing and fu el analysis. Most of the commenter ’s Illinois facilities installed ACI controls in years 2008 and 2009, and have reduced Hg emissions below 22 lb/yr. The commenter states that such plants conduct semiannual performance st ack tests utilizing Method 30B for compliance, and use sorbent traps for tracking ACI ef fectiveness. According to the co mmenter, the rule should be clear that low emitters can use Hg monitors to track perf ormance, rather than for compliance. The commenter notes that this approach is consistent with th e EPA’s long history of exempting low-emitting sources245 from monitoring or allowing those sources to us e less rigorous and lower cost monitoring technology, rather than requiring continuous monitoring. The commenter states that the EPA first used a de minimis exemption to exempt certain units from Acid Ra in CEMS monitoring regulations in 1993 and that similarly, in 1998 the EPA included low emitter provisi ons 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 mainta ining LEE status, given that Hg em issions testing need only occur annually and non-Hg emissions testi ng need only occur once every 3 years. With that incentive for reduced testing frequency comes th e responsibility for ensuring units continue to meet LEE status. While the agency expects owners or operators wi ll want to ensure prope r operation by monitoring control device effectiveness, along w ith other relevant items, the agen cy also expects adherence to LEE status requirements, meaning that should measur ed emissions exceed the LEE threshold, LEE status would become revoked.

Comment 88: Commenter 17902 recommends that the EPA s hould clarify that for LEE qualifiers it exempts units from a CEMS requirement as well as bi-monthly performance testing. Also it should not require monthly fuel analysis- this should only be required when there is a fuel switch or allow for obtaining the data from the fuel supplier. For exampl e, states the commenter, a unit could qualify for LEE for non-Hg metals by being less than 50% of the total PM limit (even if HCl or Hg emissions are not LEE status). According to the commenter, this unit would not be required to install a PM CEMS and would require fuel analysis only when there is a fuel change plus repeat the performance test every 5-
years.

Response to Comment 88: LEE status is unique to each regu lated HAP. A source may achieve LEE status for one HAP while not for another.

9. LEE fuel sampling issues.

Comment 89: Commenters 17767 and 17807 express concern over the fuel sampling and the potential for variability. Commenter 17767 states that there is no discussion of allowable tolerances to the Hg, chlorine, and HAP Metal content limits set for ongoing qualification for LEE status. The commenter states that it is unreasonable to a ssume that, given the natural variabilitywithin even the same coal seam as well as the error of the analysis methods, the constituents will be consistently below the concentrations observed during the performance testing; this would make the LEE methodology undependable and functionally unworkable. Commente r 17807 states that a single date point is not sufficient to demonstrate emissions in excess of th e 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 th e commenter, it would be impractical and environmentally impr udent to store coal for extended periods of time just to wait for laboratory analytical results.

Comment 90: Commenter 17928 states that under the LEE an o il analysis required to comply with the input-based standards requi res very low detection limits not typically available in national labs. According to the commenter, there ar e a limited number of laboratories th at do these tests to the limits of detection needed; these analyses are too costly to have performed on the regular basis proposed in the rule; and the oil-fired units typically have low capacity factors, another factor that argues against regular oil testing.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 a ccount for any particle bound Hg emissions. The commenter recommends that an ini tial performance test for Hg emissions include an accounting of any particle bound Hg; an option would be to demonstrate th at total Hg emissions is less than 10% of the Hg emission limit or less than 22 lb/yr using a test me thod that measures total Hg. The commenter states that if the particulate bound Hg is 5% or less than the total, subseque nt testing could measure only the vapor phase Hg emissions; if EPA Reference Met hod 29 or ASTM Method D6784-02 (2008) is used to determine total Hg emissions, only thr ee 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 st ates that current stack test methods should be sufficient for determining compliance with LEE stat us and a unit is still re quired to conduct monthly fuel sampling per section 63.1 0006(c) that would se rve 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 emission s that are monitored by the CEMS. According to the commenter, this would serve to keep HAP emissions consistent, and again, fuel analysis is conducted monthly for LEE units to evaluate potential increases in constituen ts that might result in higher emissions.

Comment 93: Commenter 18539 is concerned thatthe proposed rule does not adequately address the operating characteristics of fuel-flexible units. Accord ing to the commenter, the nature of monitoring requirements, both initial and every 5 years, in addition to parametric monitoring, will hinder many sites from using multiple fuel sources and types where there was not a restriction before this rule. The commenter states that this aspect will not only diminish the operationa l and financial flexibility of the facility, but it has the potent ial to virtually prohibit large segments of fuel suppliers that have elevated metals and other HAPS, and all the while there may not be any economical substitute for the unusable fuel, thus causing extreme localized economic and employment losses.

Response to Comments 89 - 93: The final rule has removed the requirements for operational limits and fuel sampling and analysis for LEE units. Compliance with LEE status will be achieved through performance tests. Increased sampling volumes may not be necessary, but must be sufficient during LEE testing such that the in stack de tection limit is less than the LEE threshold. See responses to comments elsewhere in this document relative to particulate Hg measurements.

10. Belt sampling.

Comment 94: Commenters 17730 and 17775 state that section 63.10008 includes very specific requirements for collecting composite fuel samples. The commenters state that for belt sampling, the rule requires that the belt be stoppe d. Commenters believe that this re quirement is unreasonable because it would not allow for the use of continuous belt samp lers; many belts cannot be restarted with coal on them because the belt is too heavy for the motor to st art. The commenters state that for sampling piles or trucks, the rule requires (among ot her things) use of a “square shovel, ” collection of samples at a depth of exactly “18 inches,” colle ction at five locations “uniformly spac ed over the surface of the pile,” and breaking of pieces larger than ex actly 3 inches (proposed in sec tion 63.10008(c)(2)(ii) and (d)). The commenters note that they do not obj ect to the intent behind these propos ed 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 pie ces. The commenters believe these requirements are excessively prescriptive and that the EPA should remove the prohi bition on moving belt samplers, and247 re-examine and moderate the pile sampling requiremen ts to provide more rea listic criteria (e.g., use the same shovel for all samples, collect samples at a uniform depth of approximately 18 inches, and break apart large pieces (e.g., pieces greater than 3 inches).

Response to Comment 94: The final rule has removed the requirements for operating and fuel limits with the exception of a PM CPMS.

11. Sorbent trap.

Comment 95: Commenter 17870 supports the use of sorbent traps for units not equipped with CEMS.

Response to Comment 95: The EPA thanks commenter for its comment.

Comment 96: Several commenters (17696, 17775, 17868, 17800) stat e that the EPA should provide an explanation for the difference in the days the sorbent trap is used. According to the commenters the rule provides 14 days for non-LEE units and 10 days for LEE units.

Response to Comment 96: The final rule will be amended to allow 15 days for LEE unit performance
tests.

Comment 97: Commenter 17696 does not believe that there should be any limit on the number of days that sorbent traps may be used to sample Hg. The commenter has periodically used sorbent traps over the past 2 years at five faciliti es 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 so rbent traps are routinely changed out within 14 operating days, there is no reason to invalidate a pair of sorbent traps simplybased on the duration of their use in the event unforeseen circumstances prevent removal of the traps on schedule. The commenter states that notably, the Illinois Mercury Rule doe s not restrict the number of days a sorbent trap may be used. (See 35 Ill. Admin. Code Part 225, Subpart B, App. B, Continuous Emission Monitoring Systems for Mercury, Exhibit D, Quality Assurance and Operating Procedures for Sorbent Trap Monitoring Systems.) Commenter states that sucha prescription on the durat ion 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 validityof sorbent traps should be the QA/QC criteria already in place fo r the sorbent trap monitoring method, and not the duration of use. If a trap samples for too long, stat es 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 recove ry and vapor phase breakth rough specifications)). According to the commenter, those QA/QC criteria are, by themselves, a powerful incentive not to sample for too long. However, states the commenter, if an EGU is forced to use a sorbent trap to sample for a longer duration than expected because of, for example, bad weather or mechanical problems with the stack elevator, the EGU should still be able to us e the trap data if the QA/ QC criteria are met; the duration of use does not itself advers ely affect the performance of th e 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 allo w use of sorbent traps for 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 days for Hg LEE testing. Issues extending the sample time by a day su ch as bad weather or mechanical issues can be handled on a case-by-case basis through a minor alternative monitoring requests.

Comment 99: Commenter 17927 requests clarification as to whether an existing coal or solid oilderived unit that is found not to be an LEE is required to install a sorbent trap monitoring system to demonstrate continued compliance.

Response to Comment 99: The source would be required to instal l sorbent trap monitoring system or Hg CEMS.

12. Oil-Fired testing.

Comment 100: Commenter 17818 states that they agree with the EPA’s proposed requirement for units firing residual liquid oil fuels. However, the commenter believes th at the testing requirements are excessive for units that utilize distil late liquid oil fuel, and that fire no residual fuel oil; after the initial performance test such units shou ld 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 distillat e fuel oil quality and chemical composition such that there would be little variabili ty in the emission of HAP metals, HCl, or HF.

Comment 101: Commenters 17716 and 18498 state with respect to the EPA solicitation of comment on “a limited-use subcategory to account for liquid oil-fired units that onlyoperate 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 co mmenters, limited operation that precludes the ability to conduct stack testing is no t a phenomenon limited to only liquid oil-fired units; timelines for completing subsequent performance tests for all units should be ad justed 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 almostas clean as natural gas, do not need a particulate emission limit or testing to demonstrate compliance. According to the commenter, periodic opacity testing is not needed either; a no visible emission standard is achievable and reasonable for ultra-low sulfur distillate oil.

Response to Comments 100 - 102 : The final rule has been amended to reduce all liquid oil-fired EGU performance testing to quarterly and to subject limite d use (capacity factor le ss than 8% in a 24 month block average) sources to work practice standards in lieu of numeric emission limits. In addition, the fuel sampling and analysis requirements have b een removed. The only fuel-related provision is an option for liquid oil-fired units to demonstrate compliance with the acid gas standards by documenting that fuel moisture content remains no greater th an 1.0%. This demonstrati on is based on monitoring results or fuel suppl ier certifications.

13. Measurement issues.

Comment 103: Commenters 17724 and 17729 state that for ne w units the limits are so low that adequate test methodologies to demonstrate complia nce do not exist. According to the commenters, without accurate testing methodologies, contractor s 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 virtua lly impossible to secure; and this will effectively preclude the construction of any ne w coal-based units. Commenter 17729 not es that this will affect the balance of fuel diversity in the energy supply.

Response to Comment 103: The final rule new source emission limits have been adjusted to three times the RDL to ensure the required test methods can demonstrate compliance.

Comment 104: Commenter 17716 states that in section 63.7520(d) the EPA specifies a minimum sampling time of four hours for eac h test method, following the procedur es used to establish the MACT floor data. Commenter asserts that 4 hours seems ex cessive for certain pollutants. According to the commenter, the required sampling times should be reevaluated and/or alternative minimum sample volumes should be provided for each method, taking into account representative analytical detection limits and emissions standards that are fully adjusted for non-detect values.

Response to Comment 104: The EPA has reviewed the final emission limits, sample volumes and RDL to ensure that a realistic sample volume and durati on is provided. Sources may also request alternative sample volumes as outlined in 40 CFR 63.7.

Comment 105: Commenter 17718 states that the EPA should clarify the specific testing (initial and subsequent) and monitoring requirements for a unit with bypass capability. Sp ecifically, states the commenter, the EPA should clarify whether initial te sting of the bypass emissions need to be tested within the 180-day timeframe described in the propos ed language. Alternatively, states the commenter, setting a firm testing timeframe on bypass stack emi ssions seems overly burdensome. According to the commenter, creating emissions (and incurring costs) by switching a uni t into bypass mode that would not otherwise have been used simp ly in order to perform emission te sting appears to create unnecessary burden.

Response to Comment 105: Due to the potential for technical issu es with the use of CEMS or a PM CPMS on the bypass stack, the final rule provides the opt ion to either install a nd operate a CEMS or PM CPMS in the same manner as a main stack, or to tr eat hours in which the bypass st ack is used as monitor downtime.

14. Fuel sampling issues.

Comment 106: Commenter 17716 suggests that the fuel sampli ng, analysis and calculations proposed in section 63.10021 could be applied for uncontrolled units and believes thatfor controlled units, annual testing is sufficient to demonstr ate proper operation of control devices. Commenter 17716 believes the provisions for fuel sampling, analysis, and calculation of expected emission rate s proposed in section 63.10021 should apply to liqui d oil-fired sources.

Comment 107: Commenter 17402 states that the EPA s hould allow compliance through annual performance testing rather than bimonthly or monthly, when combined with monthly fuel sampling for facilities that use a single fuel type. According to the commenter, data in the docket indicate that over the long term, facility compliance is fairly consistent despite the potential for variability in fuels and operations to affect emissions levels. The commente r states that the EPA should allow facilities to comply with the performance testing requirements on an annual basis by coupli ng the less frequent stack testing with more frequent fuel sampling.250 Comment 108: Commenter 17402 states that the EPA should cl arify when fuel sampling requirements apply. For example, states the commenter, fuel sa mpling should not be required for units that employ CEMS. According to the commenter, for units that only burn one type of fuel, sampling should only be required monthly if being used as part of a conti nuous compliance program, as the variability impact is limited. Most importantly, states the commenter, the EPA should not penalize units that burn low contaminant fuel by setting their fuel limits based on their average fuel content during the performance tests. According to the commenter, instead, the EPA should set the fuel limit based on HAP reduction performance of the unit, and set th e 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 th e EPA should moderate the al ternative procedures in proposed section 63.10008. The commenter states that all fuel analysis under the rule must be conducted according to an approved site-specific plan and according to specific procedures for sampling, preparation, and analysis. Accord ing to the commenter, the EPA’s proposed requirements are in many instances overly prescriptive; the primary object ive should be to obtain fuel samples that are representative of the fuel that is being combuste d. According to the commenter, because there is so much diversity in how fuel is receiv ed, stored, and processed at individu al facilities, as well as what is actually contained in the mine, the EPA needs to a llow more flexible procedures to accomplish the primary objective. The commenter states that unde r proposed section 63.10008(b) (l), the proposed plan must be submitted to the Administrator at least 60 days before the fuel analysis. Because some of the information required to be included may change from analysis to analysis the commenter assumes the EPA will require a new plan. For example, states the commenter, the plan must include identification of all fuel types anticipated to be combusted and whether the source or fuel supplier will conduct the analysis (proposed in section 63.100 08(b)(2). The commenter states th at although it might be possible to submit that information 60 days in advance of the initial demonstration and receive approval before conducting the analysis, it may not be possible for subs equent analysis in response to changes in fuel type or fuel mixtures (since those might occur wi th 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 believe s that the EPA should either rem ove the requirement for advance submittal and approval of a plan after the initial compliance demonstration, or remove the requirement to include in the plan information that might change.

Response to Comments 106 - 109: The final rule has removed the re quirements for operating and fuel limits with the exception of a PM CPMS. Complian ce with emission limits will be shown with periodic (quarterly) performance testing, CEMS, or a combin ation of annual emission testing and PM CPMS.

15. Fuel limits.

Comment 110: Commenter 17705 encourages the EPA to lim it the requirement to establish maximum fuel inputs to sources that are uncontrolled and solely relying on fuel analysis to demonstrate compliance with a numeric standard. The commenter states that the characteristics of fuel, in particular coal fuel, can vary between shipments, so it is problematic to establish any type of maximum value based on a one-time, short-term performance test, and further, for units that are controlled, relying on a fuel input limit does not adequately account for em issions reductions achieved by the control devices. According to the commenter, for controlled units that do not elect to us e CEMS to demonstrate compliance, it would be more appropriate to estab lish parametric monitoring for the control devices (coupled with period performance testing) than unnecessarily constrain fuel supplies through nonrepresentative “max imum” fuel inputs.251 Response to Comment 110: The final rule has removed the requi rements for operating and fuel limits with the exception of a PM CPMS. Compliance w ith emission limits will be shown with periodic (quarterly) performance testing, CEMS, or a combin ation of annual emission testing and PM CPMS.

16. CEMS only.

Comment 111: Commenter 17715 states that it is not clear in the proposed rule that installing and operating CEMS for the regulated HAP and surrogate s will relieve a source of the burden of also monitoring compliance with operati ng 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 CE MS would provide, and the EPA should format both the language and tables in the rule to clarify its intent as it relate s to CEMS used for demonstrating compliance.

Response to Comment 111: No other monitoring is required if a source uses a CEMS to demonstrate direct compliance with an emission limit (including the SO 2 surrogate limit for HCl).

17. Section 63.10007(a) Site Specific Test Plan.

Comment 112: Commenter 17718 states that the EPA should provide guidance on what should be included in a site specific test plan as me ntioned in proposed regul atory language of 40 CFR 63.10007(a) and referenced to 40 CFR 63.7(c). Accord ing to the commenter, the development of external QA programs with testing firms and laboratories (especially if multiple testing firms and laboratories are needed) has the po tential to become extremely burde nsome without cl earer guidance.

Response to Comment 112: The EPA has already issued a guidel ine document for the preparation of site specific emission test plans. The document can be found at http://www.epa.gov/ttn/emc/guidlnd/gd042.pdf

18. CPMS comments.

Comment 113: Commenter 1775 states that section 63.10010(h) sets out requirements for CPMS and the previously proposed PS 17 would apply to CPMS. 73 FR 59,983 (Oct. 9, 2008). The commenter objected in the PS 17 rulemaking to the proposed applica tion of that specificati on to future performance specifications without revision of the indivi dual 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 s upport 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 fi nal, this issue is best addressed in the response to this concern in the context of the PS 17 rule making, not in this rulemaking, given that the issue extends to all promulgated NESHAP standards with a parametric mon itoring system potentially subject to PS 17.

Comment 114: Commenter 17775 states that the rule propo ses various installa tion operation and maintenance requirements for “flow monitoring syst ems,” “pressure monitoring systems,” and “total secondary power monitoring systems.” According to the commenter, several of these proposed requirements are unnecessary or uncl ear: first, with respect to flow monitoring systems, depending on252 the fluid being measured, many system s do not use flow meters due to reliability issues, corrosion, or composition. Instead, these processes frequently use constant rate pumps. The commenter states that these pumps have a known capacity given their specific application and are either “on” or “off.” As an example, states the commenter, scrubber module slurry pumps operate in this manner; the reported scrubber slurry flow rate is simply based on the number of pumps in service. According to the commenter, the EPA should make clear that flow m onitoring systems are not required for any CPMS and that systems that use constant rate pumps ar e 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 requi rements for operating and fuel limits with the exception of a PM CPMS.

Comment 115: Commenter 17775 states that the sect ion 63.10010(h)(2)(i)(C) requirement to “Minimize the effects of swirling flow or abnor mal velocity distributions due to upstream and downstream disturbances” is unnecessary and extr emely vague. According to the commenter, the requirements in proposed subsections (A) and (B) - to properly locate the flow sensor and to use a sensor with a sensitivity no greater than two percent of the exp ected flow rate - are adequate. The commenter states that the term “minimize” is not sufficiently obj ective 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 requi rements for operating and fuel limits with the exception of a PM CPMS.

Comment 116: Commenter 17775 states that the evaluati ons under section 63.10010( h)(2)(i)(D) should specifically allow for procedures th at include process trending and co mparisons that can indicate the flow monitor is performing properly (similar to the fuel flow to load concept in Part 75, Appendix D section 2.1.7). According to the commenter, operators s hould not necessarily be required to ship meters off to get NIST traceably certified each year.

Response to Comment 116: The final rule has removed the requi rements for operating and fuel limits with the exception of a PM CPMS.

Comment 117: Commenter 17775 stated that with respect to pressure monitoring systems in section 63.10010(h)(2)(ii)(B), the requirement will be difficult to interpret as a regulatory requirement. The commenter states that the requirement in subsection (A ) to provide a representative location is sufficient; however, the EPA also proposes to re quire that EGUs “Use a pressure sensor with a minimum tolerance of 1.27 centimeters of water, or a minimum toleran ce of 1 percent of the pressure monitoring system operating range, whichever is less” (proposed section 63.10010(h)(2)(ii)(C ). According to the commenter, this should read, “whichev er 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 le sser error, states the co mmenter, 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 requi rements 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) ther e is a requirement to “[p]erform checks at least once each boiler 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 vari ety of process functions (e.g., to monitor baghouse and scrubber pressure drops, slurry tank liquid levels, etc.) and have design fe atures that ensure the pressure taps do not get plugged. The commenter states that for pressure sensor s that are exposed to gases (e.g., boiler exhaust gases), the pressure taps have purge air to periodically clean them; the purges can be varied to ensure that key pressure measurements are very reliable. For pressure sensors that are exposed to liquids (e.g., scrubber slurry), states the commen ter, redundant taps and a water cleaning system is frequently used; while one tap is being cleaned with water, the other tap is being used for process control. According to the commenter, while the EPA might believe it is reasonable to expect pluggage problems with pressure taps, thes e types of problem rarely exist, and it w ould 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 requi rements for operating and fuel limits with the exception of a PM CPMS.

19. ASTM methods.

Comment 119: Commenter 1775 states that the in addi tion to the use of ASTM D3173 for determination of moisture content in fuel the EPA also should allow use of (1) ASTM D7582 “Standard Test Methods for Proximate Analysis of Coal and Coke by Macro Thermogravimetric Analysis,” or (2) ASTM D5142 “Standard Test Methods for Proximate Analysis of the Analysis Sample of Coal and Coke by Instrumental Procedures,” which are eq uivalent to ASTM D31 73, except that they are automated. The EPA should reference ASTM D3302 “S tandard Test Method for Total Moisture in Coal,” and ASTM D3180 “Standard Practice for Ca lculating Coal and Coke Analysis from AsDetermined to Different Basis.” The commenter st ates that both ASTM D3302 and ASTM D3180 are referenced in ASTM D3173, and in addition, the following methods are currently used by EGUs for Hg, metals, and chlorine in coal and should be evalua ted for inclusion without an equivalency analysis:

 EPA Method 7473 - “Mercury in Solids and Solutions by Thermal Decomposition, Amalgamation, and Atomic Absorption Spectrophotometry”;

 ASTM D4326 - “Standard Test Method for Major and Minor Elements in Coal and Coke Ash By X-Ray Fluorescence”;

 ASTM D6357 - 04 - “Test Methods for Determin ation of Trace Elements in Coal, Coke, & Combustion Residues from Coal Utilization Proce sses by Inductively Coupled Plasma Atomic Emission, Inductively Coupled Plasma Mass, & Graphite Furnace Atomic Absorption Spectrometry.”

Finally, states the commenter, a number of methods that were identified in Table 2.3 of the 2010 ICR are not included in the rule. A ccording 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 requi rements for operating and fuel limits with the exception of a PM CPMS. The only fuel-relat ed provision in the fina l rule is an option for liquid oil-fired units to demonstrate compliance withthe acid gas standards by documenting that fuel moisture content remains no greater than 1.0%. This demonstration is based on monitoring results or fuel supplier certifications without reference to any specific methods fo r such analyses. As for the fuel metals contat sampling and analysis, the rule no longe r requires such measurement eliminating the need to specify these methods.254 Comment 120: Commenter 17808 recommends the EPA set a per cent water content lim it for oil, rather than setting HCl and HF emissions limits for liquid oil-fired EGUs. The comment er states that ASTM test methods are available for meas uring the percent water content of fuel oil (D 95 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 fi nal rule is an option for liquid oil-fired units to demonstrate compliance with the acid gas standards by documenting that fuel moisture content remains no greater th an 1.0%. This demonstrati on is based on monitoring results or fuel suppl ier certifications.

20. Miscellaneous.

Comment 121: Commenter 18025 requests clarification with respect to demonstrating compliance when using a new or changed blend of fuel th at 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 (H g, chlorine, etc.). The commenter states that if these are within the parameters established during in itial compliance testing, the fu el may be used, and if not (for example, the chlorine is hi gher than established during initial testing), the unit must conduct new testing to demonstrate compliance before using the new fuel. The co mmenter 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 requi rements for operating and fuel limits with the exception of a PM CPMS.

Comment 122: Commenter 17821 states that in some cases th e only viable option is to utilize stack testing. According to the commenter the use of tota l 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 commen ter’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 th e monitor. For sources unable to meet the SO 2 standard or use HCl CEMS, the frequency of required testing has been changed to quarterly.

Comment 123: Commenter 17808 recommends the use of Hg as a surrogate for Se and, thus, filterable PM alone may be a surrogate for other HAP metals. Th e commenter states that in the preamble, the EPA states that selenium is captured by controls for Hg and acid gases. In fact, states the commenter, commenter’s initial correlation analysis indicates that selenium emissions are in fact better-correlated to Hg and acid gas emissions than CPM (r=0.44 for Hg or 0.60 for HCl, versus 0.32 for condensable PM (r > 0.2 implies significance at 5 percent level with 60 units)).

Response to Comment 123: The EPA has removed the requirement of total PM as an alternate equivalent standard for HAP metals. For more de tailed discussion and res ponse, please see section 4F01A.

Comment 124: Commenter 17808 recommends PM CEMS combin ed with a separate Se standard. Se emissions could be confirmed by quarterly or annua l 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. Alterna tively, states the commenter, at a minimum, the commenter recommends that the EPA base the filterab le PM limit on the facility-specific ratio to the total PM standard, rather than the initial numerical performance. Commenter also recommends that this facility-specific limit remain constant for a longer pe riod 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 metals, but instead uses a filterable PM lim it. 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 whet her the purpose of operating limits is to ensure compliance between performance tests.

Response to Comment 125: Yes. Operating limits are part of the compliance monitoring and assurance provisions in the rule. In the final rule, the only operating limits that apply are for a PM CPMS and, in certain situations, for liquid oil-fi red units. See further discussion else where in this document and in the final preamble.

Comment 126: Commenter 17655 recommends clarificat ion of section 63.10005 that allows exemptions from the PM testing and testing for speci fic metals, but only for single fuels. According to the commenter, the rule should be clarified to allow similar provision s for units that co-fire (e.g., coal with natural gas). The commenter al so notes that units testing for PM should not have to test for HAP metals because there is no HAP metals limit. The co mmenter believes testing for metals is simply an extension of the ICR.

Response to Comment 126: In response to comments, the final rule has removed all requirements for duplicative testing of a HAP and an a lternate equivalent stan dard. Facilities complying with an alternate equivalent limit do not have to pe rform periodic testing for the co rresponding 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 commen ter does not regard stack-mounted PM monitors to be sufficiently accurate, reliable, or durable to yield significantly more or better compliance data than opacity monitoring currently does. The commenter notes that PM monitoring is a direct measurement of PM, which is the limit for EGUs. The commenter stat es that although PM is itself a surrogate for nonHg metals, it is the primary standard expressed in the regulation – compliance with specific metals limits would be regarded as an altern ative compliance option rather thana 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 woul d be considered accurate or sensitive to the concentration levels of PM required by the final rule.

Comment 128: Commenter 17730 states that they appreciate the EPA setting the performance testing requirements for all pollutants at the 5-year interval. The commenter believes that for sources that choose to use CEMS to demonstrate ongoing complian ce 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 w ill undergo annual certif ication 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 te sting compliance alternative as th e basis for determining compliance with the limits established under th is rule. According to the commenter, an annua l PM stack test is effective in determining compliance because operati ng units under existing CAM plans have prescribed methods to verify PM to include bag leak detection and opacity readings.

Response to Comment 129: The final rule requires quarterly pe rformance testing or PM CPMS with annual performance testing.

Comment 130: Commenter 17775 states that the EPA’s proposal contains nothing to indicate at what point a monitoring system is deemed “certified” and if the EPA were to attempt to define that point, sources likely would arbitrarily attemp t to postpone some part of the re quired testing in order to control when the “performance test” begins. According to the commenter, the EPA should allow EGUs to complete required testing (or design ate a CEMS that previously has co mpleted the required testing”) and to notify the Administrator of the date upon whic h its “performance test” will begin. The commenter states that this will ensure consistency between EGUs and allow EGUs to confirm that their controls are working properly, and that they ar e 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 notif ication of intent will indicate the date for commencement of a performance test.

Comment 131: Commenter 17886 states that the EPA shoul d not set unit “operating limits” based on performance measured during short term tests. Accord ing 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 resu lts) 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 clarifi cation as to whether the EPA intends to require 1/5 year stack testing for a ll 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 CEMs is determined using the average hourly SO 2 concentrations obtained during the first 30-day operating period, and section 63.10005(d)(5) states the same for PM CEMS. Howeve r, 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; sec tion 63.10005(a) states that “If you us e 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, states the commen ter, 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 leas t every 5 years.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 complyi ng with a surrogate limit do not have to perform peri odic testing for the corres ponding HAP or vice versa.

Comment 133: Commenter 17785 states that the proposed rule requires fuel analys is monthly in order to assess continuous compliance. The commenter states that the portion of the dr aft rule that addresses this (section 63.10011) is unclear. Acco rding to the commenter, equation 13 of this section seems to suggest that the Hg concen tration in a monthly sample must be less than the 90 thpercentile concentration based on the Hg content measured dur ing demonstration of initial compliance; equation 13 refers to the 90 thpercentile of Hg concentration as calculated according to Equation 8, but the referenced Equation 8 calculates the average fuel Hg content, not the 90 thpercentile. The commenter states that the EPA needs to clarify these e quations so it is clear how they intend the 90 thpercentile Hg concentration to be calculated.

Response to Comment 133: The fuel sampling and analysis requi rements have been removed from the final rule.

Comment 134: Commenter 17696 states that if the EPA does not limit the rule to Hg, the EPA should provide additional flexibility in the emissions mo nitoring and compliance determination requirements. Commenter believes certain of the proposed requir ements are unreasonable in light of available alternatives that are more cost-e ffective and provide sufficient assurance of continuous compliance. The commenter states that revisions ar e also needed concerning Hg monitoring and to make the compliance determination requirements clear er 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 ru le to Hg as explained in response to other comments concerning this issue.258 5B01 - Recordkeeping/Reporting: Data reporting requirements

Commenters : 17402, 17655, 17677, 17681, 17772, 17821, 17881, 17902, 18023

1. Reporting requirements for deviations.

Comment 1: Commenter 17402 opposes the EPA’s proposed de finition of “deviation” and the EPA’s reporting requirements for deviations. The commenter st ates that in the proposed rule, the EPA defines “deviation” to include (but the de finition is not limited to) any fa ilure 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 requ irement 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 duri ng a malfunction, the owner or opera tor 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 pr oposed definition of “deviation” is overbroad and should not include operating limits . Commenter 17902 suggests th at on-site records be maintained that document operating limit deviations, a ssociated investigation and appropriate corrective action if deemed necessary. Commenter 17402 recommends that operating limits and monitoring requirements should not be a report able deviation since they are in dicators of compliance and not emission limitations. As an example, the commenter st ates that the EPA’s propos al requires that for an ESP, the parameter operating limit is calculated by th e total secondary power i nput as measured during the performance test. Commenter respectfully submits that operating parameter exceedances, such as this ESP power limitation or CEMS downtime (faile d calibration error test, power outages, data acquisition and handling problems, etc.), are compliance indicators and, therefore, inappropriately categorized as deviations.

Comment 3: Commenter 17402 states a further reason to excl ude 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 reporti ng 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 report ing of deviations when these units fire lower pollutant containing fuels. The commenter asserts that since these parameters do not take into account variability, it would be arbitrary and inefficient to characterize any exceedance of the operating limit (or failure to me et the operating limit in the case of a minimum operating limit) as a deviation.

Comment 4: Commenter 17402 further urges the EPA to rec onsider its proposed reporting requirements for deviations. Specifically, commenter opposes the EP A’s proposal to require th e owner or operator of the facility to notify the EPA of an exceedance of an emission lim it during a malfunction within two business days to avail itself of an affirmative de fense to civil penalties for the malfunction. Commenter submits that such a requirement is excessive and r ecommends 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 sh ould be conducted. The commenter not es that calculations could be based on the number of block averages in the reporting period, total operating time during the block period associated withthe 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 deviat ion includes any failure to meet an emission limit, work practice requirement, operating limit, or monitori ng requirement. The final rule does not alter this approach. Deviations are reported in semiannual co mpliance reports. The compliance reports require the information in the General Provisions 63.10(e) secti on and some additional source specific information which is typical of reporting. In addition, for malf unctions, additional notificat ion requirements apply. The EPA is revising the affirmative defense related malfunction notificat ion requirement so that it reads “The owner or operator of the aff ected source experiencing an exceedan ce of its emission limit(s) during a malfunction shall notify the Admini strator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the ma lfunction 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 busines s days after the owner or operato r knew or should have known that the malfunction caused or contributed to an exceedan ce, but, in no event later than two business days after the end of the averaging peri od, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction.”

2. Reporting requirements for malfunctions.

Comment 6: Commenter 17681 states that section 63.10001(iii) (9) of the proposal appears to require notification to the EPA Administrator of a malfuncti on within two business days of the event if the malfunction may cause an exceedance of the 30-day av erage. According to the commenter, facilities may not be aware that the malfunction will cause an exceedance of the 30-day average until more than two days have passed. The commenter states that th e reporting time should be at least as long as the averaging time, which in this case is 30 days. In addition, the commenter ques tions whether facilities may report to their local compliance office if the state is delegated unde r the CAA instead of reporting to the EPA Administrator.

Commenter 17681 states this sect ion (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 de fense related malfunction notification requirement so that it reads “The owner or operator of the affected source expe riencing an exceedance of its emission limit(s) during a malfun ction shall notify the Administrato r by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not possible to determine within two business days whether the malfunction caused or contributed to an exceedance, no later th an two business days after the owner or operator knew or should have known that the malfunction cause d or contributed to anexceedance, but, in no event later than two business days after the end of th e averaging period, if it wish es to avail itself of an affirmative defense to civil penalt ies for that malfunction.” With resp ect to reporting to delegated state agencies, that would occur in accord ance with delegation of this subpart , if applicable. With respect to preparation and signature by a prof essional engineer, the answer is no. The rule plainly states: ”The analysis shall also specify, usi ng best monitoring methods and engineering judgment, the amount of excess emissions that were the result of the malfunction.”260 3. Quarterly reporting of hourly data.

Comment 7: Commenter 18023 believes the quarterly s ubmittal of electroni c hourly data is inappropriate for an emission limit-oriented rule, is highly burdensome on the emission source operator, and should be removed from the proposed rule requirements. Commenter states that section 7.2.5, Quarterly Reports, is written to reflect the quarterly submittal of electronic hourly data that is appropriate for a trading program-re lated rule, most likely because th ese requirements were copied out of the vacated CAMR rule.

Comment 8: Commenter 17655 agrees that hourly data r ecords are unnecessary for demonstrating compliance. Commenter states that in evaluating th e cost of hourly reporting, the EPA consulted with DAHS vendors and was told that th e cost of collecting hourly data would be minimal. However, commenter believes the agency failed to consult withusers to ascertain the time requirements and costs for reviewing hourly data, as opposed to records compressed to daily, weekly, or even monthly averages. Commenter submits that there is no need for hourly data, as there are no hourly compliance standards. Further, ECMPS could be easily adapte d by the EPA to accommodate records in other than hourly increments (daily or monthly). According to the commenter, this would provide considerable savings to the industry and would not impactcompliance 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 tradi ng program where there is a market function that is facilitated by the collection and public pos ting of emissions data. The commenter asserts that that approach is unnecessary and unduly burdens ome in the context of a regulatory regime where the focus is on demonstrating technology compliance.

Commenter 17772 states that in an ag e of electronic recordkeeping, there is a natural tendency to ask for “all the data that is available.” According to the commenter, however, in indus trial 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 grow n 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 demonstr ating that a facility has insta lled MACT level controls and is operating that equipment appropriately is an entirely different type of regulatory approach and the reporting requirements should be cons istent with that regulatory appr oach. The commenter requests that the EPA modify its approach as follows: (1) The relate d limits will be specified in the Title V permit. (2) The responsible entity is required to certify each y ear as to full compliance or intermittent compliance. (3) Records should be kept and made available as necessary to the EPA. (4) Exception reporting should be performed quarterly.

Commenter 17772 states that this recommendation is a proven appro ach used by the EPA for other industries and in other co ntexts and there is no need for EGU co mpliant facilities to transmit massive MACT-related databases to the EPA every quarter.261 Commenter 17772 states that this pr oposal is consistent with pastEPA MACT requirements imposed on other industries. According to th e commenter, for example, the MACT program applied to the steel industry does not require multiple CEMS and quarter ly reporting of all hourl y data; that would be unwarranted and unwieldy. The commenter states that the same can be said about the pulp and paper industries, etc., and that the uti lity sector should be treated sim ilarly - 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 re porting that is far in excess of other important U.S. industries.

Response to Comments 7 - 9: The EPA has retained in the final ru le that CEMS data be provided on an hourly basis. We believe this approach simplif ies 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 ti tle IV ARP and other emissions tr ading 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 unde r this rule. We obtained feedback from several DAHS vendors indicating that the cost of modifying the exis ting Part 75 DAHS systems to accommodate hourly reporting of Hg CEMS and sorbent trap data would be similar, and in some cases, less than the cost of the first proposed option. Also, ther e is little or no cost to i ndustry 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 previously noted, almost all of the EGUs already have these monitors and the associated reporting mechanisms in place. In viewof these considerations, we have decided in favor of this second option for Hg.

Requiring the reporting of hourly Hg emissions data from EGUs is advantageous, both to the EPA and industry. The DAHS can be automated to demonstrate compliance with the sta ndard on a continuous basis. The data can then be submitted to the agency electronically, thereby eliminating the need for the agency to request additional info rmation for compliance determinations and program implementation. The rule also requires quarterly electronic reporting of hourly SO 2 CEMS data and HCl CEMS data (for sources electing to demonstrate continuous complianc e using those certified CE MS). Those are included for the same reasons as the Hg monitoring data.

The comments seem to assume that the costs for addi ng new parameters to the system would be directly proportional to the number of parameters collected. This neglects to recognize that the ECMPS and DAHS frameworks do not need to be re-engineered if the new data requirem ents are adopted in a manner that harmonizes requirements. Also, reducing the computer output to daily or monthly values does not necessarily save the user any significant (if any) effort. In fact, it may cost the source more effort or cause them to miss data problems that in the end may affect their compliance determination. Once data collection is automated (and given that th e industry and the EPA has already invested in the automation process that is ECMPS) the burden on the operator is minimized. The systems can (and have) been programmed to do data an alysis and QA evaluations automati cally, giving a user a report of hours that might be in question. Th e environmental managers at f acilities can, and have, designed custom checks into their systems to streamline their data reporting re sponsibilities. These advantages need to be recognized when evaluating the electronic reporting option as a means for data QA.

4. Recordkeeping requirements for liquid oil-fired units.262 Comment 10: Commenter 18023 states that the recordkeeping requirements for liquid oil-fired units are unreasonable. The commenter states that the EPA re quires “for each 30 boiler ope rating day period . . . a description of the fuel, the total fuel usage amounts and units of measure, and information on the supplier and original source of the fuel” (76 FR 2 5035). According to the comme nter, 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 asse rts that it is not possible to collect this information in the format requested bythe 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 Comment 10: With the changes in the final rule that eliminate the fuel analysis requirements, this comment is largely moot. The only fuel data that must be retained is a record of fuel use by operating hour, in order to determine if the EGU meets the low use exemption. Also, if a source opts to monitor fuel moisture in each fuel shipmentfor a liquid fuel unit and demonstrates that this alternative monitoring is acceptable under the part 63 general provisions (in lieu of other monitoring for acid gases), then the source must keep records of the fuel moisture of each fuel shipment.

5. Semi-annual compliance dates.

Comment 11: Commenter 17681 states that section 63.10031(b )(2) of the proposed rule appears to require semi-annual reports on January 31 and July 31 and that the beginning of the year is very busy with reports required to state and federal agencies. The commenter stat es 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 sour ces 60 days to file th eir 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. Thes e dates do not apply to the quarter ly reporting to ECMPS of CEMS data.

6. Annual documentation.

Comment 12: Commenter 17677 states that the regulation includes documentation for an annual report on emission tests, inspection, repair s, adjustments, findings and corre ctive actions. Commenter believes this additional documentation burden seems to do nothing more than increase non-productive work load for our personnel.

Comment 13: Commenter 17681 also notes that section 63.10031( c)(5) of the proposed rule appears to require a summary of the annual performance tests inthe compliance report which is submitted to the EPA. If the testing data is reported electronically to the EPA within 60 days after each te st through CDX, why does the EPA need this data sent to them again?

Response to Comments 12 - 13: The final rule contains comp liance and deviation reporting requirements that are typical of mo st NESHAP. These summary reports are in addition to the detailed performance test results reported electronically and will be used by the permitting authority for effective compliance oversight.263 7. Other data reporting requirements.

Comment 14: Commenter 17881 states that the requirement in section 63.10031(c)(4 ) to report monthly fuel use is not relevant, as it is the fuel type and heat input fraction that matters in determining compliance. The commenter suggests that the sec tion 63.10032(d)(1) requirement to maintain such records should be deleted, or at a minimum, revise d to require records of th e types of fuel which are burned and the maximum percentage or fraction of each fuel type (on a heat input basis).

Comment 15: Commenter 17881 states that the waste de termination information should only be required if a new fuel type is introduced followi ng 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 n eed not be reported given the changes in the final rule, although records of fuel us e by operating hour must be maintained, as noted above. Moreover, EGU owners or operators who self-det ermine or have the EPA determine via petition that their fuel is a non-waste under 40 CFR 241.3 or who combust fuel pr ocessed from discarded non-hazardous secondary materials have additional emissions testing, notifi cation, reporting, and recor dkeeping requirements as discussed in the rule.264 5B02 - Recordkeeping/Reporting: Records that must be retained

Commenters : 17681, 17775, 17881

1. Objection to retaining records on-site.

Comment 1: Commenter 17681 states that section 63.10033(c) of the proposed rule appears to require that records be kept on site. Comment er believes it is much better to keep records electronically or at least not congregated at each site and if the EPA wants a copy, the f acility can produce a copy within a reasonable time.

2. Objection to requirement to retain records for five years.

Comment 2: Commenter 17775 states that the EPA proposes to require retention of all data, including reports, records of measurements, ma intenance, corrective action, and “o ther information,” for 5 years. (Proposed section 63.10033 and Appendix A section 7.1. ) Commenter objects to these requirements. To mandate a retention period longer than 3 years, th e EPA must justify the re quirement under the PRA. See 5 CFR section 1320.5(d)(2)(iv) (requiring a showi ng of substantial need or statutory mandate to require retention of record s for more than 3 years). The commenter states that the EPA’s statement in the supporting statement for the February 2011 proposed ICR291 that “None of the guidelines in 5 CFR 1320.5 are being exceeded,” is simply false. The EPA-HQ-OAR-2009-0234-3031 at 4.

Response to Comments 1 - 2: The agency believes the record keeping and retention requirements are consistent with other requirements already in place, specifically 40 CFR part 63.10 (b) “ General recordkeeping requirements. (1) The owner or operator of an affect ed source subject to the provisions of this part shall maintain files of all information (i ncluding all reports and notif ications) required by this part recorded in a form suitable and readily available for expeditious inspection and review. The files shall be retained for at least 5 years following the date of each occurrence, measurement, maintenance, corrective action, report, or record. At a minimum, th e most recent 2 years of data shall be retained on site. The remaining 3 years of data may be retained off site. Such files may be maintained on microfilm, on a computer, on computer floppy disks, on magnetic tape disks, or on microfiche.” In addition, the 5- year retention period is the genera l rule for all recordkeeping for a ll sources under the part 70 operating permits program. Given that the ge neral provisions for part 63 and part 70 already establish a 5-year retention period, the EPA believes it is justified in using those preceden ts for the retention periods under this subpart. If the EPA stayed silent on retention period in this subpart, th e general provisions would provide for the 5-year retention as would the part 70 requirements. Thus, this action does not establish any new retention requirements, but merely confirms that the existing retention requirements apply.

3. Objection to requirement to maintain mercury mass emission records.

Comment 3: Commenter 17881 states that section 7.1.8 requ ires Hg mass emission records for those units complying with the Hg lb/GWh emission limit. According to the commenter, this section is based on the misguided premise that the Hg mass emissions, as pounds per clock hour, are required in order to perform the lb/GWh Hg emission rate calculations. The commenter states that as noted in relation to section 6.2.2, only the Hg emission rates, as lb/hr, and average electrical generating rate, as MW, are needed in order to calculate the lb/GWh emission rate. Thus, according to the commenter, this section should be re-written on a Hg mass emission rate versus integrated mass emissions basis.265 Response 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: El ectronic reporting of CEMS data

Commenters : 17715, 17716, 17725, 17730, 17740, 17775, 17795, 17796, 17800, 17805, 17820, 17821, 17873, 17877, 17886, 17909, 18014, 18039, 18449, 18498, 18831, 19114, 19121, 19122, 19679

1. ECMPS reporting.

a. Support for ECMPS reporting.

Comment 1: Commenters (17715, 17740, 17796, 17805, 17877, 17909, 18039, 18449, 19122) support using ECMPS.

Comment 2: Commenter 17796 believes all CEMS collected data should be required to be submitted to a modified ECMPS so this data can be assemble d in one area which can be accessed by all users.

Comment 3: Commenters 17805 and 19122 also agree that ECMPS could be used for submittal of compliance data as required in the proposed rule. The commenters note that his system is currently used successfully to report Acid Rain Program emissions from utility units.

Comment 4: Several commenters (17740, 17873, 18039, 18449, 18831) support the EPA’s proposal to handle reporting for PM, HCl, and Hg through ECM PS. According to the commenters, the ECMPS system simplifies the reporting process by evaluating continuous monitoring dataand other information in an electronic format in preparation for submittal to the agency. The commenters note that ECMPS is used by Part 75 and emissions trading programs and is a well-established data reporting tool.

Comment 5: Several commenters (17715, 17877, 19114) state th at ECMPS is currently being used successfully by industry and the infras tructure is already in place, th ereby reducing costs. According to the commenters, industry personnel have been trained for the constituents that are already being reported by ECMPS so the learning curve will be very short and will allow a rather seamless transition to HAP reporting. One commenter proposes that the EPA take a dvantage 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 m onitoring data collected under the requirements of NESHAP be reported into the EC MPS system. Commenter r ecommends that episodic data, such as performance and stack te sting be reported using the ERT.

b. Support for ECMPS reporting, but with su pplemental rulemaking and public comment.

Comment 7: Commenters 17715 and 19114 state that the EP A should use ECMPS for all reporting. Commenters state that reporting asso ciated with the proposed rule s hould be handled by ECMPS, but should be the subject of a supplemental rulemaking in order to fully address all of the software issues that arise with electronic reporting. According to the commenters, the EPA should invite industry involvement as was used during th e initial development pr ocess 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 requir ements in sufficient detail for any parameter other than Hg. A ccording to the commenter, although the EPA previously developed a reporting format for Hg, that fo rmat was developed to meet reporting requirements under the nowvacated CAMR. Commenter states th at the EPA cannot use a reporting format to specify substantive reporting requirements but that the rule must id entify each piece of information to be reported. Commenter adds that the EPA must submit its desi red format and instructions to an open public comment process so that the regula ted 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 re quire use of ECMPS, the EPA would at a minimum need to publish for comment (1) additional reporting provisions to c over 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 in structions 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 subjec t that format to notice and comment rulemaking and review by OMB. According to the commenters, the EP A electronic reporting form ats specified to date by the Administrator have been sufficiently complex and substantive that it is not appropriate to totally exempt them from rulemaking. The commenters state that as implemented, the EPA’s electronic formats are substantive requirements that impose significant burdens and impact on EGU’s compliance status. The commenters state that to the extent some flexibil ity is needed to make adjustments to the format, that flexibility can be provided by rule.

Comment 11: Commenter 19114 recommends that the EPA i nvite industry involvement as was used during the initial development pro cess 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, th e EPA should develop the tool, then propose its use in a separate rulemaking. The commenter states that numerous times industry has been stuck with software implementations that are no t ready and that issues with soft ware should be handled in advance of it being required for comp liance with a rulemaking.

c. Opposition to ECMPS reporting.

Comment 12: Multiple commenters (17716, 17725, 17795, 17820, 17821, 17886, 18014, 18498) state that reporting hourly CEMS data el ectronically should not be require d. The commenters state that the EPA proposes to require quarterly re porting of hourly emissions data as well as results of all required certifications and QA tests through the CAMD ECMPS software and that summaries of the emissions test results and semiannual deviation re ports would also be required for SO 2 CEMS, PM CEMS, and HCl CEMS. The commenters believe there is no need for this requi rement; the hardcopy deviation reports and data assessment reports are adequate and consistent with the requirements of other MACT and NSPS compliance rules.

Comment 13: Multiple commenters (17716, 17725, 17775, 17795, 17820, 18014, 18498) state the EPA has not justified the burden of requiring th e ECMPS reporting. Several commenters (17716, 17725, 17775, 17820, 18014, 18498) state that the data reporting re quirements in Appendix A for Hg go far beyond what is necessary for this rule. The commen ters state that the EPA portrays this proposed reporting requirement as easy – that sources would “simply integrate Hg emissions data and QA test268 results into the existing Part 75-compliant DAHS,” unde r 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 wa s “similar, and some cases, less than the cost of the first option.” According to th e commenter, any software under Opti on 2 would have to provide the same information required by Option 1; The commente r states that sources would likely integrate the new requirements within the DAHS that they current ly use for Part 60 and Part 75 reporting, but this does not mean that the proposed reporting scheme woul d be simple or cheap to implement. According to the commenters, adding the requirement to report hourly emissions data and other QA/QC data would be burdensome both to utilities as well as the EPA, especially given differences between Part 75 and MACT reporting (such as bias adjustment factors a nd missing data substitution) . The commenters assert that CMPS was developed for emissions trading pur poses, not for demonstrating continuous compliance with emission limits. The commenters conclude that reporting information vi a ECMPS under this rule would be a costly exercise that is both unnecessary and unjustified.

Commenter 19679 asks for clarification on whether the Hg CEMS data to be integrated into the Part 75 compliance DAHS will be subject to the on-going QA require ment of Part 75 or if it would be subject to the QA requirements of Part 60 Appendix F and PS-12A as is indicated for the “first option”. According to the commenter, specifically relevant to this distinction is the requirement liste d in Part 75, appendix A section 7.6.5 to apply a bias adjustme nt 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 em issions relative to the emission standard.

Comment 14: Commenters 17775 and 17795 object to the EPA’ s proposal to submit hourly Hg data. Commenter 17775 states that the EPA has not jus tified or prepared an ICR for the proposed requirements for quarterly reporting of hourly Hg em issions data. The commenter disagrees with the EPA’s assumptions regarding hourly Hg data and QA reporting.

Comment 15: Commenter 17775 states that the EPA could de velop an electronic reporting scheme as an alternative to ECMPS or ERT that might more easily accommodate the kinds of information the EPA seeks to collect. According to the commenter, whatever scheme the EPA uses, it still would need to be supported by a rule, and new ICR, that identifies each piece of information to be reported and a format that has been subject to review and comment. The commenter notes th at the supporting statement for the February 2011 proposed ICR for the proposed rule does not mention reporting of hourly Hg emissions data, or of the QA and certification data for Hg m onitoring systems. The commenter states that the proposed ICR also makes no mention of the EPA’ s development and maintenance of schema and software for collection or review of those data, or an accounting of their costs. According to the commenter, if the EPA were to move forward witha requirement to report other information using ECMPS, the EPA would need to issue a rulemaki ng 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 justifica tion for requiring reporti ng of that information.

Commenter 17775 objects to the EPA’s proposal to s ubmit hourly Hg data. The commenter states that the EPA has not justified or prepared an ICR for the proposed requirements for quarterly reporting of hourly Hg emissions data.269 Commenter 17775 states that Part 75 reporting is unsuitable for the repor ting proposed under Appendix A and the revisions required to the EPA’s and E GU’s software to implement the reporting proposed under Appendix A would be significant and costly.

Commenter 17775 states that in add ition to the compliance report, devi ation report, performance tests and monitoring system performance evaluations, th e EPA proposes to requir e quarterly reporting of hourly Hg data (e.g., emissions, certification and QA, and monitoring plan data) using the EPA’s ECMPS. According to the commenter, although the proposed rule does not mention ECMPS, Appendix A includes detailed recordkeeping requirements si milar to what had been included in CAMR, and requires quarterly electronic repor ting of much of that informati on “in a format specified by the Administrator.” Commenter 17775 states that all of the information needed to determine an EGU’s compliance status already must be reported under the part 63 general provisions. The commenter finds these additional requirements to be redundant and bur densome. If the EPA requi res additional detail, the EPA should provide that additional detail in proposed sect ion 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 discussi on of modifications to ECMPS, the EPA suggests that ECMPS also could be modified to allow electr onic submission of “30-day averages of parametric data, 30-day average fuel content da ta, stack test results, and perf ormance of tune up records.” The commenter notes that the EPA’s proposed rule does not contain any requirements to record, let alone report, 30-day averages of parameter and fuel data.

Commenter 17886 states that the EPA needs to define what constitutes a valid 30 -day rolling average, suggesting that the EPA should use a specific number of hours (i.e., 540 hrs or 75 percent of the month) in that period to qualify it for a valid period.

Commenter 17775 disagrees with the EPA’s proposal for data reporting in Appendix A. The commenter observes that the EPA has not required hourly datareporting or the sorts of QA data identified in Appendix A in a MACT, and this information is notnecessary for sources or the EPA to determine compliance with MACT standards. The commenter st ates that this information does not enhance the quality of MACT complia nce demonstrations.

Commenter 17775 objects to the EPA’s requirement in Appendix A to require submission of Hg monitoring information in quarter ly reports to the Administrato r “in a format specified by the Administrator.” The commenter notes that the commenter has challenged similar provisions for use in other programs judicially. The commenter’s objectio ns are: (1) concerns re garding 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 form at 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 comput er 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 th e CAA is for exception reporting only.

2. Data reporting formats.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 syst ems. According to the commenter, these systems must be connected to other plant data monitoring systems and integrated into a single report. The quantity of data for EGUs can be staggering. The commenter encourages the EPA to employ like data collection and transfer systems for multiple programs so that this expensive system can be used for each program, especially since much of the data is the same. The commenter states that the utility industry has worked with the CAMD for the last 17 years to de vise a comprehensive schema that is flexible and is relatively easy to maintain. The commenter recomme nds 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 ECM PS reporting for the following data elements:

1. Monitoring Plan Data for PM CEMS, HCl/HF CEMS, Continuous Hg Monitoring Systems, and Sorbent Trap Monitoring Systems similar to what is currently being collected for COMS.

2. Monitoring Plan Data for Auxiliary Boilers pr esent at facilities currently reporting in ECMPS required under the Industr ial Boiler MACT rules.

3. Certification Test Results for PM CEMS: a. PS-11 Initial Correlation Audit Results b. PS-11 Absolute Correlation Audit Results c. PS-11 Annual Relative Response Audit Results d. PS-11 Response Correlation Audit Results e. Initial Certification 7-Day Drift Test Results

4. Certification Results for Continuous Hg Monitoring Systems: a. Initial Certification Cycle/Response Time, 7-Day Drift, 3-point Linearity Check, and RATA test results b. NIST Traceability Test Results c. Annual RATA testing results d. Weekly System Integrity Check results

5. Certification Results for Sorbent Trap Monitoring Systems: a. Initial and Annual RATA test results

6. Certification Results for HCl/HF CEMS: a. Initial Certification Cycle/Response Time, 7-Day Drift, 3-point Linearity Check, and RATA test results b. Required ongoing quarterly and annual ongoing QA Tests for HCl/HF CEMS

Commenter 17725 does not support routine hard copy subm ittals of Monitoring Planrecords as listed in Appendix A to subpart UUUUU section 7.1.1.2.2 and wishes to maintain an onsite file at each facility that can be made available for inspection by the EPA and state auditors and inspectors.

Response to Comments 1 - 17: We recognize that emissions re porting for continuously measured pollutants (SO 2 , Hg, etc.) and for periodically measured pollutants (PM, non-Hg HAP metals, etc.) have different data demands. We recognize that minor revisions of the ECMPS will fulfill our data needs for continuously measured pollutants and we will make these minor modifications for receipt of the271 additional data demands. We also recognize the need for substantial modifications to the ECMPS to accommodate the data needs for periodically measuredpollutants. Although majo r modifications of the ECMPS would be required for periodic compliance tests by isokinetic and inst rumental 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 th e software tools to implement the delivery of these performance test data to us.

The electronic submission of comp liance test reports to us through the Central Data Exchange (CDX) is not solely for the purpose of developing improve d 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 te st reports for use by re gulatory authorities. The electronic submission of compliance te st reports is a continuation of our efforts to bring the submission and sharing of environmental data into the modern age. The storage of this compliance data in our WebFIRE provides a convenient location which is already used to store source test data.

As our and State and local agencies data systems mature, information provided through the ERT will be used to populate these data systems. We are currently upgrading the AIRS Facility System and expect to replace manually entered information with electr onic population from the ERT. We are also working with several State and local agencies to adopt the us e of the ERT for delivery of compliance test reports. The ERT is also much improved si nce the version used during the 2010 ICR process, and there is no expectation that the information to be reported under this final rule will be as extensive as some of the data reported for the 2010 ICR purposes.

We disagree that a separate and independent regulatory action is re quired to implement electronic reporting for selected regula ted sources. Each of these regulatory actions for selected source categories provides ample notice and the opportun ity for individuals to provide comment. We also disagree that the system to receive the compliance data must be operational prior to establishing the requirement for regulated sources to submit compliance data electron ically. We are on track to have the capability to receive electronic complian ce tests through our CDX in sufficient time to receive all util ity source test reports required by this final rule.

We do plan a separate and independent regulatory ac tion to implement electroni c reporting for regulated entities which are covered by past an d 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 deliveryand storage of all air emissions compliance source test data. With this tran sition, we believe this valuable information will be more readily available not only for compliance pu rposes but also for a variety of other uses.

3. Other CEMS reporting comments.

Comment 18: Commenter 18014 notes that the proposed EGU MACT Rule does not include provisions to use the part 75 “conditionally vali d data procedures.” According to the commenter, 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 states that a clearer approach would be to allow quality-assured data fr om a CEMS certified and operated in accordance to part 75 to be used for EGU MACT compliance (with the exception of bias adjusted and missing data).272 Response to Comment 18: The final rule provides for certain part 75 procedures for the CEMS and sorbent trap monitoring systems used to comply with this rule, including th e 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. A ccording to the commenter, reporting pollutant concentrations on a dry or diluen t basis may have been appropriat e a generation ago, when point of impingement calculations required st ack output concentrations but for several decades, it has been clear that the total mass emitted of each pollutant is what drives the environmental effects. The commenter states that only the wet concentration and wet stack flow is required to accurately calculate the mass emission rate of any pollutant and th at 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 i nput of plant heat rate or electrical outputbeing 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 analyzer may be required for heat input, bu t this is a separate issue, independent of any individual pollutant CEMS. Th e commenter states that the EPA should clearly differentiate the performance requirements for each pollutant monitor from the requirements of the additional variables required to calculate the proposed emissions limits.

Response to Comment 19: The final rule retains these require ments, consistent with the general approach to monitoring for this sector under part 75.

Comment 20: Commenter 18831 supports the ability to use alternatives to CEMS. The commenter states that sources should be allo wed 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 alternativ es, primarily CEMS or periodic stack testing (and a PM CPMS option). We do not believe developing CAM-like provisi ons under this rule is warranted as those requirements would likely be d uplicative of existing control device and similar monitoring that already applies to th ese sources under other programs.273 5B04 - Recordkeeping/Reporting: Electroni c reporting of emissions test data

Commenters : 17316, 17621, 17638, 17681, 17718, 17719, 17725, 17730, 17767, 17770, 17775, 17790, 17795, 17816, 17820, 17821, 17868, 17881, 18014, 18498, 19033, 18023

1. ECMPS reporting of emissions test data.

a. Support for using a modified version of ECMPS.

Comment 1: Several commenters (17638, 17681, 18023) state th at the EPA should use a modified version of ECMPS rather than the ERT to submit pe rformance test results. The commenter states that the EPA’s proposed rule requires th at performance test results be reported electronica lly to WebFIRE and suggests using ERT software to do this and that the EPA has requested feedback on using a modified version of ECMPS for this purpose. Based on problems encountered by the industry in submitting ICR data using the ERT software, commenters suggest it would be better to use a modified version of ECMPS rather than ERT but that revisi ons to the ECMPS are nece ssary. According to the commenters, without revision, it may be difficult to use the ECMPS for this purpose because that system was developed to support a trading system and not an emission limit based rule.

Comment 2: Commenter 17316 also supports the idea of us ing a modified ECMPS program to report MACT test and RATA data in lieu of ERT reporting. The commenter stat es 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 reporti ng could also help promote the development of an information system that allows ready interchange of data between the various programs (Part 75 ECMPS and Part 60/63 NSPS/MACT ERT), serving as a sort of bridge effort. According to the commenter, if this approach were adopted, the companion NSPS (subparts Da and Db) regulations should also allow use of ECMPS reporting, as an alternativ e to ERT, otherwise for utility units subject to NSPS, the potential consolidation be nefits of reporting MACT data in ECMPS would be lost.

b. Opposition to using a modified version of ECMPS.

Comment 3: Commenter 17767 states that the ECMPS opti on would be overly burdensome as their experience with it has shown it to be increasingly obsessed with minor da ta formatting issues that often prevent the submission of data (though it might have been acceptably formatted and submitted without issue in the past). According to commenter, it often involves many hours of manpower to correct those issues without benefit to the quality of the key data sets or the environment. Commenter anticipates that this would continue if MACT rule data were to be submitted via ECMPS

Response to Comments 1 - 3: The EPA disagrees with the comment ers who feel that using the ECMPS data collection process is overly burd ensome and in the assertion that minor data formatting issues often prevent the submission of data. The assertion points to the fact that many data reporting errors may not have been previously caught in th e past. The EPA created the ECMPS process to repla ce its previous less efficient and less precise data verification systems and processes. The result of this re-engineering is that there are significantly fewer formatting issu es that prevent submissions, and a fraction of submissions that contain critical errors at the clos e of each reporting period. This has added significantly274 to the EPA’s ability to validate adherence to regu latory requirements, as well as, checking for the technical accuracy of the data. The EPA has recei ved considerable support from the regulatory community for the revised ECMPS process, praisi ng its efficiency and the reduction in man hours required to report (and when necessary correct errors ) using the ECMPS process as compared to the old record type column format and ETS/MDC pro cesses that preceded ECMPS. However, the EPA recognizes that emissions reporting for continuously measured pollutants (SO 2 , Hg, etc.) from CEMS is structurally and procedurally diffe rent from what is needed to el ectronically collect reference method test data for periodically measur ed pollutants (PM, non-Hg HAP metals etc.). Therefore, the EPA has decided not to include detailed stack test data into ECMPS, ra ther will focus on only making minor revisions to ECMPS necessary to implement the EP A’s MACT data needs for continuously measured pollutants in a manner consistent with how ot her CEMS monitoring requirements are currently implemented through the ECMPS process. Doing so will minimize the structural changes to ECMPS needed while harmonizing the data collection and reporting for CEMS systems. Because more substantial modifications would be required of the ECMPS to accommodate the MACT data requirements for detailed reference method test data and other periodically meas ured pollutants, the EPA has decided to further develop the ERT to receive these data.

2. ERT reporting of emissions test data.

a. Support for ERT reporting.

Comment 4: Commenters 17767 and 17795 agree with the proposed rule th at 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 accepta nce. According to the commenter, ERT provides the flexibility to upload and import supporting data , and a common system will benefit operators with units in multiple states to have one system to generate reports for the EPA and local regulators.

b. Opposition to ERT reporting.

Comment 5: Several commenters (17621, 17718, 17775, 17790, 17868) express opposition to using ERT for reporting compliance test re sults, and commenters (17621, 17718, 17770, 17790, 17821, 19033) state that the ERT needs extensive revisi on before it is used for that purpose.

Response to Comments 4 - 5: The EPA disagrees that the ERT n eeds extensive revision before it can be used for documentation and delivery of complian ce test reports for which it is designed. The EPA also believes that with the January2012 addition of the ability to satisfy CROMERR compliance several state and local agencies will no longer require wet si gnature paper test reports . The EPA recognizes that some state and local agencies are reluctant to adopt new programs, assess the experiences of those that do adopt new programs and adopt new programs when they have determin ed 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 comp liance oversight, improved responsiveness with resour ces that are comparable to what they currently use to manage the paper reports which they currently receive. As a result , the EPA expects a reduction in the number of regulatory authorities which require the delive ry of paper reports with wet signatures.

i. Performance, susceptibility to viruses, and corruption of data.275 Comment 6: Commenter 17730 notes that the EPA is proposi ng to use the ERT as the platform for sources to electronically report data . The commenter states that the ERT is a Microsoft Access desktop application that is prone to computer viruses, has created several proble ms in using this application, and is subject to significant performa nce issues, including software crashes and shutdowns, inoperable features (like report generation), and inadequate identification of errors preventing data analysis. Commenter has banned the use of the Microsoft Access database system on its internal network due to this susceptibility and is, therefore, opposed to it s use for uploading data to the EPA WebFIRE database. Commenter is concerned with the corruption of data that may occur due to the susceptibility of this software package to virus infections. The commenter questions how the EPA woul d ensure that the data that would be submitted to the WebFIRE database woul d not be infected and require further attention by the EPA or by the source to rectify the information and if the EPA considered the cost of repairing a database that is eventually corrupted by virus atta ck, 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 techni ques to ensure that data within its network environment, including data submitted thr ough CDX is free of viruses and other security concerns. The EPA would expect that utilities woul d likewise ensure that the information it manages within its network and computers remains free of vi ruses and is not corrupte d. It is the source’s responsibility to submit complete and accurate data to the EPA.

Comment 7: Commenter 17770 provided examples of the aspects of the ERT that the commenter considers cumbersome. The commenter states that ev en though the third party emission tester provided the correctly formatted spreadsheet to import into the ERT, there were instances where the ERT would not accept the file. According to the commenter, this resulted in manual input of the data, which was time consuming and frustrating. Commenters 17770 and 17775 noted the program provides no useful error messages when data were input incorrectly. Th e commenters state that the EPA staff were helpful in correcting these errors, but the entire exercise on ly proved that the current version of the ERT is not fully developed for everyday use.

Comment 8: Commenter 17790 states that the ERT used for submitting 2010 ICR results and had significant flaws includin g: not accepting data, incompatible test methods, inoperable features.

Comment 9: Commenter 17621 observes that the ERT pr ovides 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 al so enhance data quality by storing information needed to understand sample result s, such as results of analysis of method and field blanks and laboratory quality control samples.

Response to Comments 7 - 9: The EPA recognizes that the ERT pr ovided 2 years ago for use with the utility ICR had some aspects of data entry that required improvement. To the extent that users identified those issues we have modified the ERT to address th e issue such that users c ould successfully provide the required test report with a ll the necessary documentation. Wh ile 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 fi nal rule. The EPA understands that the number and detail of information required for the ICR was greater than what we require for compliance tests. The EPA believes that with the increased familiarity in th e use of the ERT combined with the revisions to the ERT, the delivery of compliance reports to the EPA will not be a significant issue.

ii. Issues with detection limit flags.276 Comment 10: Commenter 17621 states that dataflags confuse detected a nd non-detected results. The EPA requires users to assign a “DLL” (detection level limited) flag to emission measurements with one analytical fraction above detecti on limit and others below detection limits. The commenter notes that this can cause a degradation of data usability.

Comment 11: Commenter 17821 states that ERT coding for method detection limits is confusing and cumbersome; the ERT does not support the typical non- detect with a (<) symbol. The commenter states that the ERT requires the use of bracketed symbols as a bracketed “less than” detection level value (e.g., [<0.0105]) and that for sample trains with multiple fractions (i.e., Method 29 Metals) this is very confusing and increases the possibility for miscoded data.

Response to Comments 10 - 11: The EPA recognizes that the way the EPA required users to enter individual laboratory com ponents was not the most effective way to provide this information. We also recognize the significant level of re sources required of source testers to properly enter laboratory data into their standard report s or into the ERT. This effort duplicat es the resources expended by laboratories to enter this information into the report provided to the source tester. This effo rt is also duplicated again when tests are evaluated by regulatory authorities. Th e EPA will engage the laboratories to develop an electronic lab report which the ERT will use to populate an expanded la boratory feature to allow for improved capabilities for use by test contract ors, state agency reviewers and the EPA.

iii. All required emission test meth ods are not supported by the ERT.

Comment 12: Commenter 17821 notes that Method 30B (Hg) is not supported by the ERT in the most current version and that in order to use the non- supported methods such as Method 30B a supplemental worksheet is used. According to the commenter, the use of elements outside of the ERT increases the opportunity for errors in both data entry and data review.

Response to Comment 12: The EPA has partnered with a vendor of Method 30B hardware and software to implement the electronic documenta tion of this test method into the ERT. The implementation of 30B in the ERT will be a non proprie tary application so users can use any vendors’ hardware or field software to manage the collection and analysis of the samples. This capability will be in the version of the ERT available within 6 mont hs following promulgation of the utility boiler MACT standard.

iv. ERT is burdensome.

Comment 13: Commenters 17730 and 17775 state that use of th e ERT is burdensome (easily adding 10- 20 percent to the cost of compliance testing), requiring manual inputting of significant amounts of information much of which is not relevant to pe rformance test results. Commenter 17730 states that, contrary to the EPA’s assertion, ERT as currentl y 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 th e EPA’s requirement to report electronically is not sufficiently defined to support reporting of all the information that mu st be entered into ERT in order to submit the data.

Comment 14: Multiple commenters (17718, 17621, 17725, 17790, 17816, 17820, 17881, 18014, 18498) state that using the ERT increas es the cost of emission test subm ittal due to the time needed to manually input significant amounts of info rmation. Several commenters (17718, 17621, 17816, 17881) note that manually inputting data significantly increases the po tential for errors in data277 reporting. Commenters 17718 and 17816 suggest that the EPA should make the tool more user friendly. Commenter 17881 states that using the ERT adds significant cost s to the stack testing process.

Comment 15: Commenters 17730 and 17775 state that the ERT re quires reporting of information that is not otherwise required to be repor ted under the applicable EPA testmethods, or the EPA’s proposed rule. Commenter 17730 believes that EPA’s requirement to report electronicallyis not sufficiently defined to support reporting of all the information that must be en tered 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 propo sed rule: proposed section 63.10030(a) and Table 10 require compliance with secti on 63.7(c). The commenter states that section 63.7(c) requires development and, if requested by th e Administrator, submission of a “site-specific test plan” to the Administrator “at least 60 calendar days before the performance test is scheduled to take place” (i.e., at the same time as the notification of intent to con duct 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. Th e 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 subm ission as part of the “res ults of a performance te st,” “the analysis of samples, determination of emissions, and raw da ta,” while ERT requires reporting of much more information, and including a test plan. The comm enter states that similarly, the EPA’s proposed requirement in section 63.10031(h)(1) to report “performance test data” is not sufficiently detailed to support reporting of all of the info rmation that must be entered in to ERT in order to submit data.

Comment 17: Commenter 19033 states that using the ERT was very cumbersome, and the reported data was not easily reviewable.

Response to Comments 13 - 17: The EPA disagrees that the ERT is excessively burdensome. The EPA does understand that some users of the ERT did not ha ve 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 testcrews 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 or ganization of field data in the ERT. The EPA has developed a supplementary field data spreadsheet module for use with a wide variety of proprietary field data collection spreadsheet applic ations. We have also provided instructions for merging this supplementary module with proprietary spreadsheet applications. When the supplementary module is merged with the proprietary field data spreadsh eet applications, the ERT will import the required information and greatly reduce the effort in enteri ng the field data into the ERT. The EPA is also embarking on an effort which will allow for laborato ry information to be electronically populated into the ERT.

The EPA disagrees that the ERT requi res the reporting of vast amounts of data that is not currently required for compliance test reports. The commenters ma y 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 w ould be required for a compliance test report. The EPA made the ERT flexible to accommodate a wide variety of existing da ta requirements specified by various state and local agencies and which are specified in various published EPA test me thods and published state and local agency test methods. The EPA does notexpect sources to enter data in to every available field of the278 ERT for every source test. Each st ate or local agency which has delegated authority has provided guidance on those data elements which theyexpect in compliance source tests.

v. The EPA has provided no explanation of how WebFIRE will work.

Comment 18: Commenter 17730 states that the EPA has provided no discussion in the preamble regarding how the information required to be submitted under ERT to WebFIRE will benefit the EPA and sources by improving emission factors. Commenter says that the EPA has yet to explain in any detail how the process of emission factor development from performance test data submitted to WebFIRE will work.

Comment 19: Commenter 17775 states that the EPA is requi ring reporting to ERT under provisions that are inapplicable, inappropr iate, and impossible to implement. Acco rding to the commenter, the EPA also has provided no information to suggest that WebF IRE will be operational by the proposed January 1, 2012 deadline. The commenter stated that the proposed requirements should be withdrawn.

Commenter 17775 states that to the extent EPA wa nts to add subpart UUUUU data to an emissions factor database, the EPA can do that on its own. That is not adequate ju stification for requiring additional reporting by EGUs. The commenter asks th at the EPA fully explain how the process of emission factor development from performance te st data submitted to WebFIRE will work. The commenter states that in its comments on the ANP R, the commenter expressed concerns about the process the EPA described and objec ted to any attempts to mandate submission of reports before the EPA had more completely explained its plans, completed any necessary rulemakings, and made operational its website. According to the commenter , the EPA should not be promulgating requirements intended to support a larger program piecemeal befo re that program has been fully developed. The commenter asserts that the EPA should reserve the question of mandatory reporting to WebFIRE until it has resolved the questions raised in the ANPR.

Response to Comments 18 - 19: The electronic submission of compliance test reports to the agency through the CDX is not solely fo r the purpose of developing impr oved emissions factors. While populating WebFIRE will allow the agency to improve em issions factors, the agency intends to use data stored in WebFIRE as the primary location for comp liance test reports for us e 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 loca tion which is already used to store source test data. As EPA and State and local agencies data syst ems mature, information provided in the ERT will be used to populate these data systems. The EPA is currently upgrading the AIRS Facility System and expects to replace manually entered information withelectronic population from the ERT. The EPA is also working with several state and local agencies to adopt the use of the ERT for delivery of compliance test reports.

vi. Opposition to submittal of RATA data.

Comment 20: Commenter 17718 asked that the EPA clarif y whether only CEMS RATA performed under this proposed rule are to be submitted el ectronically using the ERT and whether only SO 2 RATAs performed for the combined purposes of 40 CFR Part75 and this proposed regul ation 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 suggesti on that reporting of RATA results to WebFIRE would be helpful in the development of emission factors. The comme nter notes that RATAs are tests of CEMS in comparison to test methods and they are perf ormed under conditions that may or may not be representative of operations the EPA d eems relevant to emission factor development. The commenter also objects to the require d submissions of results after ea ch “performance evaluation” since that term is defined to include calibrations, whic h may be performed daily, whereas RATAs likely are performed only once a year and consid ers the proposed exclusion of “op acity 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 te st data, except opacity da ta” and “relative accuracy test audit data” electronicallyusing ERT. The commenter states that in proposed section 63.10021(a)(17)(i) and (ii), the EPA also includes a requirement for repor ting of “performance test data, except opacity data” and “r elative accuracy test au dit data” for LEEs. The commenter objects to these provisions, citing the following points: EGUs using PM CEMS a nd LEEs do not conduct RATAs. PM CEMS are subject to different tests (RCAs and RRAs). Accordi ng to the commenter, since LEEs comply by initially demonstrating a pplicability with emission tests a nd thereafter by fuel analysis, LEEs have no monitoring systems upon which to conduct RATA s. The commenter asserts that with respect to “performance test data,” the provisions are duplic ative of a more general provision the EPA proposes.

Comment 22: Commenter 17881 states that all of the inform ation the agency needs to determine an EGU’s compliance status already must be reported under the part 63 gene ral provisions, and hard copies of the test reports will be provide d to the Administrator (and/or the delegated authority). The commenter does not agree with submitting RATA PM data into the WebFIRE database. The commenter states that for those monitoring systems operated pursuant to 40 CFR Part 75, RATA information is already being submitted to the EPA in an electronic format.

Commenter 17881 disagrees with the provision to submit RATA results through the ERT. The commenter states that the CEMS is the compliance mechanism, not the reference method data that is collected during the RATA.

Response to Comments 20-22: We agree that it is appropriate and supportive of future regulatory reviews that the agency collect da ta from CEMS RATA testing. The fi nal rule requires that sources submit the test reports resulting from CEMS RATAs via the CDX to WebFIRE.

vii. Use of the ERT should require ru lemaking and opportunity for comment.

Comment 23: Several commenters (17730, 17725, 17775) believe it is inappropriate for the EPA to require submission of reports throu gh this rulemaking before the EPA ha s more completely explained its plans, completed any necessary rulemakings, and made operational its website. Commenter 17730 states that the EPA should not be promul gating requirements intended to suppo rt a larger program, piecemeal, before that program has been fully developed. The commenter requests that the EPA provide notice and opportunity to comment on all reporting requirements. The commenter concludes that the EPA should set aside the question of mandatory reporting to We bFIRE until it has fully addressed these issues. The EPA also has provided no information to suggest that WebFIRE will be operational by the proposed January 1, 2012 deadline.

Comment 24: Commenter 17775 states that the EPA should iden tify the software it proposes to require with sufficient specificity that it can be incorporated by reference into the rule. According to the280 commenter, if the EPA simply wants to requir e electronic reporting, the EPA should limit its requirement to a specific format (e.g., xml) and allo w sources to procure or develop their own software to comply with that format and the associated reporting elements.

Comment 25: Several commenters (17820, 18014, 18498) state th at the development of any reporting tool or reporting format should al so follow a transparent development process that includes feedback from the regulated community.

Response to Comments 23 - 25: The EPA disagrees that a separate and independent regulatory action is required to implement electronic reporting for sele cted regulated sources. Each of these regulatory actions for selected source categories provides ampl e notice and the opportuni ty for individuals to provide comment. The EPA also disagrees that the system to receive the compliance data must be operational prior to establishing the requirement for regulated sources to submit compliance data electronically. The EPA is on track to have the capa bility to receive electr onic 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 im plement electronic reporting for regulated entities which are covered by past and future rules. While we have provided draft procedures for the development of emissions factors, that effort is an ancillary effort to th e electronic delivery of compliance test reports. It is the agency’s desire to transition to the electronic de livery and storage of air emissions compliance source test data. With this transi tion, it is believed this valuable information will be more readily available for not only compliance purposes but for a wide variety of other uses.

To the EPA’s knowledge, there exists no standardized application fo r electronically documenting the conduct of source test reports. We be lieve that the ERT may generate interest in the development of software which is superior to the ERT. Should the agency see this interest, we will develop an XML Schema for source test reports from the data elements used by the ERT. At this time, we do not know of a private enterprise willing to develop software fo r source test companies to use to document field sampling and to generate a standardized electronic output.

viii. Hard copies of reports are needed for agency review.

Comment 26: Commenter 17719 notes that stack test data reported to state agencies must be considered along with additional, specific informa tion 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 tes ting was completed is understood. The commenter states that until the number and degree of source configuration and operat ion variables can be adequately accounted for and reported in one reporting tool, allowing the associated test data to be wholly considered, the commenter relies heavily upon the submission of written stack test reports. Thus, the comme nter supports the EPA’s preservation of the submittal of wri tten performance testing reports to st ate agencies, and states that as a state agency, it intends to continue to request sources to submit hard c opies 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.

ix. Hard copies of reports should not be required.281 Comment 27: Commenters 17718 and 17816 state that a source s hould not be required to make paper or other electronic submittals of the same data s ubmitted through ERT, but should only be required to reference data previously submitted.

Response to Comments 26 - 27: The EPA disagrees that the ERT is unable to store and make available to users all the information that may be required to document the degree of source configuration and operating variables. The ERT pr ovides the ability for the docum entation of process operating parameters, laboratory analyses of parameters associated with the process, text descriptions of process, controls, monitoring methodologies and descriptions of testing issues wh ich can be migrated into larger data systems if desired. In addition, the ERT is capab le of storing a variety of formats of electronic documents including but not limited to word processing fi les, spreadsheet files, scanned image files, and ISO standard ISO 32000-1:2008 compliant Portable Docume nt Format files. The continued delivery of only a paper version of source test reports will continue to limit the availability of the information contained in these reports to the individual which receives the report. This will also limit the information which is available to others within the state/lo cal agency, EPA and those needing access to this information to that information that the recipient manually enters into a widely available data system. The EPA believes that it is much more efficient to allow electronic populati on of data systems and electronic screening of source test s requiring increased scrutiny. The EP A recognizes that states with delegated authority may require s ources to provide complete reports in paper form. However, these paper reports with be in addition to the delivery of electronic reports through the EPA’s CDX. The EPA encourages state and local agencies to accept elec tronic reporting in lieu of a paper report.

x. Cross-media Electronic Reporting Rule.

Comment 28: Commenters 17730 and 17775 state that any elect ronic 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 requir ement that the document in clude a valid electronic signature, as defined in the rule. Commenter asks that the EPA explain how ERT or WebFIRE meets this requirement and whether ERT can satisfy other criteria the EPA deems necessary for valid electronic reporting, including whether (i) each electronic signature was a valid electronic signature at the time of signing; (ii) the elec tronic document cannot be altered w ithout detection at any time after being signed; and (iii ) each signatory had the opp ortunity to review in a human readable format the content of the electronic document that he or she was certifyi ng to, attesting to, or agreeing to by signing. The commenter is concerned th at the responsible official is unable to prevent revision of the information in ERT at or after the point of submittal.

Response to Comment 28: Submission of the ERT Project Data file through EPA’s CDX will be fully compliant with the Cross-Media Electronic Reporting Ru le. This includes the sign ature validation of the authorized official of the regulated source, the additi on of electronic means to verify that no changes in the file were made subsequent to submission and the opportunity to review in th e test report in a human readable format. As with a wide variety of electr onic submissions through the EPA’s CDX, the original file submitted to the agency will be maintained with pr oof of the original signature and proof that the file has not been altered. A copy of the f ile 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 th e contents of the file will be dire cted 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 co mply with the Paperwork Reduction Act and its implementing regulations, the EPA must speci fically identify each piece of information it seeks to have reported, explain how those data have practical utility, and es timate the costs of collection and the EPA review of those data. According to the comm enters, the EPA has not appropriately responded to these requirements in the proposal. Commenters state that if the EPA intends to require reporting of more than the test results alrea dy required to be reported under th e 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 me mbers of the public may have an opportunity to adequately respond to the proposed requirements.

Response to Comment 29: While the ERT may have the ability to store a wide variety of information, there is no information required by the ERT which is not required in this rule or in those source test methods used for demonstrating compliance with this rule. There may be info rmation which are required by the delegated authority but are no t stipulated in this rule or test method required by this rule.283 5B05 - Recordkeeping/Reporting: Other

Commenters : 17197, 17681, 17691, 17725, 17775, 17820, 17881

1. Electronic reporting.

Comment 1: Commenter 17197 notes that the December 31, 2011 date in section 63.10021(a)(16)(vii) appears erroneous since it specifies compliance notifications that are due long before the rule’s 3-year implementation and compliance deadline from final ru le Federal Register publication. The commenter also notes that the referenced (CDX) electronic da ta reporting capability will be available beginning January 1, 2012. The commenter recommends that the da te references in the proposed rule be replaced by a time reference (i.e., 180 days, 6 months, 12 months) from final publication of the rule.

Comment 2: Commenter 17881 states that due to the lack of specificity in the data to be submitted as required by section 63.10021(a)(16)(vii), the regulate d community will not know how to comply with this requirement; it needs clarification. The commente r states that the EPA da tabase 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 withproposed section 63.10021(a)(16)(vii).

2. Performance test notification time.

Comment 3: Commenter 17681 asks that the EPA choose 15 days or 21 days rather than the 30 days of notification before performance testing require d 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 pe rformance testing required in sect ion 63.10030(d) of the proposed rule.

Comment 5: Commenters 17775 and 17820 state that the propos ed requirements for notifications to conduct performance tests and compliance status ar e unclear. The commenters state that proposed section 63.10030(a) requires submission of all of the notifications required unde r the General Provisions of 40 CFR part 63 (specifically section 63.7(b) and sect ion 63.9(e)), proposed Table 10 also identifies section 63.7(b) and section 63.9 as a pplicable, sections 63.7(b) and 63.9(e) require notifica tion of “intent to conduct a performance test at least 60 calendar days before the performance test” is initially scheduled to begin, but that pr oposed section 63.10030(d) requires s ubmission of a “Notification of Intent” to conduct a performance test , “at least 30 days before the pe rformance test is scheduled to begin.” The commenters state that th is inconsistency should be corrected in the final rule and provide clarity as to whether the 30-day or 60 -day notification will be required.

Response to Comments 3 - 5: The final rule requires 30-day notice of all performance tests, and clarifies any discrepancy with the general provisions.

3. Multiple reporting requirements.

Comment 6: Commenter 17775 expresses concern that th e proposed rule contains redundant requirements for reporting. The commenter states that in section 63.10031 and Table 10, the EPA proposes to require compliance w ith most of the reporting require ments in the part 63 general provisions, including requirements for submission of “performance test results” under section284 63.10(d)(2), “performance evaluati on 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), pe rformance test results must be submitted as part of the “notifica tions of compliance status” under section 63.9(h) and must include “analysis of samples, determination of emissions, and raw data”; under section 63.8(e)(5), performance evaluation results, which include resu lts 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 “Exc ess emissions and continuous monitoring system performance reports” are submitted semi-annually, and must contai n the information in section 63.10(c)(5) through (13), section 63.8(c)(7), and 63.8(c)(8 ).” The commenter states that according to proposed Table 10, some of the provisions in section 63.10(c) are not applicable to subpa rt UUUUU, and that because the reports are to include information on “excess emi ssions” “as defined in the subpart, and subpart UUUUU does not define “excess emi ssions,” these provisions are not complete. The commenter asks that the EPA address these inconsistencies a nd omissions prior to finalizing the rule.

Commenter 17775 notes that performan ce test results and notifications of compliance must be sent to the state, the EPA Regional Office and permitting authority (if different than the state). The commenter states that as a result, under the part 63 genera l provisions alone, most EGUs already will need to prepare and submit three types of reports (in addition to the notification of compliance status) to both the EPA Regional Office and at least one state office: (1) performanc e test reports, (2) performance evaluation reports for monitoring systems, and (3) excess emissions and monitoring system deviation reports. The commenter states that proposed sec tion 63.100031(h)(3) also requires a hard copy of the ERT reports to be sent to the Administrator, bringi ng 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” requir ed under section 63.10(e), EGUs would submit the additional information specified fo r 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 co mmenter believes that this is excessive.

Commenter 17881 states that as proposed in sect ion 63.10030(d), there will be limited time to submit a test plan and notice and to receive agency approval, let alone receive and reviewresults from previous test events, prior to the next te st event. The commenter suggests th at one test notice or report be submitted for all testing conducted within a semi-annual period (or some other reasonable time frame).

Response to Comment 6: The agency agrees with the commenter’s assertion that there is a potential for duplicative reporting. To the extent po ssible, the rule has been revise d to eliminate reporting to both States and permitting authorities where the state is the permitting authority. The rule eliminates duplicative reports to EPA Regional Of fices. 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 fo r more than one copy of any report. The agency agrees with the commenter regarding the unclear requirements for excess emissions and deviation reports, and the rule has be en revised to clarify that all of these reports are excess emissions reports which are referenced in th e General Provisions of part 63. Als o, 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 noti ce 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 abili ty to choose means other than emissi ons testing to demonstrate compliance.

4. Section 63.10031(c)(7).

Comment 7: Commenter 17881 asks if, assuming that pa ragraph 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 comp liance, whether there is a deviation to report.

Response to Comment 7: If you combust a new fuel, you must conduc t 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 resp ect to the emission limit.

5. Notice of Compliance.

Comment 8: Commenters 17775 and 17820 ask that the EPA clar ify if some EGUs are not required to submit a Notice of Compliance Status or revise the section to make clear th at all EGUs must submit such a notice, citing inconsiste ncies between requirements in section 63.10031(e) and section 63.10005(a). The commenters note that proposed s ection 63.10031(e) requires EGUs to submit a “Notification of Compliance Status” according to s ection 63.9(h)(2)(ii), “[i]f you are required to conduct an initial compliance de monstration as specified in § 63.10011(a) ” but that under proposed section 63.10005(a) all EGUs “must demonstrate initial complian ce with each of the applicable emission limits in Tables 1 or 2...” and that, sec tion 63.9(h) on its face applies to each affected source when it becomes subject to a relevant standard.

Commenter 17775 states that under paragraph (3), the Notification of Compliance Status must include “[i]dentification of whether you pl an to demonstrate compliance witheach applicable emission limit through performance testing and fuel analysis; perfo rmance testing with operat ional limits (e.g., CEMS for surrogates or CPMS); CEMS; or sorbent trap monitoring system.” The listed options do not appear to correspond with the re st of the proposed rule. The EPA ne eds to issue a proposal that clearly articulates the various comp liance demonstration options.

Commenter 17775 states that under paragraph (3), the Notification of Compliance Status must include “[i]dentification of whether you pl an to demonstrate compliance witheach applicable emission limit through performance testing and fuel analysis; perfo rmance testing with operat ional limits (e.g., CEMS for surrogates or CPMS); CEMS; or sorbent trap monitoring system.” The listed options do not appear to correspond with the re st of the proposed rule. The EPA ne eds to issue a proposal that clearly articulates the various comp liance demonstration options.

Response to Comment 8: The language cited in the first paragr aph above has been changed to “initial performance test,” so that, for example, the notifi cation requirement does not a pply 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 reporting.

Comment 9: Commenter 17725 suggests that the EPA c onsider reporting st artup, 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 nece ssary state or local repo rting agencies as well. According to the commenter, this w ould also allow for a document trail to be maintained and eliminate the unnecessary use of maintaining bo th 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 th e final rule. Notices are required to be delivered or mailed to the address specified. A courtesy 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, 17627, 17637, 17638, 17640, 17648, 17654, 17655, 17656, 17675, 17677, 17681, 17689, 17696, 17697, 17701, 17703, 17705, 17707, 17711, 17714, 17715, 17716, 17718, 17719, 17720, 17722, 17724, 17725, 17730, 17731, 17732, 17734, 17735, 17736, 17738, 17740, 17741, 17752, 17756, 17757, 17758, 17761, 17765, 17767, 17770, 17774, 17775, 17776, 17789, 17790, 17791, 17796, 17797, 17798, 17799, 17800, 17805, 17807, 17808, 17810, 17812, 17813, 17815, 17816, 17817, 17818, 17819, 17820, 17821, 17824, 17829, 17834, 17837, 17840, 17841, 17842, 17843, 17844, 17846, 17852, 17854, 17856, 17857, 17868, 17870, 17873, 17876, 17877, 17878, 17879, 17881, 17883, 17885, 17886, 17887, 17902, 17904, 17909, 17911, 17912, 17913, 17918, 17919, 17925, 17930, 17931, 17973, 18016, 18021, 18024, 18025, 18026, 18027, 18031, 18033, 18034, 18037, 18038, 18039, 18419, 18421, 18422, 18422, 18424, 18425, 18426, 18428, 18430, 18433, 18434, 18437, 18438, 18439, 18440, 18441, 18442, 18447, 18448, 18450, 18477, 18487, 18498, 18500, 18501, 18502, 18539, 18541, 18575, 18933, 19032, 19114, 19121, 19122, 19212, 19213, 19506, 19653, 8443, 9738, 19536, 19537, 19538, 18023

1. General comments.

Comment 1: Multiple commenters (16850, 16858, 17004, 17022, 17026, 17028, 17110, 17654, 17689, 17715, 17724, 17740, 17797, 17820, 17821, 17868, 17909) ask that th e compliance date be clearly stated as soon as possible, as well as guidance for u tilities 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 years is the maximum compliance time authorized under the statute. See CAA section 112(i)(3)(A). If sources are unable to comply within 3 years, the owne r or operator may seek a 1 year extension of the compliance period from its Title V permitting authority if the source needs the additional time to install controls nece ssary 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 mont h or more. As we have stated elsewhere, we believe utilities shou ld 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 pol icies on extensions be published in a rulemaking.

Comment 3: Commenters 18034 and 18447 request clarif ication on what ac tions the federal government will take to ensure reliability. Comm enter 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 st atements about steps to ensure a reliable and reasonably-priced supply of electri city, particularly regarding localized issues, but does not provide any288 details concerning what authority wo uld be exercised. The commenter stat es that in one discussion (76 FR 24979), the EPA indicates that the federal governme nt will work with compan ies to ensure a reliable and reasonably priced supply of el ectricity, and in a separate discus sion (76 FR 24979), the EPA states that they believe they have the ability to work w ith companies making good faith efforts to comply with the standards so that consumers in those areas are not adversely affected. According to the commenter, the EPA should be clear about the steps it may take and what the federal government might do to provide all parties the opportunity to comment on the appropriateness and legality of the actions that the EPA and other agencies of the federal governmentare considering. The co mmenter states that additionally, states that might r eceive delegation of this regulation should be made aware of possible discretionary enforcement the EPA may plan on ex ercising. The commenter stat es that rather than pointing to vague steps that the EP A and the federal government may take to address electrical power system reliability problems after they occur, the EPA should be cons idering the consequences of their actions on the electrical power system and building an adequate safety margin into their rulemaking efforts to ensure that the electrical po wer system of the country is protected.

Commenter 18447 states that EPA states in the propos al preamble that “the 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 fulf ill this promise?” The commenter points out that maintaining generation capability an d output from their facility is ve ry important not only for satisfying the electrical demand (load) of the City of Ames and Iowa State University, but also for providing voltage support and electrical st ability to the interconn ected electric system of central Iowa. The commenter further notes that the impacts on the planning reserve margins and the need for more resources is a function of the tight compliance time line associated with the proposed rules. “Potential constraints of skilled construction labor, material shortages, financing, and escalation of compliance costs coupled with coordination of overlapping outa ges resulting in congestion expense could present challenges in meeting the compressed time schedule,” NERC concluded.

Response to Comments 2 and 3: Some commenters asked that EPA, by rulemaking, extend the compliance timeframe for this regu lation. Many of these commenters wa nted the certaintythat including the compliance timeframe through rulemaking would afford. Some of these commenters suggested unique situations where providing the extension could be crucial. Pub lic power facilities might need additional time because many of them must obtai n approval from public bodies for the compliance activities that might require a pub lic process that can be time c onsuming. Some comme nters felt that smaller facilities would have di fficulty procuring the engineering, labor and equipment needed for compliance. CAA section 112 specifies the dates by whic h affected sources must comply with this rule. New or reconstructed units must be in compliance im mediately upon startup or the effective date of this rule, whichever is later. Existing so urces may be provided up to 3 years af ter 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 ex tension, 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-year extension provision because EPA established regulations to implement the prov ision and the provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(i).

We believe that the permitting author ities have the discretion to use this extension authority to address a range of situations in which installation schedules may take more than 3 years.289 The EPA’s authority to provide relief from the require ments 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 maintaini ng electric reliability. One area where the EPA has some measure of flexibility is withrespect to the exercise of its en forcement authorities. Please see the preamble to the rule for an in depth discussion of both the 1-year 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-year extens ion under secti on 112(i)(3).

Commenter 17403 suggests that a commitment to install we t or dry scrubber, fabric filter, DSI, or other major emissions control equipment would automatica lly qualify the particular unit for the extension.

Several commenters (17808, 17648, 18450) suggest that companies requesting an extension have a compliance plan outlining the steps and timing of the project. Commenter 17648 also suggests operating criteria that must be maintained during the exte nsion, to minimize emissions and remove any economic incentive of deferring compliance.

Commenter 17797 asks that the EPA outline the conditi ons in which an additional year for compliance with the proposed regulations w ould be granted. The commenter re quests that power companies be allowed to operate on a restricted basis without a dditional controls as they upgrade their facilities.

Response to Comment 4 : The EPA established General Provisions applicable to CAA section 112 standards at 40 CFR part 63, subpart A. Included in those provisions are regulations implementing the 1 year compliance extension provisi on of CAA section 112(i)(3)(B). See 40 CFR 63.6(i)(4). The EPA did not propose to revise those regulations for EGUs in the proposed rule and we are not issuing amendments to those provisions in the final rule . We believe that sources should make themselves familiar with the regulations and contract the state pe rmitting authority as early as possible if the source determines that it will need a 1 year extension.

Comment 5: Multiple commenters (17403, 17623, 17714, 17758, 17774, 17799, 17868) ask that the EPA develop procedures and criter ia related to the Presidential exemption under section 112(i)(4). Multiple commenters (17758, 17820, 17868, and 18539) ask that the utility demonstrate good faith progress toward compliance.

Response to Comment 5 : The EPA is not authorized to implement the Presidential exemption provision in CAA section 112(i)(4). That provision authorizes the President to provide 2-year renewable extension for sources to comply with the final standards if he determines that the technology to comply with the rule is not available and the extension is in the national security interest of the U.S.

Comment 6: Commenter 17808 suggests that the EPA requi re utilities to subm it 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 th at will require all generators to provide notice to FERC, system operators, and state regula tors of expected effects of the E GU MACT and other EP A regulations. The290 commenters believe that such a process would provi de an opportunity for meaningful assessment and response to reliability issues. Co mmenter 18034 recommends the EPA wo rk closely with the regional agencies, such as (PUCT and ERCOT) that are respons ible for monitoring and a ssuring the reliability of the electrical power system to ascerta in the impact of the new rules on Texas’ and the nation’s electrical power system.

Commenter 17824 urged the EPA to adopt more flexib le standards and reasonable compliance timelines, which will achieve the Agency’s goals while ensuring a ffordable 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 reti re and which units will be re trofitted to comply with the final rule. However, the Agency does encourage f acility owners to notify the permitting agencies, the transmissions operators, and state regulatory agencies as early as possible of thei r intention to retrofit or close. Early notification will help to ensure that permitting is orderly and timely for plants that are retrofitting. It would also provide transmissions operators an early heads up so that they can plan for transmission upgrades to avoid reliability problems. It w ould also allow market solutions including new generation and demand side management solutions to co me into the market and ensure grid stability.

Comment 8: Commenter 17648 suggests a process based on early notificati on of retirements.

Comment 9: Commenter 18441 asserts that the 3-year time period is insufficient for making necessary transmission upgrades. They argue that although certain local reliability upgrades such as those that entail upgrades to existing substations can occur in an expeditious manner, other kinds of transmission upgrades may involve far more comp lex projects with extended delays. The commenter provides the following three examples to support their statements:

 The need for the Susquehanna-Roseland line wa s first identified by PJM and approved by the Board as part of 2007 RTEPP and was anticipa ted 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 th e Cromby Unit 2 and Eddystone Unit 2 requires 18 separate transmission system enhancements to a ddress the identified thermal, voltage and short circuit violations. The commenter notes that even though Cromby and Eddystone provided notice of deactivation in December, 2009, due to the need for such transmission enhancements the units are not going to actually shut down until May, 2012.

 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 upg rades to existing terminal equipm ent, are not expected to be in service until more than five years after such notice in May, 2012.

The commenter states that the an alysis 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 ow ners must only give 90 day notic e prior to shutdown in the PJM region, 76 FR 25056. According to the commenter, the requirement to be in compliance three years following publication in the federa l register, 40 CFR §63.9984, may resultin the shutdown of certain291 units that are critical to the reli ability of electric supply on a timelin e that is faster than the time necessary to replace the pow er or upgrade transmission.

Comment 10: Multiple commenters (17716, 17701, 17791, 17804, 17813, 18034, 17868, 17911, 17913, 17919, 18441, 19114, 18034, 18441, 18500, 18538) express concern that the EGU MACT may cause local transmission problems due to early retirementof EGUs. These commenters argue that the EPA should have assessed reliability at much more local level rather thanrelying only on na tional studies of reliability. Commenter 18034 notes that ERCOT anticipat es localized impacts on transmission reliability in the Houston and Dallas-Fort Worth areas as a re sult of the EGU MACT a nd other EPA regulations. Commenter 17701 notes that small older plants that w ould likely retire as a result of the EGU MACT and other environmental regulations may need to st ay running for a longer period of time because they provide service to an area that ca nnot otherwise get reliable power (a lo ad pocket) or they provide a key reliability service (e.g., black-start facilities). Commenter 17919 believe s that those areas most reliant upon coal-fired capacity are likely to face profound price, supply, and re liability concerns and that in the event of extraordinary events, only the additiona l peak-load capacity supplie d by coal-fired facilities are likely to provide th e resilience necessary to address poten tial weather-related blackouts or even cyber-security threats to critical infrastructure. Commenter 17731 believes that reduced grid reliability will be exacerbated by heavier reliance on non-fi nal (i.e., interruptible) transmission and gas transportation contracts that can re sult in curtailed deliveries of en ergy during peak periods when the energy is most needed.

Comment 11: Commenter 17716 considers the EPA to be dow nplaying transmission problems related to compliance. The commenter notes that transmissi on problems can arise because current paths are not used after plant retirement, or new/expanded tran smission paths are needed for purchased power to replace that from retired plants.

Comment 12: Commenters 17868 and 18500 mention recent bl ackouts in the ERCOT region of Texas as an example of localized reliability problems resu lting from too many units out of service at one time during a cold weather event. Commenter 17868 suggest s the EPA review the Texas PUC report on the February 2-3, 2011 outage in Texas to understand the implications of reduced electricity supply. The commenters believe this event is animportant reminder that having ge neration offline for upgrades even during a low load season has its risks.

Comment 13: Several commenters (17912, 18034, 18441, 18538, 18023) believe a more detailed study of the impacts of the EGU MACT on reliability of the electric network should be undertaken by the EPA. These commenters identify several areas in whic h they believe the EPA’s analysis 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 regul ated utilities. The commenter notes that IPPs do not have a regulated utility’s ab ility to shift load to other un its because many IPP facilities are subject to regional reliab ility mandates that require firing with oil. 2. Commenter 18538 believes the EPA has overstated th e ability of energy efficiency and demand response programs to mitigate the reliabil ity 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, th e 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 woul d likely result in greate r incidence of system outages than is considered acceptable in the elec tric 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 like lihood of a system outage event. The commenter states that the study takes into account components of system volat ility, including the forced outage and derating of generating facilities, load forecast uncertainties resu lting from weather, and the intermittent nature of wind generation and that consistent with industry practice, ERCOT se ts its minimum reserve margin at a level such that the expected frequency of a lo ss-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 requir ed by ERCOT, the commenter argues that the EPA has understated the impact of th e various rules on electric re liability in the ERCOT region. 4. Commenter 18034 notes that the EP A’s modeling assumes unlimited transmission capability within a model region (e.g., power generated anywhere in ERCOT can be transmitted anywhere in ERCOT) and states that this is not correct. The commenter notes that electrical power cannot be transmitted in an unlimited manner from anywhere to anywhere within a region as large as ERCOT and that fundamental principles of electrical transmission, su ch as thermal restrictions on transmission lines and voltage stability, restrict the distance that po wer can be transmitted over power lines within a region. 5. Commenter 18034 questions whether the EPA’s an alysis accounted for units classified as Reliability-Must-Run (RMR) facilities that are necessary to ensure gr id reliability in specific local

areas. 6. Commenter 18034 notes that the 25% surplus reserve ma rgin that the EPA cites as an indication that projected retirements will not aff ect reliability is a national aver age and is not consistent with ERCOT’s local projections for Texas. The most recent information from ERCOT, they argue, indicates that the ERCOT region curren tly has 17.5% of surplus reserve (Report on the Capacity, Demand, and Reserves in the ERCOT Region, May 2011); however, ERCOT expects this surplus reserve will drop to 11.1% by 2014 ev en 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-es timated the generation pot ential 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 in stalled 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 reti red and mothballed units in their capacity calculations. The commenter notes that the actual total generation resource capacity for ERCOT is 73,175 MW, based on the May 2011 ERCOT report, whic h 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 Environmenta l Regulations on the ERCOT 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 re sult of the EPA’s regulatory initiatives on EGUs. 9. Commenter 18441 argues that the EPA analysis err oneously 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 ther e are no transmission or deliverabi lity 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 deci sions are made in a decentralized manner based on price signals that are provided by wholesale markets that signal the financial profitability of existing and new entry resources. The commenter states that in contrast, the IPM employed by the EPA to model reliability impacts does not reflect the manner in which decisions are made in the wholesale market. According to the commenter, th e objective of the IPM is to minimize the systemwide, region-wide, or nation-wide cost of ach ieving resource adequacy and maintaining its293 representation of transm ission reliability subject to the en vironmental constraints imposed on generating units by the proposed rule. The commente r states that in shar p contrast to market dynamics, in the IPM modeling framework employed by the EPA, the retirement and new entry decisions are centralized; the decisions, are not based on market price signals and do not depend upon unit profitability or returns on investment. Rather, according to the commenter, the decisions are based on cost and perfect foresight of fu ture market conditions. As a consequence, the commenter believes the IPM model may reflect re tirement and new entry decisions that differ significantly from the actual market-based retirement and new entry decisions. 10. Commenter 18441 notes that the IPM framewor k 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 driv e retirement and new entry deci sions. The commenter notes that wholesale energy and capacity markets in PJM a llow for the participation of Demand Response and Energy Efficiency. According to the commenter, since these resour ces are generally lower cost capacity alternatives than traditio nal generation resources, the commenter argues that they can have an effect on market prices and ultimately on the retirement and new entry decisions of generation resources when considered in conjunction with the costs imposed by the EGU MACT. The commenter believes the IPM framework is likely missing possible generation retirements that may be driven by the interaction of the EGU MACT with these potentially lower cost capacity resources. The commenter is concerned that the EPA’s analysis understates the volume of system security and local reliability issues faced by RT Os and other transmission operators. 11. Commenter 18447 states that the IPM modeling of regions misses large 500 kilovolt (“kV”) reactive transfer interfaces that reside with in 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 parall el path or loop flows that occur across multiple regions and the international borde r between the U.S. and Canada th at 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 allevi ate localized constraints to maintain transmission security is small, sometimes only one or two ge nerating units have the ability to relieve such localized constraints. The commenter argues that th e deactivation or retireme nt of some generation would take away potential re-dispatch solutions and therefore likely trigger the need for transmission upgrades to prevent transmission reli ability criteria violations. The commenter notes that more than half of all the pending deactivations require transmission upgrades to allow the unit to retire without a violation of transmission reliability criteria. 12. Commenter 18023 believes that the EPA’s analysis is overly simplistic and in correctly assumes that demand response, energy efficiency, and rapid and wide-spread deployment of renewable energy resources will sufficiently replace lost coal-fired generation capacity both from a resource adequacy and bulk power system operations standpoint. Th e commenter argues that renewable generation resources and demand response do not provide inerti a, frequency response, or voltage support. 13. Commenter 18023 believes that the EPA has underestimat ed the impact that a decrease in available generating resources will have on the ability of authorities to comply with the reliability standards. The commenter believes the EPA’s failure to take into account mandatory BAL and VAR reliability standards (among others) in its disc ussion of reliability impacts of th e Utility MACT is a significant error. The commenter argues that violations of th e reliability standards have a wide variety of negative consequences for the electric system , including load sheddi ng and black-outs. The commenter notes several potential op erating reliability impacts of the Utility MACT rulemaking:294  Contingency Reserves: requires re sources sufficient to address system disturbances; 50 % must be “spinning reserves” ( i.e., reserve capacity at units already on-line);

 Load-Following Reserves: requires resources sufficient to re spond to load changes within an hour;

 Regulating Reserves: requires resources suffici ent to control system performance by responding within 4-6 seconds; all regulati ng reserve must be “spinning”;

 Frequency Control: requires sufficient resources capable of automatically and instantaneously responding to changes in frequency caused by co nstant tracking and matching of power demand and power supply to prevent imbalances;

 Voltage support: needed to enable the transmissi on of electricity over di stance. Grid operators must ensure there is enough reactiv e power at the right lo cations to support the electricity that is being delivered on the system; and

 In addition to all NERC standards developed and implemented by NERC/SERC, utilities must also satisfy planning reserve margin require ments established by NERC/SERC, as well as resource adequacy expectations estab lished by state public utility regulators.

Comment 14: Commenter 17731 questions the EPA’s view thatutilities can easily retire and replace units that are unable to comply with the new em ission limits. The commenter considers the option of replacing older units with more efficient units to be risky because they utility may spend the time and money to build new coal-fired units only to find out that the units cannot comply with the stringent new unit emission limits.

Response to Comments 8-14: The EPA agrees with these commenters that real threats to reliability from these rules are unlikely but agrees as well th at a process involving earlynotification can promote confidence in reliability and as well as promote th e kind of planning by companies, regulatory agencies, grid operators, and reliability organizations that can ensure a smooth transition to cleaner electric generating fleet.

The industry has adequate resources to install the necessary controls and develop the new capacity that may be required within the compliance time provided for in the final rule. 3 The EPA believes that the flexibility of permitting authorities to allow a fourthyear 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. Fu rthermore as indicated below, in the event that an isolated, localized concern were to emerge that could not be addr essed solely through the 1- year extension under CAA section 112(i)(3), the CAA provides flexibilities to bri ng sources into compliance while maintaining reliability.

Although there are a significant number of controls th at need to be installe d across the industry, with proper planning, we believe that the compliance sc hedule established by the CAA can be met. Many companies have begun to do the detailed analysis and engineering and are ahead of others in their compliance strategy. There are already tools in place (s uch as integrated resource planning, and in some cases, forward auctions for future generating capacity) that ensure that companies adequately plan for, and markets are responsive to, future re quirements such as this final rule.

The EPA agrees with these commenters that if comp anies 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 maximu m compliance time authorized under CAA section 112(i)(3)(A).295 agencies, and regional reliab ility 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, early notification will provide an opportunity for transmission planners, market participants, and state authorities to deve lop solutions to avoid a reliability problem. In RTOs with forward capacity markets, owner/operators that do not bid generating capacity that they plan to close wi ll provide an advance signal to mark et participants to take action to assure adequate future capacity. In all regions, early and public notification will allow market participants, planning coordinators a nd state authorities, as appropriate and in a timely fashion, to bring new generation on line, put demand side resources inplace, 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 shou ld be made no later than 12 months after this regulation is final in order to allow a smooth trans itioning to action to avoid a reliability problem. The EPA strongly encourages early notif ication, and believes that responsib le owner/operators should and will do the early planning for compliance and provide early notification of their compliance plans, especially where such plans include retiring one or more units.

On the supply side, there are a range of options including the devel opment of more centralized power resources (either base-load or p eaking) and/or the development of cogeneration or distributed generation. Even with the current large reserve margins, there are co mpanies ready to implement supply side projects quickly. For instance, in the PJM region, there are over 11,600 MW of capacity that have completed feasibility and impact studies and could be on-line by the third quarter of 2014. 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 types of resources can also be developed very quickly. In 2006, PJM had less than 2,000 MWs of capacity in demand side resources. Within 4 years this capacity nearly quadrupled to almost 8,000 MW of capacity. 6 In addition to helping address reliability concerns , reducing demand through mechanisms such as energy efficiency and demand side management practices ha s many other benefits. It can reduce the cost of compliance and has collateral air quality benefits by reducing emissions in periods where there are peak air quality concerns.

With regard to transmission, recent experience also shows that, in many cases, transmission upgrades to address reliability issues from plan t closures can be implemented in le ss 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 retireme nt of two units could be made within6 months of notification, transmission

4 Paul M Sotkiewicz, PJM Interconnection, Presenta tion at the Bipartisan Policy Commission Workshop Series on Environmental Regulati on and Electric System Reliabil ity, Workshop 3: Local, State, Regional and Federal Solutions, January 19, 2011, Washington DC, http://www.bipartisanpolicy.org /sites/default/files/Paul% 20Sotkiewicz-%20Panel%202_0.pdf , slide 6
5 National Electric Energy Data Sy stem (NEEDS 4.10) (EPA, December 2010)
6 BPC slides cited above – slide 5
7 http://www.exeloncorp.com/Newsroom/p ages/pr_20091202_Generati on.aspx?k=eddystone296 upgrades for the third unit would re quire slightly over 1 year and tr ansmission upgrades to allow the fourth unit to retire could be made in approximately 18 months. 8

The CAA allows CAA Title V permitting authorities the discretion to grant extensions to the compliance time of up to one year if needed for installation of controls. See CAA section 112(i)(3)(B)). If an existing source is unable, despite best efforts, to comply within 3 years, a permitting authority has the discretion to grant such a source up to a 1-year extension, on a case-by-case basis, if such additional time is warranted. This provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(i). We believe that the permitting authorities have the discretion to use this extension authority to address a range of situations in which installation schedules may take more than 3 years.

The EPA does not believe there will be a significant im pact on oil facilities as a result of the final rule. The rule contains “limited use” provisions that will m itigate 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 pollu tion control technologies (e.g., electro static precipitators) necessary to achieve the emission standards and the remaining un its that are not capable of converting to another fuel (e.g., subject to natural gas cu rtailment) are expected to instal l 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 av ailable at the time of the analysis of the final ru le in the 2010 Long Term Assessment. In the case of ERCOT, the reserv e margin was 12.5% percent in that assessment, but was updated after the margins were provided to NERC for the 2010 Long Term Assessment. The EPA’s IPM modeling of MATS shows that ERCOT would continue to meet its target reserve margin even taking into account its recently revised target of 13.75 percent. See TSD on Resource Adequacy for EPA resource adequacy results. The EPA believes the regional impact evaluation that it conducted was correct in focusing resource evaluation at the regional level, and treating local reliability issues within regions as best handled by standard reliability ma nagement practices as the rule is implemented. Processes for addressing local reliabil ity issues have been made more flexible in response to comments received on the proposed rule and are discussed in the preamble. See also responses elsewhere on local reliability issues. As the commenter notes, ERCOT re serve margins are above their target margin in 2012. The EPA agrees with the commenter’s recogn ition that ERCOT’s projec ted capacity shortage shown in that report is not primarily driven by EP A regulations. The EPA believes that there will be sufficient time to add more capacity where n eeded in ERCOT by 2015; EPA has also included additional flexibility on timing of compliance in the final rule. The EPA’s IPM modeling does not purport to capture all potential local reliability vari ables 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 retirement s. As noted earlier, the EPA modeled demand based on the AEO, which includes an estimated level of de mand response. The reliability contribution from renewable resources is a relevantissue only for wind resources. The reliability capacity contribution from wind resources in the analysis of the rule was based on estimates from the National Renewable Energy Laboratory (NREL) and was incorporat ed in the resource adequacy assessment ( See IPM documentation of wind resource and TSD on Resource Adequacy.) Local reliability issues can be addressed during implementation of MATS.

8 Cromby Units 1 and 2 and Eddystone Units 1 an d 2 – Deactivation Study, Updated September 7, 2010 - http://policyintegr ity.org/documents/20100907-cromby-and- eddystone-retirement-study-postingupdate.pdf297 Comment 15: Commenter 17725 asks that the compliance date align with the Power Year used by RTOs.

Response to Comment 15: The compliance date for existing sources subject to this rule is 3 years from this rule’s effective date. Th at is the maximum amount of tim e permissible under CAA section 112(i)(3)(B) which the EPA felt appropriate given the si gnificant work that some plants will need to undertake to come into compliance.

Comment 16: Commenter 17821 asks that the EPA devel op guidance on applicability of section 112(i)(6) in the final rulemaking.

Response to Comment 16: There are regulatory provisions in 40 C.F.R. section 63.6 (the general provisions) that govern the use of CAA section 112(i)(6).

Comment 17: Commenter (17887) supports the provision in the NARUC resolu tion 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 orde r to ensure reliability of operations.

Response to Comment 17: The EPA has consistently said that early planning for compliance is very important and we have urged utilities to take proactiv e steps in coordination withrelevant planning and regulatory authorities. The industry has adequate resources to install the necessary controls and develop the new capacity that may be required within th e compliance time provided for in the final rule. 9 Although there are a significant number of controls th at need to be installe d across the industry, with proper planning, we believe that the compliance sc hedule established by the CAA can be met. Many companies have begun to do the detailed analysis and engineering and are ahead of others in their compliance strategy. There are already tools in place (s uch as integrated resource planning, and in some cases, forward auctions for future generating capacity) that ensure that companies adequately plan for, and markets are responsive to, future re quirements such as this final rule.

Commenter 18: Commenter 17701 representing the Nationa l Association of Regulatory Utility Commissioners (NARUC) states thatalthough there are logistical is sues that may impact system reliability given the Proposed Rule’s compliance timef rame such as: coordination of offline time for the installation of pollution c ontrols on several plants in the same region; repowering or replacing a plant with a natural gas generator relies on access to natural gas pipelines; and transmission solutions generally take longer to plan, si te, build and interconnect than the proposed rule’s 3- to 4-year compliance timeframe, the association’s members will wo rk with their utilities to ensure that customers maintain access to safe and reliable power while gene rating plants install controls or while plants are retired and replaced or repowered.

Response to Comment 18: The EPA appreciates this comment and agrees that the state regulators have an important role to play in assuri ng that the transition to a cleaner elec tric generating fleet that this rule will bring about occurs as smoothly as possibl e so that reliable power is maintained.

Comment 19: Commenter 17701 advocates flexibili ty in the implementation of this and other rules to avoid compromising electric system reliability while minimizing cost impacts to consumers. According

9 As stated above, EPA has provided the maximu m compliance 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 20: Commenters 17701 and 17791 suggest the EPA a llow 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 electri city; (2) allow regulatory options for units that are necessary for grid reliability that commit to retire or repower; (3) a llow an EPA-directed phasing-in of the regulation; and (4) establish interim progress standards that ensure generation units meet the EPA regulations in an orderly, cost-effective manner.

Comment 21: Several commenters (17701, 17761, 17791, 17930, 19506, 19114) advocate flexibility in the implementation of the EGU MACT and other rule s to avoid compromising the reliability of the electric system. These commenters believe the EPA should incorporate greater flexibility into the EGU MACT to ensure adverse impacts on the reliabi lity of the electricity supply are avoided.

Response to Comments 19 - 21: There are several flexibilities in final rule that EPA wills help to avoid reliability issues. The regulation is applied facility wide so that facilities are able to average across units. Facilities also are able to average over time. They do not have to operate above the standard all the time but rather can meet the standard on a 30 day rolling average. There ar e alternative standard formats so that a plant can choose, for example, to meet a metals standard or a PM standard on either an input or output based level. In addition EPA is encouraging that permitting agencies be generous in offering the fourth year for installation of controls.

Comment 22: Commenter 17701 encourages the EPA to workwith state and federal environmental regulators to examine all possible options to main tain 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 re trofitting of existing electric generating units in an orderly manner that will ensure the continued supply of electricity and that will allow power generators to upgrade their faci lities in the most cost effec tive way, while at the same time achieving attainable efficiency gains and environmental compliance; and

Allow regulatory options for units that are necessaryfor grid reliability that commit to retire or
repower; and

Allow an EPA-directed phasing-in of the regulation requirements; and

Establish interim progress standards that ensure generation units meet EPA regulations in an orderly, cost-effective manner.

Commenter 23: Commenters 18441 and 18448 request that the EPA state in the preamble to the final rule that the permitting authority should explicitly authorize or endorse the extensions to the 3 year compliance deadline for units which the RTO or re levant Reliability Coordinator indicates are “Reliability Critical Units.” Comm enter 18441 believes that Reliability Critical Units that have timely announced their deactivation should be eligible for a 1-year ex tension of the compliance obligation because deactivating a generating unit is simply anothe r control option to comply with the final rule if the affected generating unit owner be lieves this is the least-cost comp liance option, and is effectively no different from a generating unit choosing to install re trofits to meet the emissions rate standards that299 cannot get its retrofits in serv ice by the January 1, 2015, compliance deadline. The commenter suggests that units choosing deactivation as a compliance option would only be granted an exemption if under the RTO’s independent analysis, they are deemed critical to system reliability and are required to stay in service for a defined period until transmission or repl acement resource solutions could be placed into service.

Response to Comments 22 - 23 : The EPA expects that the fourth year for compliance will be broadly available to these plants that need it for the installation of controls or on site replacement capacity or, where reliability could be at risk, for transmission upgrades and construction of replacement capacity off site. This will allow facilities to plan for a well-coordinated compliance period.

Comment 24: Commenter 17868 desires that EPA take into account the numerous contingencies that could cause concern for reliability during the comp liance period including multiple retirements, multiple outages, lack of generator response during a cold weather event, and revisions to the North American Electric Reliability Corporation’s (NERC) Critical Infrastructure Protection (CIP) Standards.

Response to Comment 24 : The EPA has indeed taken into account the wide array of contingencies that will prevent a facility from either retrofitting or closing within the compliance time frame. The EPA maintain that most, if not all, units will be able to comply with the requirements of this rule within 3 years. The EPA also believes that making it clear thatpermitting authorities have the authority to grant a 1-year compliance extension where necessary, in the range of situations desc ribed above, addresses many of the other concerns that commenters have ra ised. The EPA believes that the number of cases in which a unit is reliability critical and in which it is not possible to either inst all controls on the unit or mitigate the reliability issue through construction of new generati on, transmission upgrades, or demandside measures, within 4 years, is likely to be verysmall or nonexistent. None-the-less, where such cases appear EPA has authorities to manage these situa tions so that the maximu m environmental protection can be achieved while facilities c ontinue to come into compliance.

Comment 25: Commenter 17919 claims that analyses that have been submitted to the EPA showing that the rule does not cause a problem for electricity reliability, are “highly suspect” in that they are “largely from economic competitors with a vest ed economic interest in decreasing the economic viability of coal-fired generation and thereby incr easing the clearing price of energy for consumers – that dispute adverse reliability cl aims from the proposed rule.”

This commenter points instead to another analys is from the Federal Energy Regulatory estimating a large amount of coal-fired capacity ‘likely’ and “very likely” to retire. The commenter states that the EPA should utilize the flexibility afforded under the CAA to ease the compliance schedule set out by the proposed rule.

Response to Comment 25: The EPA makes no judgments about the motives of any of the commenters. The Federal Energy Regulatory Comm ission (FERC) report relied on here was a staff draft that was done before EPA had even proposed its regulations. It made assumpti ons about the stringency of the regulations that went well beyond what EPA actually proposed and final led. As such it has very little bearing on this rulemaking. Furthermore the FERC Chairman stated clearly that the study the commenter is referring to was a “back-of-the enve lope first assessment of the amount and location of potential generator retirements. He further said that informal asse ssment of that kind cannot be relied upon to determine specific effects on sy stem reliability. Therefore, it is inadequate to use as a basis for decision making.”300 None-the-less as stated elsewher e in this document, the CAA provi des flexibility to address any reliability problems should any arise.

2. Current compliance period should be shorter.

Comment 26: Several commenters (15678, 16122, and 17846) ask the EPA to ensure that compliance occurs as soon as possible. Commenters 16122 and 17846 make note of the EPA’s Trust Responsibility.

Comment 27: Commenter 17819 asserts that the 3 or 4 year implementation schedule for Hg control is not as expeditious as practicable . According to the commenter:

1. U.S. EPA asserted in 2000 that is appropriate and necessary to es tablish Hg emission standards for coal-fired EGUs. 65 FR 79825 (December 20, 2000).

2. By 2003, the DOE concluded ACI is an effective Hg control technology for coal-fired EGUs that requires minimal capital costs, is easily retrofitted and can achieve 90 percent removal efficiencies. See Durham, Michael et al. Full-Scale Evaluation of Mercury Control ByInjecting Activated Carbon Upstream of ESPS. 2003. available at: www.netl.doe.gov/technologies/coa lpower/ewr/mercury/control-tech/pubs/ A5-B2.pdf.

3. The DOE’s findings about the effectiveness of ACl Hg control systems are cons istent with the use of ACl in other industry sectors since the mid-1990’s to meet MACT mandates. See 62 FR 48348 (September 15, 1997).

4. Coal-fired EGUs in Illinois and se veral other states are already subj ect to state-specific Hg emission standards and have demonstrated it is already practic able to retrofit effective Hg controls. See “State Local Mercury Toxics Program for Utilities” from the NACAA, availa ble at \Vww.4cleanair.org; see also 35 Ill. Admin. Code § 225.230.

5. For its part, U.S. EPA’s present regulatory prop osal explicitly acknowledge s that all Hg control options take significantly le ss than 3 years to install. Proposed Rule at 441-447.

6. U.S. EPA also estimates that the implementati on of these controls will reduce cumulative Hg emissions from 29 tpy to 6 tpy. Id at 26 and 153. Each year that regu latory implementation is delayed will result in up to 23 tons of unnecessary emission s 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 emi ssions, U.S. EPA’s compliance timeline is not as expeditious as practicable.

8. To comply with the CAA mandate for emission st andards to be implemented as expeditiously as practicable, two commenters asse rt U.S. EPA must establish a more immediate deadline for implementation of Hg emission st andards for coal-fired EGUs.

9. Under any circumstances, it is contrary to the plain language of the CAA and against the manifest weight of evidence to allow a 4-year co mpliance schedule for any coal-fired EGU.301 On the other hand, commenter 17675 requests a 5-year compliance period for the Hg limits only. The commenter notes that this would be similar to the BACT status allowed under 40 CFR 63.6(i)(2)(ii).

Response to Comments 26 and 27 : Several commenters suggested that 3 years was too long for a compliance period given the delays in promulga ting 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 s hort 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 furt her delay. We agree that many plants will need fewer than 3 years to come into compliance and some alr eady are in compliance. For other plants, coming into compliance will require substantia l engineering and construction. The EPA finalized the 3-year compliance period for EGUs given the sheer number of sources that are in the category and that may have to install controls to comply with the final rule.

3. Current compliance dates are sufficient.

Comment 28: Multiple commenters (19536, 19537, 19538, 17110, 17402, 17648, 17808, 17854, 17870, 17973, 18025, 18027, 18421, 18425, 18438, 18439, 18450, 18487, 18501, 18541) ask that no additional time be granted for compliance.

Multiple commenters (19536, 19537, 19538, 16850, 17408, 17421, 17648) reference an April 2011 report entitled “Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants” where URS Corporation c oncludes not only that technology is readily available, but that the technology can typically be inst alled in less than 2 years.

Commenter 18421 states that based on that report, no a dditional controls would ne ed 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 u tility companies have anticipated the EPA’s rules and are already taking action to ensure a reliable supply of electrici ty in their service territory and beyond. Commenter 17808 cites two companies that have made planning efforts in advance of final rulemakings. The commenter cites one company (N extEra Energy) that be gan evaluating control technology before the release of th e proposed rule. The commenter c ites another company (Constellation Energy) that similarly conducted preliminary engineering studies before the Maryland Legislature enacted the Healthy Air Act of 2006.

Commenters 17648 and 18450 agree that there is significant excess genera tion capacity in the country and reliability will not be threatened by the rule.

Several commenters (18487, 19536, 19537, 19538) agree that the 3-year period will not adversely affect electricity system reliability.

Commenter 17110 urges the EPA to proceed with fina lizing 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 states that a shortage of skilled labor is unlikely to prevent utilities from meeting the compliance requirements.

Commenter 18421 notes that the Buil ding and Construction Division of the AFL-CIO has stated that there is no evidence to suggest that the availability of skilled manpo wer will constrain pollution control technology development. According to the commenter, in fact, given the high levels of unemployment in the construction sector, these jobs are much needed.

Several commenters (17844, 18439, 18450) believe that the industry is well-positioned to comply in the time allotted without threateni ng electric system reliability. Commenters (17844, 18450) cite the following sources: two recent reports – one from M.J. Bradley & Associates and Susan Tierney of the Analysis Group, and the other from the Bipartisan Polic y Center – that independe ntly conclude that the electric industry is well-positioned to comply with the EPA’s proposed air regulations without threatening electric system reliability. According to th e commenters, if electric sy stem reliability were to be threatened in local areas as a result of the rule, the EPA has the st atutory authority to grant, on a caseby-case basis, extensions of time to complete the installation of pollution control systems.

The commenters assert that in addition, recent electri city forward capacity market auctions in the PJM and ISO-New England markets for the period of 2014 and 2015 indicate that the capacity markets cleared with electricity reserve margins of 20 per cent in PJM and greater th an 14.4 percent in ISO-New England. According to the commenters , these reserve margins are well inexcess of the federal reliability standards set by the NERC for the year 2015, and these resu lts cover periods after the rule is expected to have been in place for at least 6 months, demons trating 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 do es not see impacts from the propos ed climate legislations or anticipated EPA regulation as a reliability c oncern. Commenter 18450 cites a January 2011 report by Charles Rivers Associates (CRA) that concludes th at (1) Less than 5 percent (35 GW) of the total capacity in the EIC will retire by 2015; and (2) Electric system reliability can be maintained while transitioning to a cleaner energy future through increasing operation of ex isting, underutilized gas plants, coal-to-gas conversions, ne w 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 ge neration and grid management technologies that are making “baseload” power obsolete as FERC Chai rman Wellinghoff noted in 2009. Indeed, a combination of renewable energy (such as wi nd, solar, biomass, geothermal, low-head hydro), natural gas and flexible generation t echnologies, and energy efficiency can now meet new electricity demand, and begin to repl ace or back out existing generation, within most balancing areas in the country. Such combinations of technologies, paired with smart grid management in balancing areas (including use of forecasting of output from wind and sun generation) can ensure a reliable electricity supply. The use of renewable energy and efficiency will also provide sa vings 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 li ttle downtime to install, is effective for bituminous and sub bituminous co als, can achieve 90 percent removal when303 used with a fabric filter, canbe integrated with virtuallyevery configuration of air pollution control equipment including ESPs, fabric filters, we t and dry scrubbers.

Commenter 18425 states that the 1-year extension if the f acility is unable to inst all appropriate controls will protect electricity system reliability. Accordi ng to the commenter, applying the extension to both the installation of add-on controls and the construction of on-site replacement power is appropriate under the CAA.

Commenter 17928 supports the schedule and the agency’s authority to extend th e time allowed provided that any additional time granted does not provide an undue economic advantage.

Comment 29: Commenter 17648 asked that EPA establish unif orm criteria for the section 112(i)(3)(B) case-by-case one-year extension and allow plants thatreceive the extension to dispatch only to meet reliability needs during the extension period.

Comment 30: Multiple commenters (17254, 17620, 17648, 17810, 17852, 17853, 18025, 18421, 18932) agree with the EPA’s assessment that the new ru les will not jeopardize or impair the reliability of the electricity supply. Other comment ers (17254, 17648, 17810, 17852, 17853) cite reliability assessments that show sufficient capacity to ensure re liability of the electricity network after the rule takes effect. These include:

 North American Electric Reliability Cor poration (NERC). 2010 L ong-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 Forthc oming Utility MACT” (Dec. 16, 2010)

 Michael J. Bradley, Christopher E. Van Atten, & Amlan Saha (M.J. Bradley & Associates LLC) & Susan F. Tierney (Analysis Group), “Ensurin g a Clean, Modern Electric Generating Fleet while Maintaining Electric System Reliabi lity: Summer 2011 U pdate,” (June 2011)

 Susan F. Tierney & Charles Cicchetti, “The Re sults in Context: A Peer Review of EEI’s ‘Potential Impacts of Environmental Regulat ion on the U.S. Generation Fleet’” (May 2011).

 Integrated Planning Model data commissione d by America’s Natural Gas Alliance (ANGA).

 Credit Suisse, Growth from Subtraction: Impac t of EPA Rules on Power Markets (September 23, 2010), p. 45, available at http://epw.senate.gov/public/index.cfm?FuseAction=File s.View&FileSto re_id=b42de70d--

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Comment 31: Several commenters (17648, 17853, 18421) believe that the number of coal-fired EGU retirements that will result of regulation of EGUs have been overestimated by some sources. These commenters note that independent analyses support th e EPA’s retirement projec tions, and criticisms of the EPA’s projections are overstated. Commenters note that EEI’s reportresulted in inflated unplanned coal retirements because their modeling scenarios in correctly assumed that th e Waxman-Markey climate change bill passed Congress, that the CWA section 316 cooling tower regulations would mandate a onesize-fits-all standard, and MACT limits that are more restrictive than those proposed in the Toxics Rule. Commenters also state that the Tierney-Cicchetti Peer Review Report found that only one of EEI’s scenarios represented a plausible regulatory scenari o, 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 overstat es the impacts of the section 316 rule. Commenter 18421 believes that the North Amer ican Electric Reliability Corporation (NERC)304 “2010 Special Reliability Assessmen t: Resource Adequacy Impacts of Potential U.S. Environmental Regulations” may also overestimate the impact of new regulations.

Comment 32: Several commenters (17648, 17810, 17852) belie ve that existing gas units have significant untapped potential, which can be utilized to maintain reliabil ity without the n eed 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 pow er produced by these retired units coul d be replaced using only 5% of the unused capacity of existing combin ed cycle gas units. Commenter 17810 notes that the existing natural gas-fired EGU capacity will allow the industry to ma intain its reserve margins, including during the scheduled outages that will be necessary to in stall pollution control equipment required by this regulation.

Comment 33: Several commenters (17620, 17648, 17853, 17875, 18932) argue that EGUs will have sufficient time to comply with the rule without disr upting reliability. These co mmenters note that power plants have known about the various new regulations affecting power pl ants for several years and have therefore had plenty of time to prepare. These commenters note that many public utility commissions require integrated resources plans, which implemen t a planning mechanism to assure adequate reserve margins are maintained. Commenter 18932 notes that se veral utilities have made statements indicating that they are well positioned to comply with the E GU MACT, as well as other EPA regulations that will affect the utility sector.

Comment 34: Commenter 17620 points out that several states have implemented Hg limitations for EGUs without adverse impacts on reliability.

Comment 35: Several commenters (17110, 17810, 18025, 18421) note that forward capacity auctions, such as those held by PJM and ISO-New England fo r the years 2014 and 2015 (aft er the Transport Rule and this proposed rule will be in effect), have shown that the regions will have more than enough capacity to meet federal reliability standards without significant price increases.

Comment 36: Several commenters (17648, 17810, 17853, 18025) beli eve 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. Thes e commenters note that a number of practical and legal options exist for when an EGU is to be retired or needs greater tim e to install controls. Commenters further note that a resolution that maintains reliabilitycan be reached through the authorityunder the Federal Power Act, or through exercise of enforcement discretion in a consent order to decree that accommodates both environmental imperatives and reliability concerns. Commenter 17648 points out that if reliable electric power is compromised by compliance with environm ental regulations, the U.S. DOE, the EPA, state agencies, and regional transmission organizations (RTO s) can work together to strike a balance in protecting public interest in bot h objectives. Commenter 17648 also not es that RTOs typically have advanced warning of proposed unit retirements and that each RTO has procedures to assure that threats to reliability are identified early enough to be avoided.

Comment 37 : Commenter 17810 notes that the EPA can gran t 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 administrativ e orders of consent or consent decrees with power plants that allow them to run under spec ific 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 emergenc y circumstances, and if a widespread reliability concern were to arise that could not be addressed through these statutory mechan isms, the President also305 has the authority under the CAA to ex tend deadlines in the rule if techno logies are not available and it is in the national security interest.

Comment 38: Commenter 18039 questions the s uggestion that existing units be allowed to run for an additional year while a replacement is constructed, w ithout being subject to MACT standards for that year. The commenter agrees that this is a reasonable scenario for facilities that will use that year to construct a replacement unit with si gnificant long-term emission reducti ons. However, the commenter is concerned that a facility in the process of building replacement pow er may decide to operate a highemitting unit for an additional year, specifically due to the extension. The commenter therefore objects to the extension, for fear a large amount of pollutants will resu lt. The commenter also asks that if construction replacement power last s longer than the one-year extensi on, the final rule wording make clear that the older unit is not permitted to avoid MACT complianc e beyond that year, even if the replacement is not yet on-line.

Comment 39: Commenter 18421 called on the EPA, the Department of Energy, and the Federal Energy Regulatory Commission to expand and accelerate interac tion with regional utility planning and operation centers, the National Association of Regulatory Utility Commis sions, state PUCs, and all market participants to ensure that the measures av ailable to preserve electric system reliability while providing for life-saving reductions of Air Toxics are implemented.

Commenter 19114 states that EPA notes that before th e final rule, they will wo rk with “DOE and FERC to identify any opportunities offered by the authorities and policy tools at the disposal of DOE and/or FERC” to protect reliability. Acco rding to the commenter, this language suggests that EPA has not consulted with DOE and FERC to date, which sugg ests that the necessary rule coordination or harmonization is not occurring. The commenter states that the statement implies that EPA only sees flexibility on the part of DOE and FERC to protect re liability and that adding th is flexibility into the MACT rule itself, or other proposed rules for that ma tter, is not a concern for EPA, which goes directly against the Executive Order.

The commenter states that it has been involved in a series of meetings with PJM, SPP, EPA, DOE, FERC, and NERC to discuss the impacts of this and other EPA rulemakings on the reliability of the transmission system as well as to discuss ways that EPA can provide flexibility to ensure reliability. The commenter suggests that EPA closely examine all of the publicly announced implementation plans from utilities to assess the accuracy of the data EPA is relying on to make the claim that grid reliability is not an issue. According to the commenter, these data must take into account actual and planned future regulations and their impact on the electric sector, as well as resulting rate and reliability impacts, and only in viewing a comprehensive and holistic analysis of the electric sector can there be a reasonable discussion of the reliability impacts. The commenter st ates that this type of cross-functional analysis should include the most specific localized or unit leve l reliability analysis possi ble in order to pick up key ancillary services important to grid stability.

Response to Comment 28 - 39: The EPA has set out in the preamble to this rule, the situations that merit the one-year extension under CAA section 112( i)(3)(B). While authority to grant the 1-year extension is given to the state perm itting authorities, EPA expects thatthat 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 broadly av ailable to facilities. Plea se see the preamble for a fuller discussion of the 1-year extension.306 4. Current compliance period should be longer.

Comment 40: Numerous commenters (18023, 8443, 9738, 16705, 16469, 16849, 16856, 17022, 17055, 17254, 17265, 17297, 17368, 17383, 17400, 17402, 17403, 17406, 17608, 17623, 17627, 17637, 17638, 17640, 17648, 17654, 17655, 17656, 17675, 17677, 17681, 17689, 17696, 17697, 17703, 17705, 17707, 17711, 17714, 17716, 17720, 17722, 17724, 17730, 17731, 17732, 17734, 17735, 17736, 17741, 17752, 17756, 17758, 17761, 17765, 17767, 17770, 17774, 17775, 17790, 17798, 17799, 17800, 17805, 17807, 17808, 17810, 17812, 17813, 17815, 17817, 17820, 17821, 17824, 17829, 17834, 17837, 17840, 17857, 17868, 17870, 17873, 17876, 17877, 17878, 17879, 17881, 17883, 17885, 17887, 17902, 17904, 17909, 17911, 17912, 17913, 17918, 17925, 17930, 17931, 18016, 18021, 18024, 18026, 18027, 18031, 18037, 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 en tities be granted addi tional 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 year s. Several commenters (18575, 19032, 19213) request that the EPA allow a total of 5 years for compliance.

Multiple commenters (18023, 17623, 17689, 17714, 17722, 17731, 17732, 17756, 17775, 17817 (major sources of HAP), 17868, 17904, 17925) request that the EP A allow a total of 6 years for compliance.

Multiple commenters (17022, 17408, 17735, 17758, 17761, 17817 (non-major sources of HAP)) ask that the timeframe be extended until 2020.

Several commenters (17724, 17741, 17805, 17868) ask that a compliance timeline of 9 years be permitted.

Multiple commenters (17055, 17408, 17677, 17734, 17756, 17761, 17774, 17791, 18024, 18026, 18422, 19506) ask that the EPA consider a flexible, gradua l, or staggered compliance schedule for this rulemaking.

Commenter 17911 requests a 2-year ex tension on compliance with some provision for further extension for local utilities, based on the utilities’ additional bur den of maintaining a public ly accountable process. The commenter requests provision for fu rther extension provided that th e local utility can document that they have pursued a good faith effort to expediti ously secure approvals, fi nancing, engineering, design, manufacturing, acquisition and in stallation of the necessary emission control equipment.

Commenter 18441 states that outage windows to accommodate upgrade construction are limited to opportunities when prevailing system conditions perm it, so that operational reliability is not compromised. The commenter appreciates the EPA’s r ecognition of the need to spread complex outages over multiple outage periods. According to the commenter, as the breadth of the outages and the availability of retrofit materials may impact the sche duling of outages, it is not clear that the proposed 3+1 timeline provides sufficient flexibility for the co mmenter, 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 transmission organization and an identification that the unit in que stion is a reliability critical unit which cannot be replaced with alternative resources or transmission reinforcements in the 4-year time allotted would be allowed a limited “safe harbor” from penalties until th e regional transmission organization indicates that adequate resources have been put in place to addre ss the reliability concern. The commenter states that the regional transmission organizatio n’s findings would be developed inopen stakeholder processes and made available for the EPA’s (or state air permitting authority’s) ultimate determination as to whether to grant such an extension and that such a process may entail the EPA authorizing or endorsing a schedule of compliance in the affected ge nerating unit’s Title V permit through the implementing state authority, in coordination with the regional tr ansmission 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 streamlinedprocess including the EPA, and the implementing state authority working with the asset owner and the regional transmission organization to grant extensions beyond January 1, 2016.

Multiple commenters (16469, 16850, 17608, 17640, 17705, 17711, 17716, 17719, 17724, 17730, 17752, 17756, 17761, 17774, 17805, 17820, 17821, 17837, 17840, 17868, 17902, 17918, 17919, 17931, 18016, 18033, 18037, 18422, 18428, 18440, 18442, 18498, 18575, 19506) ask that the EPA consider other simultaneous rulemakings and extend the complian ce period. Commenters sp ecifically 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 Lim it Reductions (17724, 17774, 17805, 17919) f. Cross State Air Pollution Rule (16850, 17640, 17705, 17716, 17730, 17752, 17756, 17761, 17774, 17820, 17821, 18442, 18498, 19506) g. NESHAP for industrial, commercial and institutional boilers (16469, 17608, 17711, 17756, 17837, 17840, 18024, 18424, 18442) h. NESHAP for commercial and industrial solid wast e incinerators (17608, 18024) i. NSPS for greenhouse gas emissions from EGUs (17608, 17774, 17918, 17919, 18440, 18442, 18498) j. NAAQS for SO2, NO2, ozone, and PM (17821, 17918, 17919, 18440, 19506) k. Area source Boiler MACT (18024)

Multiple commenters cite previous compliance timeline extensions that were granted:

a. Marine Tank Vessels - 1 year (18023, 16469, 17254, 17368, 17403, 17623, 17681, 17696, 17734, 17758, 17775, 17837, 17840, 17857, 17902, 17931, 18033) b. Pulp and Paper Production - 8 years (17623, 17774) c. MON (17623, 17774) d. NESHAP for Secondary Lead Smelting - 1 year (17716, 17731)

Multiple commenters (8443, 17402, 17627, 17767, 17821, 17868, 18021, 18037, 18502) ask that the EPA consider physical space limitations. According to the commenters, without sufficient space to install control devices, units may have to be retired.

Commenter 18575 discusses its diverse generation portfo lio and says 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 abilit y to afford and meet compliance timelines. The commenter gives the following examples:

1. EGU MACT: As proposed, the commenter’s coal-f ired generation will be covered by the proposed EGU MACT; 2. RICE Rule: commenter’s contracted generation fr om gas-fired, reciproca ting internal combustion units are covered under the EPA’s recent RICE Rule; 3. CSAPR: Commenter’s Whelan En ergy Center unit is covered by th e CSAPR (formerly known as the “Clean Air Transport Rule”); 4. CCR Rule: Commenter’s coal-fired resources face compliance requiremen ts related to the disposal of coal combustion residuals from coal-fired power plants to be finali zed by the EPA in 2012; 5. GHG Rule: Commenter’s facilities face restric tions 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 secti on 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, locat ed in Wyoming, faces additional regulatory costs since th e state’s SIP is still under reviewand could face new, potentially very expensive retrofit requirements to be completed by 2013, according to the EPA’s Regional Haze timeline.

Commenter 17911 asks that the EPA consider th e unintended consequences of recommending technologies that make CCR more difficult to recycl e. 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 : In this regulation the EPA provide d the maximum 3-year compliance time authorized under the statute. See section 112(i)(3)(A). Fu rthermore, the EPA’s actions in other CAA section 112 rulemaking actions auth orizing longer compliance periods are no longer relevant. Since those rules were issued, the D.C. Circuit Court has determined that the EPA does not have authority to provide a compliance period in excess of 3 years. See NRDC v. EPA , 489 F.3d 1364, 1373-74 (D.C. Cir. 2007) (rejecting a 1-year extension for all sources in the category because of changes to reporting requirements issued after the final rule setting forth the emission standards were initially promulgated too short). However as discussed elsewhere in this document and much more fully in the preamble, the permitting authorities do have authority to grant a 1-year extension under a range of circumstances. Beyond that the CAA provides mechanisms for sources to come into complia nce while maintaining electric reliability.

The following is a response to the various reas ons given in comments as to why the proposed compliance time frame is too short. For a fuller di scussion of these issues please see the Technical Support Document entitled, “An Assessm ent of the Feasibility of Retrof its for the Toxics Rule” in the docket.

Claims of Infeasibil ity 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 specifi c analysis to assess the feasibility (e.g., ability of309 companies to install the required controls within th e compliance time-frame) and potential impact of the proposed rule on reliability. For that analysis entitled “An Assessment of the Feasibility of Retrofits for the Toxics Rule” dated March 9, 2011, the EPA has pr ojected the quantity of each APC technology that may need to be newly retrofitted and in service by the compliance date(s). Th e EPA used its IPM model to analyze which APC technologies w ould likely be used, and in what quantities, to achieve compliance with the proposed Toxics Rule.

The EPA’s assessment shows that a reasonable, mode rately paced effort of the power sector and supporting industry, including some ear ly starts, would result in many of the needed retrofits being installed by January 2015 with some needing up to an additional year. Inorder for all retrofits to be completed by January 2015, most projects would have to start early and the sectorwould have to engage in a more aggressive deployment program. In the ev ent that individual project s cannot be completed by the January 2015 statutory deadline for compliance, th e CAA offers affected sources the opportunity to apply for a 1-year extension.

Claims That More Time is Need ed for Small Entities To Comply

As stated above, the EPA’s authority to provide more than three years to comply with the standards is constrained by CAA section 112(i)(3)(A ) and the D.C. Circuit Court interpretation of that provision. See NRDC v. EPA , 489 F.3d 1364, 1373-74 (D.C. Cir. 2007) (rejecting a 1-year extension for all sources in the category after the agency promulgated changes to reporting requirements issued after the final rule setting forth the emission standa rds). The compliance provisions of the statute do not provide an exception for small entities.

Inadequate Labor Pool, Low Skill Level & Insufficient Equipment Suppliers

With current unemployment rates, sufficient quant ities of engineers and skilled craft exist for implementation of this rule. Likewise, for the extr eme case of local labor s hortages (which is not anticipated), this challenge can be overcome by in stituting a workforce development action plan during project execution. This sector’s equipment suppliers and manufacturer s are underutilized and have been since 2010.

Site Congestion Can Lengthen Retr ofit Timing and lead to retirement

One commenter suggested that the faci lities that were easy to retrofit, did retrof it 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 th e past. Several commenters said th at plants may retire because space constraints would pr ohibit retrofitting.

Available space is a problem at many remaining faciliti es. Space constraints are a challenge that must be addressed early in the design stag e of a compliance strategy. There are a number of ways to economize the available space but ultimately each plant is differ ent and the solutions will be different. Many of the controls that the EPA expects plants to use to comp ly with MATS, especially DSI and ACI, work well at a space constrained facility. In addition, the EPA e xpects that in many cases it will be possible and economic to combine emissions from several units into a larger control device. In such combined multiunit cases the installation time should be only slightly greater than for a single unit, and s till feasible for compliance by 2015-2016. In any event, a multi-unit retrof it 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-tim e mobilization, extended equipment rental, dedicated310 staging area, efficient skilled craf t utilization, and reduced administra tive outlays. Furthermore, units can be “tied-in” sequentially, avoiding a complete station shutdown during installation.

Successful examples include Dickerson Station’s three 190 MW units feed a single scrubber which discharges into a single flue stack. Chalk Point station’s two units share a single common wet FGD. FirstEnergy’s Sammis station’s wet scrubber project combined emissions from seven units into three absorbers. AEP’s Clifty Creek and Kyger Creek stat ions will employ similar design concepts for their wet FGDs. And at WE Energies’ Pres que Isle facility several units ar e tied into one fabric filter.

Finally the rule allows facility averaging for existi ng EGUs in the same subcategory so that in many cases it may be possible to re trofit only some of the units and achieve the standards.

Time frame for Compliance Is Too Shor t to Construct and Permit an FGD Landfill

The compliance deadline allows sufficient time for completing landfills for FGD solids disposal. For example, DP&L will construct a la ndfill within 18 months to accept wastes generated from Stuart and Killen stations scrubbers. The EPA notes, however, that retrofitting units do not necessarily need to complete landfill construction ahead of commencing operation of the retrofit to achieve cost-effective emission reductions under the Transport Rule prog rams. Such a source may either utilize a completed portion of the newly permitted landfill under constructi on, transfer waste off-s ite to a permitted landfill within the owner’s fleet, or c ontract waste removal (and disposal ) services. For example, Dallman station subcontracts coal ash disposal at a local abandoned mine. The EPA uses a disposal cost assumption of $30-$50 per ton for wet FGD, dry FGD, and DSI controls, which the EPA developed in consultation with an experienced power sector engineering firm.

Short Time Frame Will Cause Electricity Rates to Rise

The EPA recognizes that this rule wi ll cause electricity prices to rise. The EPA projects that the increase in retail electricity prices that will result from th is regulation range from 2 to 3 cents per kWh in 2015 and will decrease in the ensuing years. On average, this is a 2.9 percent increase and is well below electricity prices seen historically and as recentlyas four or 5 years ago. The average increase over the base case declines over time.

Multiple Rulemakings Necessi tate 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 th ere are a number of regula tions 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 be en under development for the past few years. The confluence of these regulations allo ws the power industry to plan for compliance with information about the full suite of requirements that they will face. It reduces uncertainty and provides an opportunity for the power sector to develop integrated strategies for meeting EPA regulations allowing for a cost effective approach on the part of the companies that takes account of the multiple requirements. Many of these strategies will take advantage of the collateral effect of pollution control technologies. For example, actions taken to reduce emissions under the Cross-State Rule will help facilities achieve the acid gas and in many cases mercury standards in this rule.311 Smaller Plants Will Not be Able to Co mpete with Larger Plants for Controls

Some commenters said that smaller pl ants would have a harder time ge tting 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 therefor e they need a longer compliance tim e frame. Small plants are not necessarily at a disadvantage. The EP A notes that smaller plants can of ten control very cost effectively either because they simply need less equipment and la bor to retrofit and because they can often tie more than one small or midsize unit into one control devi ce. Shared APC systems will allow the overall effort to be more manageable than otherwise, and should require relatively fewe r supply chain resources.

Smaller Companies Will Not be Able to Co mpete 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 services to comply with this regulation. This comment pres umes that there is a shortage of equipment, labor and materials to apply to compliance with this regulation. As stated elsewhere we are in an economy that is characterized by high unemp loyment and chronic excess capacity. While this regulation will modestly spur demand it cannot reas onably be expected stimulate enough demand to cause shortages such that firms will have difficu lty obtaining the services they need to comply.

Comment 41: Multiple commenters offer suggestions on methods for allowing more time for compliance:

a. Authority under sectio n 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 se ction 112(i)(4): (18023, 16469, 16705, 16849, 17265, 17400, 17637, 17655, 17656, 17681, 17689, 17703, 17705, 17714, 17722, 17724 (5-year exemption), 17730, 17756, 17758, 17774, 17775, 17799, 17805 (5-year exemption), 17807, 17817, 17820, 17821, 17868, 17870, 17876 (5-year exemption), 17877, 17886, 17931, 18027, 18031, 18033, 18034, 18038, 18428, 18477, 18500, 18502, 18575)

d. Categorical extension for publicly-owned or governmental facilities according to EO 13132, 13563, and UMRA of 1995: (17868)

e. State-designed programs under the delegati on provisions of sec tion 112: (17719, 17873)

f. Delay Consent Decree: (17654, 17876, 17930)

g. Through Administrative Orders of Consent (AOCs): (17808, 17868, 17870)

h. Through Consent Decrees: (17648, 17808, 17870, 18448)

i. Temporary waiver mechanisms: (17055)312 j. Adoption of MACT compliance sc hedules through minor permit modifi cations of a source’s Title V federal operating permits: (17868, 18422)

k. Compliance extensions for units that reduce ea rly or install specified control equipment: (17265, 17638, 17681, 17807)

l. CAA section 112(i)(6): (17821; al though the commenter argues that it o ffers no meaningful relief to most sources)

m. Provide a future effective date for the rule. This approach would allow promulgation by the date mandated by the consent decree, and would assist st ates 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 allo w use of consent agreements. Commenter 17648 states that as a matter of law and long-standing admi nistrative practice, then, the requirements of the Toxics Rule will apply without abat ement to facilities subject to a c onsent arrangement, however, as a matter of policy, the EPA may wish to accommodat e certain consent arrangements that pre-date publication of the proposed Toxics Rule in case-specific circumstan ces. Commenter 17648 explains that most existing consent arrangements are directed to c ontrols on criteria pollutants which will ordinarily be insufficient to control HAP in a manner consiste nt with the rule. Commenter 17648 states that any accommodation would need to provide for the implement ation of HAP controls “a s soon as practicable” given existing commitments under the consent arrangeme nt. According to the commenters, for example, a consent arrangement that provides for installationduring 2015 of a FGD system that would adequately control acid gas HAP might be accommodated provide d 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 st ate permitting agencies to provide facilities subject to a consent arrangement with the same 1-year extension from th e 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. Accordin g 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 en ter into a “wrap-around” consent order or consent decree that would incorporate additi onal requirements necessary to co mply with the Toxics Rule beyond those required in the existing c onsent arrangement. The commenter st ates that this task must be approached on a case-by-case basis, with the judici ous use of the enforcement discretion by the EPA and state permitting agencies and that existing cons ent arrangements are unlikely to provide for the installation of emission controls sufficient to comply with the Toxics Rule. The commenter asserts that EGU operators who are parties to su ch arrangements will bear the bur den of deciding whether to seek additional relief, or to comply with the rule on time. The commenter states that some consent arrangements will be inadequate in scope or alacrity, or both, and will need to be supplemented either by a “wrap-around” consent order or decree, or by an am endment to the existing arrangement. According to the commenter, ultimately the same enforcement discre tion that formed the basis of the existing consent arrangements will be applied to determine if, a nd how, they must be modified, and the operating conditions that should be applied during the period of extension. The comme nter states that only in this313 way can the EPA and state permitting agencies conserve the benefits of these consent arrangements without sacrificing the overwhelming health and economic benefits that the Toxics Rule will provide.

Response to Comment 41 : The agency has provided the maximu m time authorized under CAA section 112(i)(3)(A), and the provisions cited by commenters do not alter our authority concerning the initial compliance time that may be provided in CAA section 112 standards. Furthermore, as the EPA stated in the preamble to the final rule, our analysis shows th at most plants can meet the standards within the 3- year timeframe. The EPA believes that although most un its will be able to fully comply within 3 years, the fourth year that permitting authorities are allowed to grant for installation of controls is an important flexibility that will addr ess 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-y ear extension under CAA sec tion 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) request a “blanket 1- year extension” of the compliance deadline.

On the other hand, multiple commenters (9738, 17265, 17402, 17648, 17701, 17758, 17808, 17810, 17852, 17887, 17973, 18025, 18027, 18438) ask that requests be granted only on a case-by-case basis.

Response to Comment 42: CAA section 112(i)(3)(B) provides that “[t]he Administrator (or a State with a program approved under subchapter V of this ch apter) may issue a permit that grants an extension permitting an existing source up to 1 additional year to comply with standard s under subsection (d) of this section if such additional period is necessary fo r the installation of contro ls.” This provision on its face applies to individual sources and, furthermore, the D.C. Circuit Court has determined that EPA does not have authority to provide a compliance period in excess of three. See NRDC v. EPA , 489 F.3d 1364, 1373-74 (D.C. Cir. 2007) (rejecting a one year extension for all so urces in the category after the Agency promulgated changes to reporting requireme nts issued after the final rule setting forth the emission standards). Some industry commenters have specif ically stated that they will be able to comply with the rule in the 3 year period and we believe that ther e are approximately 69 EGUs that appear to be currently complying with all of the existing source stan dards. We do not think it would be reasonable or consistent with the statute to provide a longer complian ce period for sources currently complying and sources that can in fact comply within 3 years. For sources that cannot comply in that time, the 1 year compliance extension is available and EPA has comm itted to working with sources to ensure that compliance with the final rule will not affect electric reliability.

Comment 43: Multiple commenters (16824, 17003, 17137, 17730, 18441) ask that compliance be delayed until additional studies or analyses are conducted.

Commenter 16824 asks that the EPA complete a cost-b enefit analysis (with fu rther peer review and additional opportunity for public comme nt) before implementing this rule.

Commenters 17137 and 17821 endorse an indefinite dela y until further study can be undertaken on the costs and impacts to industry, jobs, and consumers along with a dditional testing and evaluation. According to commenter 17137, the current deadline m eets 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 manpower needed to meet compliance deadlines for the Utility MACT and other pending regulations affecting coal-fired power generation.

Commenter 17003 asks that the EPA a llow 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 adversely impacting electric reliability. The commenter states that although the EPA’s analysis a ddresses overall system adequacy, the EPA has not analyzed system security under the rule.

Response to Comment 43 : The MATS was developed by the EPA after years of studies and data analysis that examined the nature and quantity of HAP emissions from power plants, the health and environmental effects of the pollution, the availabilityof pollution controls and other measures to reduce emissions of these pollutants, the costs and benefi ts of reducing HAP emissions from EGUs, and the effect of the rule on consumers and on jobs. What the EPA learned is that coal-fired and oil-fired power plants are very large emitters of these pollutants, that cost effective strategies to reduce these emissions are readily available, and that doing so, while expens ive would provide public he alth benefits valued at many times the cost, including avoiding premature deaths , more aggravated asthma and other respiratory problems, non-fatal heart attacks, missed work and school days In the process the rule has little impact on consumer prices and increases jobs moderately.

Although one can always argue for more studies, delayi ng this rule now for the purpose of more studies would delay significant health benefits to hundreds of thousands of Americans.

Comment 44: Commenter 17682 worries that the rule as proposed will severely harm the ability of the United States to produce reasonably pr iced power, diminish its international competitiveness, and result in minimal environmental improvements, and that it co uld even result in increased environmental risks from alternative energy sources, Th is commenter requested that the EPA withdraw the proposed rule. Commenter further asks that the EPA reissue a new rule only if it reflects the re sults of a credible costbenefit analysis and a full assessment of the imp acts of using potentially conflicting and relatively untested MACT technologies to achieve complia nce with the range of pollutant standards

Commenters 17003 and 17297 quote the EPA compliance costestimates of a $3-4 increase in consumer electricity costs and suggest that a longer complian ce timeline to develop and implement the least cost compliance strategy to ensure a reliable electric supply and minimal rate impacts.

Response to Comment 44: The impact of this rule on electricity and natural gas prices are within the range of normal variability and well be low levels seen only 2 or 3 years ago. It is not reasonable to take as a “given” that this rule will dimi nish international competitiveness. In fact the annual cost of the rule is less than 0.001 percent of GDP. It is unlikely to ha ve much impact on the competitiveness of the U.S.
economy.315 The benefits of the rule on the other hand, accordi ng to the EPA’s cost benefit study which is based on peer reviewed scientific literatur e and methodologies are far greater th an the costs, providing significant public health improvements to Americans. Furtherm ore this regulation can be complied with using tested control technologies that are in use on coal-fired plants today.

Comment 45: Multiple commenters (18023, 16850, 17402, 17403, 17623, 17648, 17655, 17686, 17705, 17736, 17757, 17758, 17800, 17805, 17840, 17873, 19114) offer opinions on the timelines for control equipment installation. Commenter 19114 provides a deta iled discussion of time frames for planning, permitting and construction of controls in their comments.

a. DSI:

(1) 9-18 months on average but up to 5 years recently (17758) (2) Two years (17402) (3) <12 months (17648)

b. ACI: Up to 2 years for optimization after installation (17402)

c. FGD:

(1) Up to 60 months (17758) (2) 40-69 months (18023) (3) 36-42 months (17402) (4) 40–60 months (17705) (5) 40-65 months (17403) (6) 52 months (17736, 19114) (7) 44-64 months (17800) (8) 66-72 months (17873) (9) 2-4 years (16850) (10) 40-65 months (17799) (11) 52 months (17821) (12) 50-63 months (17886)

d. FGD-associated landfill:

(1) 54 months on average (17736, 18428, 19114) (2) > 10 months (19114) (3) 3-5 years for permitting (17800)

e. Baghouse:

(1) 12-24 months (18421) (2) >36 months (18023, 19114) (3) >4 years for retrofit (17805)

f. SCR:

(1) 36 months (1837) (2) 3 1⁄2 years (17623, 18428)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 years (18023)

i. Changes in fuel supply to natural gas: 4 1⁄2 years (18023)

j. Changes to transmission grid:

(1) >3 years (18023) (2) up to 7 years (17886)

k. Fabric filter:

(1) 42 months (17736, 17821) (2) 5.5 years (17840) (3) >=36 months (17868)

l. DSI with baghouse: 50+ months (17886)

Commenter 17868 notes that the EP A’s assumption of faster retr ofits is probably incorrect.

Response to Comment 45: Numerous commenters submitted their own evaluation of the length of time required to install controls, switch fuels, and upgrade the grid, some of it based on their own experience from the past. Numerous commenters claimed that actual project execution timeframes exceeded the time allotted by the proposed rule. To illustrate th e point, some commenters referenced specific retrofit project elements with asserted time requirements for their completion as part of the retrofitting process.

The EPA does not agree with commen ters that lengthy retrof it schedules from various individual prior projects are dispositive of the power sector’s ability to install cost -effective retrofits under the MATS schedule. Project schedule lengthis heavily influenced by resour ce dedication and execution method. While any project can be executed at a slow pace, the EGU pollution c ontrols 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 considerable efficiency gains through integrating standardized equipment designs,317 systems approach, and modular cons truction techniques as well as the formation of business alliances1 to reduce frictional time lags.

A typical control retrofit projec t consists of the following elements, several of which may occur simultaneously: site studies, conc eptual engineering, equipment si zing, and cost estimating, planning, detailed design, procurement, construction, commi ssioning/testing, and permit application. For designbuild methodology, the project is di vided into two major phases: pr e-award work requiring minor expenditures (site studies, conceptu al engineering, equipment sizing, cost estimates, schedule planning) and award work requiring significant capital commitm ent (detailed design, procurement, construction, commissioning/testing).

Pre-award work elements are typically executed seque ntially since each precedi ng stage’s results inform the following stage; however, award work elemen ts can be executed with “Lean Construction” techniques to shorten time frames. Since a typical emission control device is a combination of, rail car unloading, waste water treatment, and dewatering facility occupy differe nt plant site lo cations; thereby, allowing simultaneous design, procurement, construction, and testing activities. To illustrate the point, Asheville Power station FGD retrofit was complete d on a 26 month schedule. Constellation’s FGD, fabric filter, and activated carbon re trofit was completed in 29 months from notice to proceed. Presque Isle’s 3-unit fabric retr ofit was completed in approximately 2 years.

The examples cited by commenters fail to account fo r the adoption of proven faster execution methods evidenced by numerous units that have demonstrat ed FGD retrofit project completion in less than 30 months. In particular, commenters who cite examples of lengthy or delayed retrofit schedules from projects conducted during the high ly uncertain period of the CAIR remand (when it was prudent to proceed cautiously) cannot reasonably expect such e xperiences to apply to retrofit project execution with the benefit of renewed regulatory certainty gain ed 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 quicklythan 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 syst ems. Springerville Unit 3, for example, is a 400 MW coal-fired unit that became operational in July 2 006, some 33 months after the turnkey engineeringconstruction contractor was given a notice to proceed with engineeri ng.5Springerville was clearly on an accelerated schedule, as its original planned schedule was about 38 months. The main point here is that typical schedules for large complex power projects can be significantly accelerated. Because the scope of the work involved for an entire new coal unit is atleast five times that of a retrofit wet FGD system, EPA believes that even the most complex retrofit APC project can be significantlyaccelerated as well.

The recently surveyed wet FGD project schedules ar e not all representative of the shorter project schedules that EPA expects to be prevalent under the MATS Rule. Some of these projects were conducted in a period of regulatory uncertainty w ithout a strong driver fo r accelerated retrofit completion, tie-in, and subsequent operation – partic ularly 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-shif t work schedules during construction, and 5- or 6-day work weeks, instead of the 4-day x10-hr schedules often used to minimize cost when time is not of the essence. Increased use of offsite modularization a nd pre-fabrication of APC components can also shorten schedules and reduce job hours. Also, many of the wet FGD projects performed in response to CAIR or to other legal ac tions in the same time frame took longer to perform than under normal market conditions due to the in itial high demand for a large number of complex wet318 FGD systems in a short period of time. Extended l ead times in the 2007/2008 time period, as high as 18 months for key wet FGD engineered equipment (s uch as large recycle pumps, large motors, and chimneys) contributed to extended wet FGD project dura tions. Increased lead times quickly subsided as the supply chain processed the initial influx of orde rs for this equipment. Neither the proposed Cross State Rule nor the MATS Rule, however, is projected to require a significant number of large, complex wet FGD systems. The relatively much simpler dry F GD, fabric filter, and other even simpler DSI and ACI systems that may be required under the Mercur y and Air Toxics rule will take significantly less time to plan, design, install, and commission than wet FGDs.

5. One-year extension.

Comment 46: The EPA requested comment on a 1-year extension under section 112(i)(3) for “installation of controls.” Mult iple 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 li mited cases of extensions beyond 3 y ears, it will be important for the EPA to ensure that a company uses the additional ti me to install controls or test the installation of controls and to ensure a unit is only dispatched fo r reliability purposes so th at 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 ot her 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 ex tension should apply if additi onal gas supply lines must be constructed or replaced, or if required state and federa l regulatory approvals to retire the capacity cannot be obtained.

Commenter 17385 asks for clarification of whether en ergy efficiency and fuel switching measures can count as “controls.”

Commenter 18434 stated that this ex tension should also apply to on-si te non-conventional replacement generation through combined heat and power and wast e heat recovery. According to the commenter, restricting replacement power to on- site equipment significantly reduces opportunities fo r facilities to invest in clean replacement power and consider retirement as a compliance strategy. The commenter states that this approach has multiple advantages.

Several commenters (18434, 18439, 19114) ask the EPA to clarify that retirement and any clean replacement power that complies w ith the NESHAP rule, including off-site combined heat and power and waste heat recovery, can be deemed “controls ” under the CAA, thereby allowing the same 1-year extension to apply. Commenter 18439 notes that the EP A should clarify that energy efficiency and fuel switching measures can count as controls for pur poses of eligibility for a 1-year extension for compliance if additional time is needed for inst allation. Commenter 19114 notes that the timeline for constructing a new combined cycle unit is similar to that for retrofitting an FGD system on an existing unit, and could not be completed within a 3-year window.

Several commenters (19536, 19537, 19538) believe that: S hut-down of an existing unit is within the definition of a pollution “contro l” under section 112, as well as under the CAA generally. The commenters state that section 112 uses “emission contro l” broadly to refer to pollution reductions of any319 sort(see, e.g., 42 U.S.C. §7412(d)(3), (d)(5), (d)(6), & h(1) (all usi ng “control” to refer to pollutionreduction and referring to “emission control” achieved by “best controlled similar source”)), that in keeping with that general synonymy, section 112 de fines “maximum achievabl e 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 c onfirms that any “measure,” “method” or “technique” that reduces hazardous air pollution may be prescribed to accomplish the necessary limitation(42 U.S.C. §7412(d)(2)). The commenters state that elsewhere in th e statute, as well, the term “control” is defined broadly enough to include the cessation of polluting operations. See , e.g., 42 U.S.C. §7479 (defining “best achievable control technology”). According to the commenters, closure of a high-polluting unit is a measure that reduces pollution, and is th erefore a “control” under the CAA. The commenters state that the EPA has, accordingly, recognized in its consent decrees that shut-down is under some circumstances a method of pollution-reduction that is a “control tec hnology” within the meaning of the CAA. See , e.g., Consent Decree, United States v. Tampa Electric Co. , Civ. No. 99-2524 (M.D. Fla. 204) at 7-8 (prescribing permanent shut-down amongst “emissions reductions and controls” required to comply with CAA). According to the commenter, consequently, the word“control” in section 112 encompasses the shutdown of a polluting unit, and “installation of contro ls” should be understood to include the on-site physical operations required to accomplish permanen t 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 in stallation of controls,” 42 U.S. C. §7412(i)(3)(B), while also establishing that controls are to be installed “as expeditiously as practicable,” 42 U.S.C. §7412(i)(3)(A). The commenter states that whether an extension is “necessary” for the installation of controls must be informed by whether those controls can “practicabl[y] ” be put in place at an earlier date. According to the commenter, read together, sect ions 112(i)(3)(A) & (B) allow an extension of up to 1 year to be granted on a case-by-case basis for f acilities at which controls cannot practicably be installed within 3 years. The commenter states thatthe EPA has, elsewhere in its proposed rulemaking, considered reliability to determine the pace at which controls can practicably be installed ( see 76 FR 25,054, 25,056 & nn. 177-178 (describing EPA’s efforts and intention to work with FERC, NERC, the Department of Energy, and regional transmission organizations on issues related to compliance and reliability, particularly in the event unit shutdowns occur in load-constrained areas)).

Commenter 18426 states that the ex tension, with the factors and c onditions for qualifying and applying for the extension, needs to be part of the rule. Th e commenter provided Michigan’s conditions for that state’s Hg rules.

Commenter 18034 requests clarification, as the commen ter is unaware of any precedent for such an interpretation of the CAA. The commenter states thatwhile the EPA’s attempt at flexibility through this interpretation is clear, the commen ter is unclear as how other parts of the proposed NESHAP rule should be interpreted and enforced given this new interpretation and poses th e 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 63.9 984(a) that a new or reconstructe d EGU must comply by the date of the final rule published in the Federal Register or upon restart of the EGU, wh ichever is later? Is this interpretation limited to just EGUs or may states appl y 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 states that the 1-y ear extension process seems to a pply only to the installation of control equipment and not for installation of sy stems such as CEMS and BLDS. The commenter recommends that the EPA provide an extension process for procurem ent of emission monitoring/BLDS as well as for installation of control equipment and streamline the exte nsion process such that a source can be granted an extension if good faith effo rts have been made to meet compliance.

Commenter 17868 outlines the EPA prediction that the i ndustry will have very little problem in meeting the 3-year compliance schedule propos ed in the regulation if the additional year of compliance time is provided to “some” units. The commenter provides thei r key assumptions supporting this conclusion as:

1. The use of low-cost, simple, DSI systems to c ontrol acid gases, instead of more complex FGD systems; 2. Faster retrofits than similar projects in the past; 3. Compliance requirements of other regula tions have no impact on HAP compliance; 4. The small number of projected retire ments, about 10 GW of coal capacity; 5. Early planning action by re gulated utilities; and 6. Early planning action by RTOs.

Comment 47: Multiple commenters (16850, 17004, 17026, 17887, 18539) comment on retiring or repowering units.

Commenters 17004 and 17026 request that the EPA allow power companies to oper ate their plants as efficiently as possible, including al lowing units that are already schedul ed to shut down to operate on a restricted basis without installing additional controls , as they upgrade their faci lities and move toward new generation.

Commenters 18434 and 18439 ask the EPA to clarify th at retirement and any clean replacement power that complies with the NESHAP rule, including o ff-site combined heat and power and waste heat recovery, can be deemed “controls” under the CAA.

6. Extensions for retirement and replacement power.

Comment 48: Several commenters (18023, 17638, 17696, 17820, 17821) ask that the provision to allow a 1-year extension apply to all retirements.

Multiple commenters (17841, 18426, 18434, 18441, 18442 18448) ask that a 1-year extension be provided for possible unit retirements, retrofit s, or repowering. Se veral commenters (18434, 18441, 19114) note that this extension shoul d apply to off-site power gene ration in limited circumstances. Commenters 18031 and 18442 ask that the maximum amoun t of time allowable be available for these actions.

Commenter 17677 states that for units that elec t 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 constr uct a replacement facility or contract additional power that will most likely have to be constructed.

Commenter 19506 states that the EPA should consider allowing units that a company has scheduled to be shut down to continue to operate beyond the co mpliance deadline until other units owned by the same company have been fully retrofitted.321 Commenter 18450 opposes allowing a fourth year fo r compliance when building replacement power unless the source can demonstrate an electric reliability issue.

Commenter 18039 objects to granting 1-year extensions for facilities that are building replacement power. According to the commenter, the EPA should a void allowing a facility in the process of building replacement power, and that would otherwise shut down an existing high-emitting unit at the 3-year compliance deadline, to operate such existing high-emitting unit for an additional year, specifically due to the 1-year extension. The commenter states that in addition, if designing, permitting and constructing replacement power continues beyond a 1-year extens ion, it should be stressed that the CAA does not allow MACT compliance extension beyond 1-year, whether or not a replacement unit has come on-line.

Commenter 18441 notes that the 1-ye ar extension request, if gran ted, may create incentives for generation owners faced with compliance decision s to wait as long as pos sible to submit their deactivation requests to their regiona l transmission organization in the hope they can get their units extended beyond the January 1, 2015 compliance deadlin e if their units are deemed by the regional transmission organization in its subs equent deactivation study to be Re liability Critical Units. According to the commenter, in this case, gene rator owners can effectively attemp t to extend the life of their units for an additional year or more with no intenti on of installing retrofits by simply delaying their deactivation request so they can effectively side-s tep compliance with the final rule through a potential misuse of the extension process contemplated herein. The commenter requests the EPA provide guidance in the final rule that suchan extension for deactivating units only be granted if the unit owners provide the regional transmission organization, with a copy to the EPA, with notice of deactivation by the earlier of 12 months from the effective date of the final rule, or January 1, 2013, a full 2 years in advance of the January 1, 2015 compliance deadline. Th e commenter notes that nothing in this proposal should be read as limiting the ability of units whic h are retrofitting but cannot complete such work by the compliance deadline from also being eligible fo r a compliance extension. Th e commenter states that nothing in this proposal eliminates a generating owner from petiti oning the Secretary of Energy to excise its authority under section 20 2(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 precl ude a generator from working with the EPA to establish a compliance schedule.

Response to Comments 46 - 48 : The EPA believes that although most un its will be able to fully comply within 3 years, the fourth year that permitting authori ties are allowed to grant for installation of controls is an important flexibility that will address situations where an extra year is necessary. That fourth year should be broadly available where it is necessary. Please refer to the pr eamble where there is a detailed discussion of the fourth year. The EPA is making it cl ear that permitting authorities have the authority to grant a 1-year compliance ex tension 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 th at making it clear that permitting authorities have the authority to grant a 1-year compliance extension where necessary, in range of situations described in the preamble, addresses many of the other c oncerns that commenters have raised.

7. Issues and costs that need to be co nsidered in determining compliance date.

Comment 49: Multiple commenters (16469, 16849, 17403, 17406, 17640, 17722, 17730, 17732, 17734, 17752, 17756, 17757, 17758, 17770, 17774, 17812, 17813, 17815, 17817, 17820, 17821, and 17868, 17876, 17881, 17912, 17925, 17931, 18033, 18037, 18422, 18424, 18428, 18440, 18442, 18447, 18498,322 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 betweensmall utilities and larger utilities, for equipment and labor.

Commenter 18433 states that it will be difficult for facilities in re mote areas to get vendors and contractors to respond to requests-for-proposals for a single opportunity to sell an ESP when large utilities will also be seeki ng larger quantities of such equipment from the same vendors.

Commenters 19032 and 19653 believe that too many activ ities must be coordinated and completed to comply with the proposed rule. The commenter states that these activities incl ude emissions testing to determine what type of capital equipment or upgrad es 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 majo r tie-in outages, especially during low peak seasons.

Commenter 18477 does not have shoulder months like the contiguous U.S. Therefore, according to the commenter, there are no specific tim e periods when outages can occu r without impacting electric reliability.

Response to Comments 49 - 50: In both the preamble to the rule and in greater detail in the TSD, the EPA has assessed the feasibility of installing these contro ls within the complia nce window and believes that the controls can be reasonabl y installed within that time. Although the EPA a ssessed the ability to install the controls in 3 years (and determined that the controls could be inst alled in that time-frame), this would require the control tech nology industry to ramp up quickly. Therefore, the EPA also assessed a time-frame that would allow some installations to take up to 4 years. This time-frame is consistent with the CAA which allows permitting authorities the discretion to grant extensions to the compliance time-line of up to 1 year. This time-frame also allows for staggered installation of controls at facilities that need to install technologies on multiple units. Staggered installation allows companies to address such issues as scheduling outages at different units so that reliable power can be provided during these outage periods or particularly complex retrofits (e.g., wh en controls for one unit ne ed to be located in an open area needed to construct controls on another unit) . In other words, the a dditional 1-year extension would provide an additional two sh oulder periods to schedule outag es. 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 thyear that permitting authorities are allowed to grant for installation of controls is an important fl exibility that will address situations where an extra year is necessary. The EPA expects that state permitti ng authorities will make the fourth year available where it is warranted. In addition where necessary to avoid a viola tion of applicable FERC-approved electric reliability standards the EP A can use existing CAA authorities to allow additional time to come into compliance.

Comment 51: Multiple commenters (8443, 17123, 17297, 17406, 17623, 17716, 17732, 17756, 17716, 17752, 17758, 17820, 17842, 17912, 18024, 18419, 18422, 18440, 18502, 19121) are concerned about financing these projects and the like ly cost increases for labor and e quipment 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 aff ect the affordability of electricity.

Response to Comment 51: The EPA has not observed financing obst acles for pollution control retrofits under its previous programs. The EPA includes publicly-reviewed fi nancial assumptions regarding pollution control investments with its IPM modeling of the power sect or. Furthermore, the financial industry views utilities w ith large customer bases (e.g., AEP, Duke, Edison Intl., Southern Co., TVA) as less risky to finance due to the cons istent, ample revenue stream. To re duce financing risk, utilities have the option to award “fixed price” contracts with pe nalties for exceeding price lim its 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 retrof it under the final MATS.

Although costs could increase during the compliance period, the EPA anticipates the first wave of retrofit controls orders to be le ss costly than recent historical pri ces since suppliers shall compete for work to utilize idle resources. For example, in June 2011 NIPSCO awarded B&W a contract worth $54 million for two wet scrubbers at R.M. Schahfer Gene rating Station with an operational date of autumn 2013 and 2015 for units #14 (465 MW) and #15 (515 MW), respectively. In another example, Colorado Springs Utility plans to retrof it its 254 MW Martin Drake unit with a FGD for $113 million with projected construction completed by 2014. The EPA exp ects therefore that the costs it has used in its IPM modeling will be accurate over the life of th e compliance period. Documentation for IPM can be found in the docket for this rulemaking or athttp://www.epa.gov/airmarkets/progsregs/epaipm/index.html or at http://www.epa.gov/ai rmarkets/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 larg er regional adequacy impacts ca n only be determined once the impact of the final rule has been analyzed and units have made their individual retrofit vs. retirement decisions. The commenter believes that the EP A understates the number a nd size of retirements.

Comment 53: Many commenters (16549, 17055, 17701, 17137, 17697, 17716, 17724, 17725, 17743, 17745, 17757, 17761, 17774, 17775, 17813, 17791, 18038, 18437, 18433, 17887, 17930, 18448, 18540, 19506, 19199) express concern that the EGU MACT will jeop ardize the reliability of the U.S. electricity supply by reducing generating capacity through early retirement of EGUs.

Numerous commenters (16549, 17055, 17701, 17137, 17697, 17716, 17724, 17725, 17743, 17745, 17757, 17761, 17774, 17775, 17813, 17791, 18038, 18437, 18433, 17887, 17930, 18448, 18540, 19506, 19199) express concern that the EGU MACT will jeopardize the reliability of the U.S. electricity supply by reducing generating capacity through early retirement of EGUs. Some co mmenters (18034, 18538, 18907) believe that the EGU MACT may result in rolling blackouts that have economic impacts. Commenter 18034 notes that without reliable, affordable electricit y, sensitive populations, such as elderly citizens, may be at risk during severe winter weather or hot summer temperatures.

Some commenters offer comme nts about processes based on early notif ication that might be set up to assure that the compliance timeframe did not inte rfere with electricity reliability. Commentor 17648 suggests that the EPA be notified within 1 year of th e 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 ISOs of their pl ants to retire units so that th e RTO/ISO can assess the impact on reliability of the planned closure. In the event that a unit is deemed “reliabi lity 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 54: Commenter 18023 believes the loss of genera tion capacity caused by early retirement of EGUs would undermine the operational support that is cr itical to maintaining ba lance, resilience, and contingency response capability on the bulk power network. The commenter believes the EPA has overlooked the critical role generation capacity plays in providing grid stability.

Comment 55: Numerous commenters (16705, 17055, 17254, 17400, 17403, 17608, 17627, 17761, 17765, 17804, 17813, 17857, 17901, 17911, 17813, 17901, 17904, 17911, 17919, 17930, 18034, 18038, 18437, 18441, 18497, 18500, 18538, 18575, 18023) believe that the EPA has underestimated the number of EGU retirements. Ma ny commenters (16705, 17055, 17403, 17761, 17765, 17627, 17761, 17813, 17901, 17911, 17813, 17901, 17904, 17911, 17919, 17930, 18034, 18038, 18437, 18441, 18497, 18500, 18538, 18575, 18023) cite independent projections thatestimate capacity retirements will be much higher than the EPA’s estimate. The indepe ndent projections cited by commenters include:

 Potential Coal Plant Retirements Unde r Emerging Environmental Regulations , The Brattle Group, December 8, 2010 (estimate 67 GW will be re tired as a result of the EGU MACT);

 Potential Impacts of Environmental Regulation on the U.S. Generation Fleet , Edison Electric Institute, prepared by ICF International, January 2011 (estimate 50to 70 GW will be retired as a result of the EGU MACT in conjuncti on with other new EPA regulations).

 Review of the Potential Impacts of Proposed Environmental Regulations on the ERCOT System

, Electric Reliability C ouncil of Texas, May 11, 2011 (predi cts that by 2016, the base case scenario will lead to 11 GW of retirements inthe state of Texas to all forms of generating capacity, leaving only a - 2.3% reserve margin);

 US Department of Energy (Deputy Assistan t Secretary, James Wood) (suggested that the approval of new rules for air po llution, water pollution and waste di sposal 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 l ead to pronounced transmission grid reliability issues “...both because of the shutdowns and because of the intermittency of renewables.”).

 Ira Shavel & Barclay Gibbs, Charles River Associates, “A Reliability Assessment of EPA’s Proposed Transport Rule and Forthcoming U tility MACT” (Dec. 16, 2010)(estimate 39 GW will be lost through early retirement).

 2010 Special Reliability Scenario Assessment: Resource Adequacy Impacts of Potential U.S. Environmental Regulations , North American Electric Reli ability Corporation, October 2010 (Estimate that 78 GW from coal, oil, and gas E GUs will be lost through early retirement over the next 10 years).

 U.S.Utilities: Coal-Fired Genera tion Is Squeezed in the Vice of EPA Regulation; Who Wins and Who Loses? , Bernstein Research, October 2010. (estimate that close to 60 GW of coal fueled capacity will find it “uneconomic” to install MA CT and will shut down. Also predicts that capacity margins would decrease by 7 to 15 % and reliability is forecasted to go down).

 NERA Economic Consulting, May 2011 (estimates 48 GW of additional coal-fired generating capacity will retire prematurely by 2016).

 PIRA (states that over 160 GW of coal units do no t currently have scrubber s installed. Of these, about 55 GW have announced plans for scrubber re trofits, leaving a pote ntially 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-bas ed generation capacity will be lost as a result of the EPA’s regulations;

 Commenter 17757 estimates that 5 coal-fired plan ts (6,000 MW) will be shut down as a result of the EGU MACT.

 Commenter 17821 plans to retire 6 units, or 1,125M Ws of coal fired capacity at the W.C. Beckjord Station by January 1, 2015, prin cipally 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, includi ng the EGU MACT rule.

Comment 56: Commenters 17919 and 18033 refer to statements made by FERC that acknowledge FERC’s preliminary assessment on the impact of EPA rules on coal-fired generating capacity “showed 40 GW of coal-fired genera ting capacity ‘likely’ to retire, with an other 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 inwhich 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 re liability standards. Co mmenter 18033 claims that the EPA has failed to document its discussions w ith FERC on the impacts of the EGU MACT on electric system reliability. This commenter believes it is in appropriate for the EPA not to include a record of those discussions in the rulemaki ng docket and that by not doing so the EPA has not adhered to the statutory requirements of the CAA, which requires the EPA to provide the public with an opportunity to review and comment on these documents.

Commenter 18033 states that the EPA also attempts to fall-back on early collaboration with key stakeholders to prevent the potential for skyrocketing electricity prices and job losses. According to the commenter, the agency states that, “[i]n addition, EPA itself has already begun reaching out to key stakeholders including not only sources with dire ct compliance obligations , but also groups with responsibility to assure an affordable and reliable supply of electricity incl uding state Public Utility Commissions (PUC), Regional Transmission Organiza tions (RTOs), the National Electric Reliability Council (NERC), the Federal Energy Regulatory Commission (FERC), and DOE.” The EPA further states, “[i]t is EPA’s understanding that FERC and DOE will work with entities to ensure an affordable, reliable supply of electricity...” Th e commenter states that it can fi nd 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 optimis tic DSI assumption thereby co loring 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 sc hedules for the air and solid waste regulations, along with the required compliance for rule 316(b) fo llowing shortly thereaft er, 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 co nstruction increase could cau se potential bottlenecks and delays in engineering, permitting and construc tion. The commenter assert s that based on this assessment, either NERC has changed its position si nce this time to align with the EPA based on information not included in the rulemaking docket, or the EPA is not being forthcoming about the reality326 of these “collaborations” to deal wi th this important issue. The comment er states that in any event, and unsurprisingly, the foregoing demonstr ates that FERC – responsible for de livering reliable electricity to the country – is not as confident in the EPA’s assessment of the situatio n as the EPA portrays it to be.

Following FERC’s responses to Senator Murkowski, th e commenter joins the Senator’s extreme concern with the impending situation, as de scribed in her August 3 press re lease, “[h]aving received FERC’s responses this week, I must say thatI am now less confident [after initi ally hearing the Chairman’s plans for an interagency task force] of that being the case.” The commenter states that preliminary review of FERC’s responses completely validates her position.

The commenter states that in response to the EP A’s exaggerated representations in the preamble, Chairman Wellinghoff stated in his letter, “...this information assessment offered only a preliminary look at how coal-fired generating units c ould be impacted by EPA rules, and is inadequate to use as a basis for decision-making, given that it used information and assumptions that have changed” (emphasis added). The commenter states that this sentimen t is further confirmed in Commissioner Moeller’s response, “[a]ccording to OER staff, EPA’s reliability analysis has been limited ,” and that staff have, “pointed out to EPA that a reliability analysis sh ould explore transmission flows on the grid, reactive power deficiencies related to clos ures, loss of frequency response, bl ack start capability, local area constraints, and transmission delivery” (emphasis a dded). According to the commenter, in sum, the EPA’s “trust us” mentality has far underestimated th e complexity underlying the delivery of affordable and reliable electricity.

The commenter states that this is further eviden ced by the fact that neither FERC nor the EPA has conducted a cumulative impacts analysis and that FE RC’s assessment that 81 GW of “likely or very likely” retirements may result from the implementation of this suite of rules, further highlights the need - - as expressed by the commenter – for a more transpar ent and open process to de al with these important issues. The commenter states that recognizing the Chairman’s reservat ions 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 regard ing the EPA-FERC consultation process.

The commenter joins Commissioner Moeller’s recomme ndations to have FERC: (1) use its expertise to perform an analysis of the EPA’s rules that could impact reliabilityof electricity – and disclose that analysis for public comment – and then hold a technical conferen ce for public input; and (2) have the EPA extend the timing of these regulations as the ag ency’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 understate ment of potential coal-fired EGU re tirements and electricity prices will be especially acute if the EPA holds the line with its new source emissions limits. The commenter states its belief that the new source emissions standards are based on the impermissible HAP-by-HAP approach, which makes it difficult to foresee investment in new coal. According to the commenter, Credit Suisse projects that at a 60 GW retirement fi gure, there would need to be an additional 24 GW just to maintain reserve margins at 15% begging th e important question of where will coal-dependent regions of the county replace these important sources of energy. The commenter states that despite the EPA’s effort to “level the playing field,” the agency has done an inad equate 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 documen ts regarding this particular issu e. The commenter asserts that the public is entitled to an opportunity to in spect these documents and provide comment.327 The commenter states that the failure to provi de evidence of the communication between FERC and other key stakeholders regarding th e electric reliability issue is inexcusable and that the EPA cannot claim it has adhered to the statutor y requirements of the CAA without installing all reco rds related to these consultations and permitting the public an opport unity to meaningfully comment. The commenter asserts that given FERC’s reservations about the EPA’s portrayal of the situation, there is a glaring need for more serious collaboration on this issue with anopportunity for public partic ipation and that the EPA must not sacrifice electric affordability and reliability at the feet of an arb itrary regulatory calendar.

According to the commenter, these ar e errors that are directly at odds with the rulemaking requirements under section 307(d). The commenter states that under paragraph (d)(3), a “notice of proposed rulemaking...shall be accompanied by a statement of its basis and purpose,” and this statement “shall include a summary” of the “factual data on which the proposed rule is based;” and the “methodology used in obtaining the data and in analyzing the data,” and that paragraph (d)(3) instructs that “[a]ll data, information, and documents referred to in this paragr aph shall be included in the docket on the date of publication of the proposed rule.” According to the commenter, the EPA has not followed these statutory commands as the requireme nt to provide “all data” on whic h the proposal was based was not included in the preamble nor in the docket at th e time the proposal was p ublished in the Federal Register

.

The commenter states that the D.C. Circuit Cour t of Appeals has held th at 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 a ffected parties, (3) to give affected parties an opportunity to develop evidence in th e record to support thei r objections to the rule and thereby enhance the quality of judicial review.” According to the commenter, these objectives have been undermined in this rulemaking process, and there ar e 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-spec ific compliance options” and that the Court’s holding highlights the issue of whether EPA’s unreasonable timeframe will effectively prevent the agency from being responsive to public comments.

Comment 57: Commenter 19114 believes that the EPA has not taken into c onsideration the impact of upsets or variations in operation, process or fuel sp ecification could have on re liability. 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 EP A more thoroughly examine the impact of process upsets on reliability of the electric supply.

Comment 58: Several commenters (17813, 17911, 17930) ar e concerned that the EPA has underestimated the impact of rising demand on electri c system reliability. Co mmenter 17813 argues that even without the EGU MACT retirements, the Texas E RCOT grid will struggle to meet rising electricity demand. They note that Texas is gr owing at a rate of 1,000 people a day, and that ERCOT anticipates capacity shortfalls of at least 7,000 MW in 2015, 18,245 MW in 2020, and 50,000 MW in 2030 to maintain a reserve margin of 13.75%. Commenters 17911 and 17930 note that the current electric power market has significant excess capacity that is the re sult of power consumpti on cutbacks caused by a stalled economy. If industry were to return to pre-2008 levels, they ar gue the market availability and market demand would be more closely aligned, and even the EPA’s estimated 9 GW retirement may have an impact.328 Comment 59: Several commenters (17627, 18037, 18441) note thatthe EGU MACT has already had an impact on coal-fired electricity generation. They not e 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 antici pated 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 likel y to be retired and that they expect a much higher percentage of coal capac ity 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 becau se the agency has failed to fully account for the potential effects of other relate d, ongoing and or upcoming regulatory initiatives affecting the electric generation sector, including more stringent NAAQS, upcoming emi ssion guidelines for GHG emissions (under NSPS as well as related PSD guidance), co al combustion residue (CCR) regulations, and regulations under section 316( b) of the Clean Water Act (CWA) fo r cooling water intake structures. Commenter 8843 worries that the “enormous” investment s required to comply w ill lead to reliability issues by closing down anywhere from 30-50% of coal-fired power plants. Commenter 17055 worries that the EPA has not considered the impact of the RICE regulations that could pot ential result in the loss of the small generators upon which many municipalities rely . They note that elimination of those units could create local supply challenges.

Comment 61: Commenter 17725 argues that more time is needto comply with the rule because the utilities that participate in the PJM and ISO-NE auctions have already made commitments to supply power through May 31, 2015. They furthe r note that the last date to s ubmit a delist bid for ISO-NE for PY 2015/2016 will have passed before the final EGU MACT is published.

Comment 62: Several commenters (17774, 17919, 18441) disagree with the EPA’s statements that reliability challenges related to early EGU retirements can be managed. Commenter 18441 believes the RTO/ISO notification procedures are not adequate to meet the magnitude of changes and potential retirements that could result from implementation of the proposed rule. Commenter 17774 states that South Carolina does not have an RTO or ISO to a ssist in planning. This co mmenter 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 shut downs of coal plants in the southeastern U.S. Commenter 17919 believes that the i ndustry cannot rely on EPA emergenc y 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 th at the EPA has not yet consulted with DOE and FERC and worries that the necessary rule co ordination or harmoniza tion is not occurring.

Response to Comments 52 - 62: The EPA has considered the concerns raised by commenters and has concluded that given the flexibilitie s provided in the final rule, the re quirements of the final rule for existing sources can be met by most sources without adversely impacting electric reliability. In particular, the EPA believes that the flexibility of permitting authorities to allow a fourth year for compliance should be available in a broad range of situat ions (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, lo calized concern were to emerge that c ould not be addressed solely through the 1-year extension under CAA section 112(i)(3), the C AA 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 resource adequacy. In considering these impacts, the EPA consid ered both the analysis it has conducted as well as analyses conducted by a number of other groups. The EPA’s anal ysis 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. B ecause concerns have been raised that the use of DSI may not be as prevalent as the agency has pred icted and because this could lead to more coal retirements, the agency also performed a sensitiv ity analysis in which le ss DSI systems and more scrubber systems were installed. In that sensitivity, we see approxima tely 1 more GW of retirement. This small change would have only a very small pot ential impact on reliability. When considering the impact that one specific action ha s on power plant retirements, it is important to understand that the economics that drive retirements are based on mu ltiple factors including: expected demand for electricity, the cost of alternativ e generation, and the cost of contin uing to generate using an existing unit. e EPA’s assessment looked at the capacity re serve margins in each of 32 sub-regions in the continental U.S. Demand forecasts used were ba sed on EIA projected demand growth. The analysis shows that with the addition of very little new cap acity, average reserve margins are significantly higher than required. The NERC assumes a default reserve margin of 15 pe rcent while the average capacity margin seen after implementation of the policy is n early 25 percent. Although su ch an analysis does not address the potential for more locali zed reliability concerns associated with transmission constraints or the provision of location-specific anc illary services (such as voltage s upport and black start service), the number of retirements projected suggests that the ma gnitude of any local reliability concerns should be manageable with existin g tools and processes.

Several outside analyses have reached conclusion s consistent with EPA’ s analysis. The DOE, in December 2011, published a report that looked at re source adequacy in the bulk power system when faced with a stress test which was a regulatory sc enario 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 sy stem and a fabric filter to redu ce air toxics emissions. If such installations are not economically justified, this scen ario assumes that the plan t must retire by 2015. In reality, as discussed previously, power plant owne rs will have multiple other technology options to comply with the regulations – options that typicall y cost less than installati ons of FGDs and fabric filters. The analysis finds that target reserve ma rgins can be met in all regions, even under these stringent assumptions. Moreover, inevery region but one (TRE), no a dditional new capacity is needed. In TRE, the analysis finds that less than 1 GW of new natural gas capacity w ould be needed by 2015 beyond the additions already projected to occur in the Reference Case. This analysis also finds that the total amount of new capacity that would be added by 2015 is less than the amount that is already under development.

In August 2011, PJM Interc onnection – the Regional Transmission Operator (RTO) responsible for planning and reliable operation of th e bulk power system serving all or po rtions of 13 states in the MidAtlantic and Midwestern regions - issued a report analyzing the imp acts of the CSAPR and the proposed MATS rule. 11 Although PJM’s analysis assumes substantiall y more retirements than EPA projects, it nevertheless concludes that resource adequacy is not threatened in th e PJM region. This is particularly significant, given that the PJM regi on is one of the largest and most heavily dependent on coal-fueled

10 U.S. Department of Energy, December 2011, “Resour ce Adequacy Implications of Forthcoming EPA Air Quality Regulations”.
11 PJM Interconnection, August 26, 2011, “C oal Capacity at Risk for Re tirement 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 regi onal basis, localized re liability issues may emerge in connection with retirements that may need to be addressed.

In June 2011, the Bipartisan Policy Center issued a report analyzing potentia l collective impacts of EPA’s pending power sector ru les and concluding that “scenarios in which electric system reliability is broadly affected are unlikely to occur.” 12

The EPA has reviewed industry and NERC studies s uggesting, contrary to the EPA’s and these other groups’ analyses, that EPA rules affecting the power s ector (including this fina l rule, the CSAPR, EPA’s proposed rule addressing power pl ant cooling water intake systems under section 316(b) of the Clean Water Act (CWA), and EPA’s proposed rule addressi ng 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 adve rse effects on electric reliability in some regions of the country. Although the specifics of these analyses di ffer, in general they share a number of serious flaws in common that call thei r 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 re tirements projected by several of thes e studies is attributable to their inaccurate assumption that EPA’s c ooling water intake rule under CWA section 316(b) would require all or virtually all existing pow er plants to install cooling towers. In one study, the reliability effects reported are based on inaccurate assumptions that all existing EGUs witha capacity utilization factor of less than 35 percent would cl ose, and that all in-scope electric ge nerators would be required to install cooling towers within 5 years, whereas the not-sel ected options with closed cycle cooling in EPA’s proposal envisioned that permit authorities could exer cise discretion to allow facilities 10 to 15 years’ time to comply. In most cases, these analyses were performed before the CWA s ection 316(b) rule or the MATS rule were even proposed; even analyses subsequent to the CWA section 316(b) proposal continue to inaccurately portray EPA’s proposed approach.

Second, in reporting the number of retirements, ma ny analyses fail to differentiate between plant retirements attributable to the EPA rules and older, smaller, and less efficient plants that are already scheduled for retirement because owners have made business decisions, based in significant part on market conditions, not to continue operating them.

Third, most of these analyses fail to account for the broad range of respons es available to address electric reliability concerns a ssociated with power plant retir ements, including upgrades to the transmission system, construction of new genera tion, and implementation of demand-side measures. These measures are discussed at greater length below.

As a preliminary matter, none of these situations, eith er alone or in combinati on, will necessarily lead to an electric reliability problem. Ther e is excess generating capacity in the U.S. today and in most cases an EGU that closes, either temporarily until it comes into compliance or permanently, will not cause a reliability problem. As explained ab ove, our modeling of the impact of this final rule at the regional level projects retirements of less than one percent of nationwide generating cap acity and confirms that there will continue to be adequate capacity in all 32 subreg ions of the country as sources comply with

12 Bipartisan Policy Center, June 2011, “Environmen tal Regulation and Electric System Reliability”.331 the rule. 13 This analysis shows that significantly less capac ity will close in response to the final rule than might have under the proposal. Moreover, the regional m odeling of retirements demo nstrates that plants that close in response to this rule are spread out across the country ra ther than clustered in one area. Outside analyses have identified many of the same fl aws in studies projecting large-scale retirements as a result of EPA’s power sector rules. For exam ple, On August 8, 2011, the Congressional Research Service (CRS). 14 issued a report that report that concluded th at studies that assertthat 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 mylower 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 63: Numerous commenters (17402, 17403, 17689, 17697, 17705, 17730, 17734, 17736, 17757, 17758, 17761, 17770, 17800, 17808, 17813, 17815, 17817, 17820, 17821, 17868, 17877, 17881, 17925, 17931, 18016, 18021, 18024, 18033, 18424, 18430, 18433, 18442, 18447, 18498, 1850, 18502, 19032, 19114, 19121) note that there are like ly to be delays due to pe rmitting, which will likely increase due to the volume of utilities complying with this rule.

Multiple commenters (17689, 17821, 17868, 17877, 17881, 18024, 18442) specifically reference the NSR process.

Multiple commenters (17730, 17736, 17758, 17808, 17820, 17821, 18024, 18037, 18428, 18447, 19114) specifically reference the PSD process.

Multiple commenters (17402, 17757, 17736, 17800, 17820, 17821, 18428, and 18502) are concerned with the extra delay that FGD landf ill permitting and building could cause.

Commenters 17821 and 18428 are specifically concer ned with GHG permitting and an associated BACT determination.

Commenter 18424 is concerned that util ities must have rate-payer fina nced capital investments approved by state regulatory bodies, which can e xpand the compliance time by many months.

Commenter 17813 is concerned about pre-permit appr oval evidentiary hearings required in Texas, which typically exceed 2 years in duration.

Commenter 18031 notes that Minnesotautilities must comply with the Minnesota Mercury Emission Reduction Act of 2006 (“MERA”), which requires revi ew by the Minnesota Pollution Control Agency.

13 See Technical Support Document on Resource Adequacy in this Docket.
14 James E. McCarthy and Claudia Copeland, Congressi onal Research Service, August 8, 2011, “EPA’s Regulation of Coal-Fired Power: Is a ‘Train Wreck’ Coming?”.
15 Bipartisan Policy Center, June 2011, “Environmen tal Regulation and Electric System Reliability”.
16 M.J. Bradley & Associates and Analysis Gr oup, June 2011, “Ensuring a Cl ean, Modern, Electric Generating Fleet while Maintainin g 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 stat e regulations require obtaining public utility commission approval in the form of a certificate of need.

Commenter 18450 asks that the EPA establish an expe dited permitting process for those affected units that require permit amendments to install HAP controls.

Response to Comment 63:

Permitting Process under the Clea n Air Act can cause Delays

Some commenters thought th at EPA permitting could cause delays in implementing this rule. The EPA recognizes that, following the vacatur of the ne w 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 pr ojects constructed to comply with this rule, have the potential to trigger NSR permitting. Based on an analysis done in 2005 th at looked at SCR and FGD for CAIR compliance, but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR requirements would not significantly impact the constr uction of pollution controls that are installed to comply with this Rule. In addition it is very un likely that pollution contro l projects would cause GHG increases that would exceed the 75,000 tons per year threshold either as a result of either chemically manufacturing GHGs or as a result of parasitic load. The EPA concludes therefor e that there will be no significant impacts on timing from NS R for any pollution control projec ts resulting from this rule. Should NSR be triggered it would at mo st be for just a few of the proj ected control installations.. In the limited circumstances where pollution control installa tions under the Mercury and Air Toxics Standards may trigger NSR, we also note that an expedited permitting process can occur with sufficient time to obtain permits and achieve emission reductions. For this reason, we strongly encourage permitting

State Requirements Can Cause Delays

Some commenters said thatstates may have laws and other requirements that will cause companies to delay implementation of this rule. Some compan ies may construct replacement generation as a compliance strategy. State pre-construction permitti ng requirements depend upon each individual state. Some states do not requir e pre-construction permits while some others require public utility commission (PUC) approval. For states obtaining PUC pre-appr oval for cost recovery, authorization typically averages seven months and is obtained usually within one year. 17 Furthermore, while PUC approval is necessary to recover investment costs through rate paye rs, 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 r easonable effort to implement this regulation within the compliance time frame. The EPA continues to be lieve, based on the analysis discussed at the beginning of this section, that most, if not all, units will be able to comply withthe requirements of this rule within 3 years. The EPA also believes that making it clear that permitting authorities have the authority to grant a 1-year compliance extension wher e necessary, in the range of situations described elsewhere in this document, addr esses 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 Shor t to Construct and Permit an FGD Landfill

As we have said elsewhere in this document, the compliance deadline allows sufficient time for completing landfills for FGD solids disposal. For ex ample, DP&L will construct a landfill within 18 months to accept wastes generated from Stuart and Killen stations scrubbers. The EPA notes, however, that retrofitting units do not neces sarily need to complete landf ill construction ahead of commencing operation of the retrofit to achie ve cost-effective emission reduc tions under the Transport Rule programs. Such a source may either utilize a co mpleted portion of the newly permitted landfill under construction, transfer waste off-site to a permitted landfill within the owner’s fleet, or contract waste removal (and disposal) services. For example, Dallman station subcontracts coal ash disposal at a local abandoned mine. The EPA uses a disposal cost a ssumption of $30-$50 per ton for wet FGD, dry FGD, and DSI controls, which the EPA developed in co nsultation with an experienced power sector engineering firm.

EPA should Establish an Expedited Permitting Process

As explained above and in the Pream ble to the rule, the EPA does not f eel that a new expedited process is necessary. If all parties work diligently and pr oactively, state permitting will not prevent facilities from coming into compliance with this rule with in the compliance period. If, however there is an unexpected delay that could not be prevented by the facility’s owne r, the EPA expects the 1-year extension of the compliance time to be available.

Comment 64: Multiple commenters (16705, 17055, 17701, 17725, 17400, 17608, 17724, 17775, 17791, 17812, 17815, 17834, 17868, 17868, 17868, 17887, 18441, 18497, 18500, 18023) argue that the EPA is unrealistic about the ability of uti lities and state or regional energy authorities to avoid electricity reliability issues after the rule is implemented. Th ese commenters believe the rule may result in the shutdown of certain units that are cri tical to the reliability of electric supply on a timeline that is faster than the time necessary to replace the power or upgrade transmission. Commenter 17608 notes that the EPA’s assumption that industry can comply quickly with the rule was a key assertion in the EPA’s conclusion that reliability will be unaffected.

These commenters identified several logistical problem s that they believe may take longer to overcome than the 3- to 4-year time period allowed by the rule. These include:

 Time for coordination of offline time for the installation of pollution controls on several plants in the same region.

 Time to obtain access to natural gas pipelines fo r repowering or replacing a plant with a natural gas generator.

 Time for planning, building, and interconnecti ng 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 step s could be accomplished in 2 years, there would realistically remain only 6 months inthe third year when control equi pment 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 cons equently most units must either be online or on standby to meet demand peaks. The comm enter argues that failure to have an adequate number of EGUs available during th is period could result in power curtailments or, in the worst case,334 brownouts or rolling blackouts. Commenter 17775 estimat es that installation of new control equipment required by the EGU MACT would take at least 6 years to complete.

Response to Comment 64: The EPA’s authority for setting the compliance time frames is set out in the CAA. In developing this proposed rule, the EPA has pe rformed specific analysis to assess the feasibility (e.g., ability of companies to install the required c ontrols within the compliance time-frame) and potential impact of the proposed ru le on reliability. For that analysis entitled “An Assessment of the Feasibility of Retrofits for the Toxics Rule” date d March 9, 2011, the EPA has projected the quantity of each APC technology that may need to be newly retr ofitted and in service by the compliance date(s). The EPA used its IPM model to an alyze which APC technologies woul d likely be used, and in what quantities, to achieve compliance with the proposed Toxics Rule.

The EPA’s assessment shows that a reasonable, mode rately paced effort of the power sector and supporting industry, including some ear ly starts, would result in many of the needed retrofits being installed by January 2015 with some needing up to an additional year. Inorder for all retrofits to be completed by January 2015, most projects would have to start early and the sectorwould have to engage in a more aggressive deployment program. In the ev ent that individual project s cannot be completed by the January 2015 statutory deadline for compliance, th e CAA offers affected sources the opportunity to apply for a 1-year extension.

Although the EPA assessed the ab ility to install the controls in 3 y ears (and determined that the controls could be installed in that time-frame), this woul d require the control tech nology industry to ramp up relatively quickly. The EPA also assessed a time-frame th at would allow some installations to take up to 4 years. This time-frame is consistent with the CAA which allows permitting authorities the discretion to grant extensions to the compliance time-line of up to 1 year. This time-frame also allows extra time for staggered installation of controls at facilities that need to install technologies on multiple units. Staggered installation allows compan ies to address such issues as sc heduling outages at different units so that reliable power can be pr ovided during these outage periods or particularly complex retrofits (e.g., when controls for one unit need to be located in an open area needed to construct controls on another unit). In other words, the additional 1-year extens ion would provide an additional two shoulder periods to schedule outages. It also pr ovides additional opportunity to spread complex outages over multiple outage periods. The EPA believes that while many units will be able to fully comp ly within 3 years, the 4 thyear that permitting authorities are allowed to gr ant for installation of controls is an important flexibility that will address situations where an extra year is necessary. The EPA expects that state permitting authorities will make the fourth year available.

Comment 65: Commenter 17697 writes that the proposed rule is unrealistic about the ability of the Guam Power Authority (GPA) to avoid electricity reli ability 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 65 : The EPA agrees that the unique c onsiderations faced by non-continental EGUs warrant a separate subcategory for units thatuse liquid oil-fired units in non-continental areas such as those on Guam and has included such a sub category in the final rule. At proposal, the EPA did not have all of the data from liquid oil-fired units in non-continental areas (e .g., Guam, Puerto Rico) and solicited comment on whether a subcategory should be established, based on the data to be received, for non-continental oil-fired EGUs. The EPA has now recei ved these late data and, based on those data, we determined the emissions characteri stics of the non-continental units were different, and, therefore, the Agency is finalizing a non-continental subcategory for liquid oil-fired EGUs in Guam, Hawaii, Puerto Rico, and the U.S. Virgin Islands. The EPA is not awar e of any liquid oil-fired EGUs in any of the other335 U.S. territories that meet the CAA section 112(a)(8) de finition but, if there are such units, they would also be part of the non- continental subcategory.

The EPA agrees that the unique c onsiderations faced by non-continenta l refineries, including a limited ability to obtain alternative fuels that lead to different emissions characteristics, warrant a separate subcategory for these EGUs. The EPA believes that units in this subcategory will comply through the use of cleaner oils or, for PM, th rough the installation of an ESP.

Comment 66: Commenters 17724 and 17805 ask that the EPA take into consideration the advance determination of prudence (ADP) process, which is a process to obtain co ncurrence from regulatory commissions that its decisions on options (and required expenditures) for future energy resources and modifications to existing energy reso urces 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 prudenc y review by regulatory authorities.

Response to Comment 66:

Fiduciary Obligations Prevent Expenditures until Rule Finalized

Multiple comments claim initiating major capital expenses prior to the rule’s promulgation violates a public company’s fiduciary obligatio ns. In all cases, the comments fail to quantify financial burdens to justify their position. A corpora tion’s obligations go beyond fiduciary trust: they include civic responsibilities for public (and empl oyee) health, as well as accountab ility for future direction (as determined by the board of directors). In response to these monetary assertions, the EPA recognizes the adversity towards financial risks associated with installing controls equipment prior to rule promulgation; however, the expenditures for dete rmining 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, engi neering and construction management costs (as a percentage of total installed cost) range from 4.1 % to 7.3% (basis: 500 MW unit). Considering industry typically limits conceptual engineering not to exceed10% of total engineered cost, by extension, preaward work accounts for less than 1% of total installed price. [Conceptual e ngineering studies are defined as: establishing project scope , type of controls, control’s perf ormance, auxiliary equipment, and permit plus funding requirements.] Since conceptual engineering is necessary to assess potential unit modification options, the EPA believes these pre-aw ard minor expenditures do not violate fiduciary obligations; rather, they provide va luable planning information for future regulatory compliance. For example, Nebraska Public Power District (N PPD) 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 conceptu al engineering is necessary to assess potential unit modificati on options, the EPA believes that th ese pre-award minor expenditures do not violate fiduciary obligations; rather, they pr ovide valuable information for future planning for regulatory compliance, which appears to serve a sensible fi duciary purpose.

Negotiating Contracts, Competitive Bid Eval uation – More Time Required for Compliance

18 “S&L to Develop Cost Estimates, Plans for FGD at Gerald Gentleman”; Utility E-Alert #1030, June 24, 2011; McIlvaine Company336 Contract negotiation through the competitive bid pro cess is an agreement achieved between a buyer (utility) and seller (supplier). Ul timately, the buyer determines length of time spent in negotiation, and concludes negotiations by signing an award for goods and/or services.

Owner’s Decisions & Options

Citing procedural difficulties (interfacing with mu ltiple entities, meeting once a year, etc.) do not constitute sufficient basis for inabi lity to meet compliance dates. The ow ner is ultimately responsible for assuring adequate and timely comp liance by exercising imitative over a “business as usual” approach. Moreover, MATS is inherently flexible – it allows an owner multiple options to attain compliance deadlines; namely, purchase power, shift power generation to cleanerunits (combined cycle plants, stations with emission controls, etc.), expedite retrofit work (utilize multi-shift schedule or extended overtime), fuel switching/blen ding, upgrade existing equipment, replace equipment/components, and retrofit existing equipment – or any combination there-of.

Comment 67: Multiple commenters (18023, 17608, 17638, 17716, 17752, 17756, 17820, 17821, 17840, 17868, 17904, 17925, 17931, 18033, 18502) have concerns with“early planning” and “forward planning” recommended by the EPA. Commenter 18023 notes , “If EPA intended this to be a direct final rulemaking, it should have said so.”

Commenter 17911 states that municipalities may not make any significant fi nancial or operational changes before the rule is promulgated, otherwise, th ey may be violating their fiduciary res ponsibilities.

Commenters 18428 and 19114 state that it would be im prudent planning for utilities to commit capital without knowing what the final standards are, as the risk of penaltie s and uneconomic investments is too great. The commenters state that mo re fundamentally, utilities contempl ating retrofits to generating units in rate-regulated states such as those in which the commenter operates run a substantial risk of nonrecovery if they make capital commitments before a final rule is issued.

Comment 68 : Commenter 18421 recommends that the EPA, the DOE, and the FERC work closely with regional utility planning and operation centers, th e National Association of Regulatory Utility Commissions, state PUCs, and utilities to ensure that the measures available preserve the reliability of the electric system.

Commenter 17741 is concerned that the compliance tim e will not allow adequate prep time, causing utilities to shutter multiple units or entire plants. The commenter is concerned about job loss.

Response to Comments 67 and 68 : In the preamble to the proposed rule, the EPA urged power generators and others to perform ad vanced planning so as to be prepared to implement the regulation in the 3-year compliance timeframe. A number of commenters took excep tion 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 th e compliance timeframe.

In the MATS preamble, the EPA stated that, although there are a significant num ber of controls that need to be installed, with proper planning, we belie ve that the compliance schedule established by the CAA can be met. The EPA pointed out that there are already tools in place (suc h as integrated resource planning, and in some cases, advanced auctions for cap acity) that ensure that co mpanies adequately plan for, and markets are responsive to, future requirements such as the ru le. In addition, the EPA itself is reaching out to key stakeholders including not only s ources with direct compliance obligations, but also337 groups with responsibility to assure an affordable a nd reliable supply of electri city 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 unders tands that FERC and DOE will work with entities whose responsibility is to ensure an affordable, reliable supply of electrici ty, 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 id entify 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 re ductions and health benefits required by the CAA can be achieved without any ri sk of adverse impacts on electricity system reliability.

Comment 69: Several commenters (17403, 17716, 17821, 17902) note that delays are expected due to the number of involved stakeholders (state public utility commissions, RTOs, NERC, FERC, DOE, EPA).

Response to Comment 69: Some commenters thought that there w ould be delays in compliance with this rule attributed to the nume rous stakeholders who would be involved. With proper planning, we believe that the compliance schedule established by the CAA can be met. As stated above, there are already tools in place (such as integrated resource planning, and in some cases, advanced auctions for capacity) that ensure that compan ies adequately plan for, and markets are responsive to, future requirements such as the proposed rule. In addition, the EPA itself is reaching out to key stakeholders including not only sources with di rect compliance obligations, but al so groups with responsibility to assure an affordable and reliable supply of electricity including stat e Public Utility Commissions (PUC), Regional Transmission Organizations (RTOs), the Na tional Electric ReliabilityCouncil (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 respon sibility is to ensure an affordable, reliable supply of electricity, including state PUCs, RT Os, 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 regiona l reliability concerns will inform decisions about the timing of retirements and other compliance strategi es to ensure energy reliability. The EPA believes that the ability of permitting authorities to provid e an additional 1 year beyond the 3-year compliance time-frame as specified in CAA section 112, along with other compliance t ools, ensures that the emission reductions and health benefits require d by the CAA can be achieved while safeguarding completely against any risk of adverse impacts on electricity system reliability

Comment 70: Several commenters (17402, 17752, 17758, 18428, 19114) note that the word “installed,” when attributed to vendors, refers only to the physica l construction of the controls but that the reality of control technology installation includes more than that.

Comment 71: Several commenters (17403, 17756, 17820, 17931) ask for additional time to allow for unit/control device testing/optimization after installation.

Response to Comments 70 and 71: The EPA is aware that installation of controls means more than simply manufacturing the device but m eans that it is installed on the unit.

Comment 72: Commenters 18430 and 18023 note that interstate gas pipelines may need to be expanded to account for EGU fuel supply changes.338 Response to Comment 72: The EPA’s analysis does not fully support this conten tion. The use of natural gas to comply with this regulation doe s increase modestly, by about 3% in 2015. However natural gas generation in 2015 with this rule will be more than 200,000 GWh less than generation from natural gas in 2009. This indicates th at the shift to natural gas for co mpliance with this rule would be very modest and that it could be acco mplished mostly with existing capacity.

Comment 73: Commenter 17815 notes that the short compliance timeline will jeopardize fuel diversity.

Commenter 16850 states that over the past 20 years, the vast majority of new capacity additions in Florida have been natural gas-fire d. The proposed Air Toxics rule, th e recent Cross-State Air Pollution rule, potential greenhouse gas regulati ons, and currently low gas prices ma y further encourage utilities to install natural gas-fired generation or repower existing oil- or coal-fir ed capacity to natural gas as a compliance strategy. In order to provide Florida’s cons umers with the benefits of a balanced fuel mix, utilities should be allowed to retain existing co al capacity without instal ling costly air compliance measures, if the utility commits to retire or repower the unit in the near future.

Commenter 17887 states that the EPA should recognize the needs of each state and region to deploy a portfolio of cost-effectiv e supply- and demand-side resources base d on unique circumstances – Over the past twenty years, the majority of new capacity a dditions in Pennsylvania have been natural gas-fired. Many states in the PJM footprint including Pennsylva nia are actively encouraging the development of renewable resources such as wind and solar. In order to provide Pennsylvania customers with the benefits of a balanced fuel mix, generators should be allowed to retain existi ng coal capacity without installing costly air compliance measures, if the gene rator 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 gene rators to avoid installing costly controls on units that are rarely dispatched.

Comment 74: Several commenters (16549, 17403, 17682, 17917) are co ncerned that the rule will weaken reliability by removing coal -fired units as a resource. Comm enter 16549 believes that that the EGU MACT may make it impossible to utilize th e 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 intentiona lly trying to increase the compliance costs for coal-fired plants to force coal plants to either clos e or be replaced by other s ources, such as gas-fired EGUs and renewable energy alternat ives (solar, wind, biofuels). Th is commenter believes the EGU MACT amounts to a subsidy of alternative ener gy industries and is defacto tax on the public. Commenter 17403 coal-fired retirements would have a significant impact on ke y midwestern and south Atlantic states.

Comment 75: Commenter 17386 expresses concern that th e proposed rule would decrease generation capacity by forcing early retirement of oil-fired EGUs. This commenter believes that forcing early retirement of oil-fired EGUs and the consequential decrease in generation capacity and system reliability is contrary to NERC’s objective to provide reliable service.

Comment 76: Several commenters (17701, 17791, 17807) are conc erned that environmental regulations for EGUs will drive electric generators to a single fuel source, which they argue could unintentionally weaken the stability of the power sector and increase cost for consumers. Commenter 17807 believes that the EGU MACT may result in electricity supply problems in Florida because the state is a peninsula, which limits opportunities to import power. Th e 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 hur ricanes, when supply of natural gas may not be available for sustained periods of time.

Comment 77: Commenter 16850 notes that significant controls would be necessary at many of Florida’s coal- and oil-fired generating units, and so me units would be at risk of retirement. The commenter states that the EPA’s final rules should avoid compromising electric system reliability and allow the maximum compliance flexibility for electric utilities provi ded for under the CAA.

Commenter 18500 states that the EPA ha s also asserted that fuel switch ing 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 construc tion 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 suffici ent gas supply to repower re sulting in necessary gas transmission upgrades that can be time consuming and costly. According to the commenter, the reality is that the EPA’s own permitting rule s present a time consuming obstacl e to meeting the EPA’s deadline yet nowhere in the proposal does the EPA contempl ate addressing accelerated permitting for pollution controls or exemptions from NSR requireme nts when making pollution control upgrades.

Response to Comments 73 - 77: The EPA does not dictate the complia nce strategy that might be used by regulated companies. The EPA has carefully designed a rule that can be achie ved by all coal types. Although the EPA’s analysis indicate s that most plants will comply by retrofitting existing coal-fired plants with pollution controls, some may switch to cleaner fuels. Our anal ysis shows that in fact there is very little difference in the relative use of the thr ee major coal ranks with a nd without the rule in 2015. There is a slight increase in the use of interior bituminous coal and a slight decreases in the use of subbituminous and lignite coals. Over all, coal remains the most important fuel for electricity generation.

Some plants may retire. In most cases there is ade quate excess capacity to avoi d any threat of a problem for electricity reliability. Should ther e be a reliability concern, it can be addressed in a variety of ways including use of excess capacity, installation of new capacity, transm ission upgrades, and demand-side strategies that can make over all compliance with this regulation mu ch less expensive, and can be implemented relatively rapidly. The EP A projects that this rule will re sult in a very small increase in gas-fired generation, a very small decrease in coal -fired generation as a re sult of compliance with MATS.

Comment 78: Commenter 17732 is concerned about the time it takes to receive land use approvals on Indian trust lands should site-specific cons traints necessitate use of additional land.

Response to Comment 78: Sources can obtain an additional year to comply if necessary for the installation of controls. Unavoidable delays in obtaining permits necessary to install th e controls would likely be sufficient to obtain th e additional year to comply.

Comment 79: Commenter 17738 is concerned about plants which already ha ve emissions controls and limitations established through case-by-case MACT de terminations. The commenter suggests alternate compliance dates for these plants.

Response to Comment 79: Sources that are existing sources on th e compliance date for the final rule would have 3 years to come into compliance. Gene rally 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 nega tive impacts of delays that could occur. According to the commenter, such an approach would also ease concerns over grid security caused by mass outages on generato rs to install the required equipment

Response to Comment 80 : The EPA’s analysis does not confirm that MATS will result in anywhere near the extent of outages that this commenter projects, and severa l outside analyses have reached conclusions consistent with the EPA’s analysis. Th e 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 he lp to assure grid security.

Comment 81: Commenter 17930 stated that the EPA’s beyond-th e-floor analysis [for Hg at facilities burning virgin low BTU coal] does not properly take in to account the effect thatthe limit would have on energy requirements and reliability when lignite units are closed due to inability to meet the proposed beyond-the-floor limit.

Response to Comment 81: As stated elsewhere, the EPA believes that the data us ed to conduct the beyond-the-floor analysis are consis tent with results achieved in U.S. DOE Hg control technology demonstration projects. The DOE’s National En ergy Technology Laboratory (NETL) sponsored a project entitled “Mercury Control for Plants Firing Texas Lignite and Equipped with ESP-wet FGD”. In this project, URS Group evaluated so rbent injection for Hg control inan 85/15 blend Texas lignite/PRBderived flue gas. The authors of th e 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 cubi c feet (lb/Macf) and greater than 90 percent at higher rates. In longe r-term (60-day) testing using a brominated sorbent, Hg removal averaged 80 percent at a modest inj ection rate of 2 lb/Macf. This comp ares favorably to the results of 70 to 90 percent achieved in th e short-term testing at the same injec tion rates. However, greater than 90 percent could have been achieved at in jection rates of 3 to 5 lb/Macf. Note that all of these results are for control across a cold-side ESP. Control across a fabr ic filter is normally expected to exceed that measured through an ESP. The EPA believes that its beyond-the-floor analysis is appropriate, including the costs analyzed. We do not anticipate any reliabili ty problems due to lignite plants closing. Any shift away from lignite is made up for by other type s of generating capacity and shifts to PRB.

Comment 82: Commenter 18033 said that the EPA has co mmitted a “fundamental error” with its “undocumented and unsupported claims of key stakehol der collaboration to ‘saf eguard[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 executiv e concerning this rulemaking.

Comment 83: Several commenters (17627, 18034, 18037, 18907) are concerned that the reduced reliability resulting from the EGU MACT may result in an increase in emissions because industry will be forced to rely on small emergency generators. These commenters note that most of the emergency generators are small diesel-fired units that are not capped or in many cases permitted. The commenters note that higher emissions from these emergency b ack-up generators are not normally a concern because of their limited use during emergency situations a nd power outages. According to the commenters, if demand response programs become a necessary strategy to prevent or minimize the impact of reliability issues resulting from loss of capacity, however, thenlocalized net increases in emissions would be341 expected. Rather than improving air quality, the comme nters argue that this ru le would directly and adversely impact citizens in the urban cores wh ere emergency generation is typically located.

Commenter 18037 stated that in its anal ysis of this year’s capacity au ction results, PJM noted that the coal plant offers which included anticipated envir onmental 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 s hould consider in it cost -benefit analysis. The commenter states that ISO-RTO estimates that are available suggest that 50% or more of DR resources in the market are not dema nd reductions, rather they are merely a shift to customer-supplied behind-the- meter generation, and muchof that generation is from small diesel units the emissions from which are not accounted for and in many cases not permitted. According to the commenter, this is particularly important on very hot, ‘high electric demand days” when DR generators are called upon. The commenter states that as the EP A was informed by the State of Delaware in the RICE NESHAP docket (EPA-HQ-QAR-2008-0708), there are tens of thousands of these diesel generators throughout the Northeast.

According to the commenter, these “area sources” em it air toxics and are an increasingly significant contributor to the ground level ozone non-attainment problem as DR programs continue to grow exponentially; they represent tens of thousands of megawatts in the PJM, ISO-New England, New York ISO, Midwest ISO wholesale markets and throughout th e US. The commenter states that at a minimum, since EGU units are clearly being displaced in the competitive markets by DR offers, and will not likely be replaced megawatt-for-megawatt by cleaner, more expensive thermal generation which must control and account for its emissions, the EPA’s cost-benefit an alysis is incomplete if it does not account for the growth in emissions from behind-the-meter gene ration participating in ISO-RTO DR programs, particularly those from uncontrolled diesel units.

Response to Comment 83: Not all demand response is a reducti on in electricity demand, much of it shifts demand for electricity from peak demand peri ods 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, a nd 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 reconsider ation, limits the operati on of these sources, specifically to prevent an increase in emissions. These generators are less efficient to operate than other sources and thus are less desirable economically as well as envir onmentally. The EPA does not expect that the Mercury and Air Toxics Standards rule will substantially increase the use of these generators.

Comment 84: Commenter 18538 believes that the EPA ha s overstated the amount of generation available in future years by more than 10 GW by including generating plants that have retired and by failing to adjust wind generating capacity to account for the fact that wind is variable and often does not blow during times of peak energy use.

Response to Comment 84: The EPA disagrees with the claim thatit does not account for the variability of wind generation in its power sect or modeling projections. The EPA r ecognizes that wind is a variable resource for power generation, and our modeling of MATS in fact takes this re ality 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 cl ass (ranging from class 1 to class 7) and geographic region, an d are explicitly designed to repr esent how often the wind blows to support power generation at differentlocations. The EPA worked with the U.S. Department of Energy’s (DOE) National Renewable Energy Laboratory (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 ca pacity (in MW) broken into four cost classes in each IPM model region.

To represent intermittent renewable generating sources like wind and solar, the EPA’s IPM modeling (including the modeling used for MATS compliance cost projections) uses generation profiles which specify hourly generation patterns for a representative day in winter and summer . Each eligible model region is provided with a distinctset of winter and summer generati on 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 fr om the Energy Information Administration’s (EIA) Annual Energy Outlook (AEO) 2010. They are shown in Table 4-20, Table 4-21, and. Table 4-22 of the IPM documentation on EPA’s website. See IPM documentation.

Comment 85: Several commenters (17800, 17807, 17911) believe that the work practice standards will impact the reliability of electric supply. These co mmenters argue that most EGUs do not have annual planned outages that would allow time for implem enting 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 th at by requiring outages every 18 months, the EPA will increase the number of outages and thus unit downtime. The comment er 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 scaffold ing; 2-5 days to repair or replace burner components; 3 days to dismantle the scaffold ing). According to the co mmenters, additional time may also be required to order replacement parts, whic h could result in an extended outage of between 16 to 26 weeks.

Response to Comment 85: The EPA does not believe work practi ce standards will impact reliability and notes that the frequency of the tune-ups required have b een changed in the final rule. See Preamble discussion of work standards.

8. Survey of public power utilities.

Comment 86: Commenter 17868 shared results from a surveyit conducted of public power utilities (utilities owning approximately 14 GW of coal base d generation capacity responded to the survey). According to the commenter, these represent over 50% of the coal-based capacity wholly owned by public power utilities, and res pondents ranged in cumulative capacity between 55 MW and 2200 MW, and averaged 610 MW of coal based capacity):

a. About 20% of respondents planned to retrofit FGD and about 20% SCR (typically the same utilities were retrofitting both). About one-h alf planned to replace or supplem ent existing ESPs with new FFs

b. About one-fourth were moving forward with plan s 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 befo re deciding on a compliance approach.

d. About three-fourths of respondents stated that they needed the assi stance of engineering consultants for planning their compliance strategy. Such reli ance 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. Add itionally, several respondents cited a mandatory

― public bid process for selecting contractors (and purchasing equipment) which deterred some contractors and created additional delays in reaching compliance.

e. Public power utilities generally must receive appr oval from political bodies, such as an elected Board of Directors and a City Council. Pr ocedures vary by utility, but separa te 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 fina ncing 8 months. However several respondents noted that budgets were addressed only once per year, a nd that public reviews of plans and funding could result in extended delays, including what one respondent called “hos tile interventions.”

Response to Comment 86: 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 privately ow ned facilities do not have. We think that the flexibilities that are offered under the CAA includi ng the availability of a fourth year and other compliance time flexibilities will ease the burden these facilities face.

9. Other.

Comment 87: Commenter 18027 notes that the language in section 112(i)(3) is inconsistent across paragraphs. Section 112(i)(3)(B) prov ides for a one-year source-specif ic extension to the principal compliance schedule established for the source category or subcategory whereas the preceding paragraph states that Congress pr ovided for the compliance schedule established upon promulgation of the standards to apply to an entire category or subcategory of sources.

Response to Comment 87: The EPA does not agree with the comm enter that the CAA section 112(i)(3) paragraphs are inconsistent. CAA s ection 112(i)(3)(A) authorizes the EP A to provide up to 3 years for initial compliance with promulgated standards, and section 112(i)(3)(B) allows the EPA or a state with an approved title V permit program to approve a 1-y ear extension of the comp liance period established 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, 18539, 19114, 19120, 19121, 19214, 9738, 19536/19537/19538, 18023

1. Opposition to emission averaging compliance option.

Comment 1: Commenter 17174 states the emissions caps fo r existing affected sources choosing to demonstrate compliance by the emission averaging option cannot be effectively implemented or enforced. The commenter encountered many problem s with the approval process in the vacated Boiler MACT in 2007, and now the EPA has proposed th e same approval process here for the Utility MACT, disregarding the known problems in implem enting 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 requirem ent to establish an emission cap and submit an implementation plan to the permitting agencies for approval is problematic as written. The commenter states that because the emission cap is not usedin 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 demonstra tion methodology that shows th at a facility is not exceeding the cap in the compliance equations in s ection 63.10009. According to the commenter, if the cap is included in the compliance equations, faci lities 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 res ources to approve these duplicative plans.

Response to Comment 1: The agency disagrees with the comme nter’s suggestion that the emissions averaging option cannot be implemented or enforced effectively. The commente r’s concerns regarding emissions averaging plan approval is mistaken, as su ch 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 th is requirement are already required to be submitted in notices of compliance status (NOCS), so no rule change is needed. Finally, states, local, or tribal agencies who are delegated the aut hority to implement this program will decide based on their own needs and requirements whether or not to choose to require submissi on and approval of plans.

Comment 2: Commenter 17818 opposes the averaging of HAP. However, the commenter supports allowance of limited emission averaging for existi ng units at sources that are within a single subcategory. Commenter further states that withou t averaging their existing units are already below existing HAP emission rates due to pr evious emission control projects, so me of their units will be above new HAP emission rate limits and would require re design of the existing c ontrols to achieve unitspecific compliance. According to the commenter, aver aging of units might fac ilitate state-of-the-art highly effective controls installati on on other units at the source to achieve an a pproved averaging plan, and this may relieve the need to replace or modify c ontrols that had been recently installed, in effect giving credit for the insta llation of those controls.345 Response to Comment 2 : The agency agrees with the commenter that emissions av eraging can provide a cost-effective, if not cost-savi ng, means of compliance, to EGU owners or operators. The emissions averaging provisions of the rule remain.

Comment 3: Commenter 18450 opposes allowing owners and ope rators of existing a ffected sources to demonstrate compliance by emissions averaging for units at the affected source that are within a single subcategory since it will allow larg e facilities to avoid installing air pollution c ontrols to reduce HAP emissions on all affected units. Co mmenter recommends that the EPA remove the averaging provisions and establish a discoun t 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 th e use of emissions averaging for existing sources for a number of reas ons, ranging from increased flexibility to reduced costs for EGU owners or operators, as well as redu ced emissions through use of a discounted emissions limit for those units subject to emi ssions averaging. The EPA disagrees th at use of a discount factor is needed for this rule, as stack testing variability ha s 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 criteriaestablished by the EPA, in practic e, it works only if all affected sources operate exactly as assumed in the formula tion. According to the comme nter, realistically, the better-controlled source may operate le ss than assumed (perhaps due to the greater costs of compliance), while the under-controlled source uses cost advant age 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 wo rth providing more flexibility to emit hazardous air pollutants.

Comment 5: Several commenters (19536, 19537, 19538) states that the EPA should not permit units to average emissions. According to the commenters, th e proposed averaging woul d allow some coal- and oil-fired units to emit HAP in excess of the pr omulgated standards (so long as a neighboring unit operates below the standards) – a result prohibited by section 112. The comment ers state that section 112 states that “[a]fter the effectiv e date of any emissions standard . . . promulgated under this section and applicable to a source, no person may operate suchsource in violation of such standard” unless the agency provides a more lengthy complianc e schedule. 42 USC section 7412(i)(3).

The commenters point out that the agency’s discreti on to construe the word “source” under the CAA is constrained by the congressional policies underlying section 112. Chevron, U.S.A. v. Natural Resources Def. Council , 467 U.S. 837, 866 (1984). The commenters state that Congress intended, in section 112, to ensure the maximum reduction of hazar dous air pollution, and to that end, it constrained the agency’s ability to balance pollution-reduction with economic considerations. See 42 USC section 7412(d). The commentesr assert that the agency ha s set most standards at the statutory minimum. According to the commenters, section 112 does not al low the agency to perm it additional pollution in order to ease compliance (see 40 CFR section 63.41 (sources may not average emissions to avoid compliance with section 112 standards).

Response to Comments 4 - 5: As mentioned earlier, while the ag ency 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 (existin g units within a single subcategory) and frequent emissions verification (quarterly ) can provide a flexible, cost-effective compliance approach.346 2. Support emissions averaging compliance option.

Comment 6: Numerous commenters (17402, 17623, 17648, 17655, 17705, 17716, 17718, 17722, 17725, 17758, 17774, 17798, 17870, 17873, 17904, 17928, 18025, 18031, 19121, 18023) support emissions averaging for compliance.

Response to Comment 6: The agency appreciates the commenters’ support for use of emissions averaging subject to the rule’s eligibility requirements.

Comment 7: Commenter 17174 requests the EPA eliminate the requirement for delegated authorities to approve implementation plans and instead develo p an emission averaging certification mechanism within the Notice of Compliance Status (NOCS), b ecause the NOCS process is established, and states have experience implementing it.

Response to Comment 7: As mentioned earlier, the rule allo ws, but does not require, delegated authorities the ability to appr ove emissions averaging plans.

Comment 8: Commenters 17402 and 17648 note that emission av eraging provides a flexible approach. Commenters also note that emission averaging achieves equivalent MACT emissions limits. Commenter 17402 states that facility-wide averaging will allow owners and operators to comply with emissions limits by over controlling s ources within the group where it is co st effective to do so in order to offset exceedances of the standard by sources for which emissions cont rol would be less cost efficient.

Response to Comment 8 : The agency appreciates the commenters’ support for use of emissions averaging subject to the rule’s eligibility requirements.

Comment 9: Commenter 17174 states the requirement for delegated agencies to approve implementation plans is burdensome and unnecessary. The commenter suggests the EPA should provide specific guidance and examples on what constitutes an acceptable emission cap. The commenter notes that while the EPA attempted to correct the enforc eability problem related to the emission cap in the final Boiler MACT by requiring f acilities 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 constitu tes 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 re tain the authority to approve the implementation plans.

Response to Comment 9 : The agency finds the commenter’s concern misplaced. While the rule allows state, local, or tribal authoritie s who have been delegated approval of this rule the ability to require submission of, as well as approval of, emissions av eraging plans, the rule requires EGU owners or operators who choose to engage in emissions averagi ng to develop an emissions averaging plan and to maintain and present such a planupon request. The rule establishe s the formula for demonstrating compliance when emissions averaging is used, so th ere is no need for additional guidance. Should the commenter find developing a plan or determining compliance to be pr oblematic, he or she could choose another compliance option available in the rule.347 Comment 10: Commenter 17174 suggests the emission av eraging compliance option in the Boiler MACT and Utility MACT be consistent.

Response to Comment 10 : The agency agrees with the comme nter’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 th at emissions averaging re presents an equivalent, more flexible, and less costly alternative to unit- by-unit emissions limits while still maintaining a regulation that is workable and enforceable. Acco rding to the commenter, this flexible compliance option will be particularly helpful to smaller genera ting units that are co-locat ed with larger generating units, but may not be economic to retr ofit with pollution control systems.

Response to Comments 11 - 12: The agency appreciates these commenters’ support of emissions averaging.

3. Request expanded flexibilit y for emissions averaging.

Comment 13: Multiple commenters (17718, 17816, 17820, 18037, 18539, 19114) state that the proposed emission rate averaging plandoes not provide much flexibilitybecause the emission rate limits are so low. According to the commenters, in order fo r a source to take advantag e of these provisions, at least one unit would need to achieve a rate substan tially lower than the MACT limit, and there is no evidence that such rates are achievable for any exis ting units. The commenters state that the mass-based approach would provide each facility with a total annual mass emission limit for HCl, PM, and Hg that could provide flexibility for the source to operate in the most economical way to meet that facility-wide limit.

Comment 14: Numerous commenters (17627, 17718, 17719, 17737, 17740, 17768, 17774, 17775, 17813, 17816, 17820, 17856, 17885, 17902, 17913, 17928, 18024, 18037, 18539, 19114) state that the averaging provisions should not be limited to units at a facility but should be expanded to include adjacent units that have controlled access within a common fence line. The commenter states that the EPA can provide additional flexibility and cost sa vings on emission reductions by revising the facility definition to include un its within a common fence line. Comme nter 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 fo r the unit for the previous 3 years. Commenter 17740 suggests that emissions averaging for units in different subcate gories could easily be accomplished by requiring the units to develop an emissions averaging plan, similar to the plan required for NO X emissions averaging under the Acid Rain Program at 40 CFR 76.11. Accordi ng to the commenter, such an approach could easily be used in the EGU MACT rule to allo w units in different s ubcategories to meet the HAP emission standards through emissions av eraging. Commenter 17928 further states that oilbased units are particularly disa dvantaged by the proposed constraint s on averaging because they are often stand-alone units that would not be able to average emissions with ot her units at a facility. According to the commenter, oil and coal units at a facility should be perm itted to average emissions.

Response to Comments 13 - 14: The agency reviewed the comment ers’ suggestions, and the rule continues to allow emissions aver aging of a rate, not mass, from existing units within the same348 subcategory. EGUs in the same subcategory located at one or more contiguous pr operties, belonging to a single major industrial grouping, which are under comm on control of the same person (or persons under common control), remain eligible un der to rule to engage in emi ssions 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 ent ities 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 Mercur y Risk Assessment Supporti ng the Appropriate and Necessary Finding for Coal and O il-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 comm enter’s suggestion, but, apart from the contiguous property eligibility criter ion mentioned in the rule, emission s 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) indi cate that the emission aver aging criteria are too rigid. Commenters (17623, 17655, 17757, 17758) request broader applicabilityand more flexibility in emissions averaging. Commenters (17623, 17758) believ e 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 be cause all facilities will collectivel y 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 enforcem ent issues that could arise from allowing emission averaging in any of the scenarios the rule bars, and this lack of information deprives commenters the opportunity to assess, comment on, and address the EPA’s concerns. Commenter 17758 went on to state that the EPA does not explain why emission averaging provisions or limitations that were applied in other MACT rules are applied in Utility MACT or what characteristics of those other sources are comparable to Utility MACT sources (i.e., why are limits that were deemed necessary for synthetic organic chemical manufacturing appr opriately applied to electricity generation). In fact, commenter 17758 states that the EPA appears to assume that pa st rulemaking limits applie d to emissions averaging create an enforceable “cr iteria” that must be satisfied in this rule for utility generators. Commenter 17758 states that the EPA has not explained why any of the additional limiting criteria are needed if the owner or operator can demonstrated that total averag ed emissions do not exceed the limits that would be applied to individual units. Commenter 17758 states th e EPA has not demonstrated that limiting the use of emissions averaging would obviat e the unspecified implementation and enforcement issues that the EPA suggests are of concern. Commenter 17758 further st ates the EPA fails to recognize the compliance and enforcement difficulties that would be creat ed by imposing the proposed limitations on averaging; for example, it would be substantia lly more complicated and expensive to segregate, measure separately, and monitor the emissions of units that share a common stack to determine that e ach is in continuous compliance with the MACT standard for a particular po llutant than to allow these units to use averaging by measuring common emissions from the stack.

Response to Comment 16: The agency has considered all but disagrees with most of the commenters’ assertions and notes that the commenters provide no data to support their a ssertions. We specifically disagree that broader averaging is consistent with the statute as e xplained in the preamble to the HON NESHAP:349 The fundamental problem with the broader aver aging 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 stan dard, as the collection of SOGMI emission points within a major source. Many major sources containi ng such points will also contain other points not covered by this standard but to be covered by later, different MACT standards. Each of these standards will have a separate floor, and the statute requires that eac h standard be no less stringent than its floor. If av eraging were allowed between s ources covered by two separate standards, it is likely that one of the sources involved in the average would be emitting HAP’s at a level that violates the standard applicable to it. Thus, averaging between multiple sources in different categories is not legally defensible.

Similarly, allowing averaging between new and exis ting sources at the same facility would also likely lead to one source failing to meet its applicable standard. There are separate MACT standards with separate floors for new and existing sources within the HON, just as there will be separate standards for sources in different catego ries at the same site. An average that included sources with different floors and different standards cannot be reconciled with the statutory requirement that each source in the category comply with the applicable standard.

59 FR 19427 (April 22, 1994)

Based on the long standing in terpretation of the statut e, the rule is unchange d. Further, we note that commenters appear to presume that the agency must justify not allowing averag ing on a broader level, but such an assertion is not vali d. CAA section 112 does not expressly authorize averaging and the final rule would be consistent with the statute abse nt 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 inte rpretation, nor have the commenters provided information that would call into question our policy jus tifications for limiting averaging in the manner proposed. That certain EGU owners or operators may not be able to avail themselves of the emissions averaging options (e.g. because they vent units in different subcategories to a common stack) or may choose not to because they determine that the potential benefits of averagin g do not justify compliance with the requirements to average does not render th e provisions invalid.

Comment 17: Several commenters (17623, 17627, 17689, 17736, 18037) state that limiting emissions averaging to only units in the same subcategory shrinks the universe of sources that can use this option. Commenters 17655 and 17757 encourage the EPA to a llow averaging between units at different facilities that are under the same/c ommon control and operating in the geographic region or at adjacent facilities. Commenters 17655 and 17881 encourage the EP A to allow averaging new unit emissions with existing unit emissions. Commenter 17623 states that no t allowing new facilities to participate puts new generation capacity at a disadva ntage and reduces the effectiveness of the averaging program. Commenter 17623 states that allowing emissions averag ing for new facilities will incentivize installation of state-of-the-art controls on new units. Comm enter 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 arbitr ariness. Commenters 17758 and 18037 s uggest the EPA allow emissions averaging across all affected units (both coal and o il) on a facility basis, including both new and existing units and where averaged units share a comm on stack. Commenter 17758 suggests the EPA allow broader emissions averaging where it can be demonstr ated that public health and environmental benefits are preserved. Commenter 17881 states that averagi ng across multiple new EGUs would minimize the risk of startup, shutdown or malfunction at a single unit resulting in an exceedance of an applicable emission limit.350 Response to Comment 17 : As mentioned earlier, the agency be lieves 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 s uggestions, such as including new units that can be designed for appropriate emissions control devices from the onset or mixing units from differing subcategories with differing emissions limits, are not consistent with the statute as discussed above and, in any case, we do not be lieve such averaging would be appr opriate in any case. The rule has not been revised for these suggestions. Note that th e final rule contains work practice standards during periods of startup or shutdown.

Comment 18: Commeter17758 states that the EPA previously proposed emi ssions averaging for EGUs in its 2004 proposed standards and the rationa le 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 allo wed to average actual emissions data from CEMS to determine monthly average weighted emissions for the units participating in an averaging plan, as this simplifies the demonstration of compliance.

Comment 20: Commenter 17705 notes that section 63.10022 requires facilities using emissions averaging to also comply with operating limits fo r control devices and fuel limitations for Hg and chlorine on top of numeric stack emissions standa rds. Commenter 17705 states this burden can be alleviated by allowing an averaging plan that base d on CEMS usage, as CEMS data is a more accurate indicator of continuing compliance with a numeric standard than operating limits set during periodic performance tests or fuel analyses.

Comment 21: Commenter 17705 stated that the av ailability of the alternate SO 2 standard coupled with use of emissions averaging based on use of existi ng certified CEMS is lik ely to be a preferred compliance option for sources with existing FGD technology and should be fully accommodated in the final rule language.

Response to Comments 19 - 21: The agency supports the commenter s’ suggestions regarding use of CEMS for units subject to emissions averaging, and th e rule has been revised so that units that use CEMS can participate in emissions averaging. Note th at, as stated elsewhere, the rule no longer requires fuel analyses for pollutants.

Comment 22: Commenter 17402 notes emission averaging is permitted under section 112 and there is ample precedent for allowing it. Commenter 17402 notes the emissions averaging is permitted under section 112(d) of the CAA(particular ly given the important limitations included in the rule) and there is ample precedent for allowing such facility-wide emi ssions 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 th at the EPA apply MACT standards on an individual unit basis; CAA section 112(d)(1) provide s that the EPA shall promulgate regulations “for each category or subcategory of major sources and area sources of hazardous air pollutants...” (emphasis added); and CAA section 112(d)(2) standards are applicable to “new or existing sources” (emphasis added).351 Response to Comment 22: The agency acknowledges the commenter s’ support for emissions averaging and for the agency’s discretion in designing emissions averaging provisions according to program needs. No changes to the rule regarding expansion of emi ssions averaging across subcategories or to new units were made.

Comment 23: Commenters (17402, 17655) support weighting by heat input (based on the performance test results). Commenter 17655 agre es that existing DAHS can perfor m these calculations and produce reports.

Response to Comment 23: The agency thanks the commenters’ for their support of weighting emissions rates by heat input.

Comment 24: Commenter 17648 supported the f our criteria required by th e EPA to participate in emissions averaging and went on to st ate that the EPA should also apply a discount factor to assure that emissions from the affected sources as they are actu ally controlled will be at least as stringent as the total sum of emissions that woul d be achieved if each unit at an affected source were controlled individually to the level required by th e rule, as it has done in prior NESHAP.

Response to Comment 24: The agency disagrees with the comment er’s support for use of a discount factor, for under the emissions averaging procedures c ontained in the rule, each group of units subject to emissions averaging will have to meet the emi ssions limits of a specific subcategory. While these emissions limits would otherwise apply on an individual basis, thr ough 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 notbound by a cap, but by the otherwise applicable emissions limit. Th e rule does not include a discount factor.

Comment 25: Commenter 17774 states that disallowing the new facilities from emission averaging puts new generation capacity at a disadvantage and reduces the effectivene ss of the program. According to the commenter, units subject to th e NSPS would have to continue to comply with the individual PM limits in that rule even if the emissions averagi ng option is used, further re ducing the utility of the option.

Response to Comment 25: The agency disagrees with the comment er, and the rule co ntinues 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 stat e-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 averag ing of new sources. One reason we allow emissions averaging is to give existing sour ces flexibility to achieve complianc e at diverse points with varying degrees of add-on control already in place in the mo st cost-effective and tec hnically reasonable fashion. This flexibility is not needed for new affected s ources because they can be designed and constructed with compliance in mind.

Comment 26: Commenter 17798 recommends initial emission averaging by utility ownership and state staged to facility averaging 2 y ears later. The commenter states th at 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 owne r or operator will need to have his or her emissions averaging plan developed and re sults of all testing in hand on or before 180 days after the unit’s first compliance date in the rule.

Comment 27: Commenter 17881 states that insection 63.10006(o) if emissi on limits are consistently being met, then reduced frequency of testing shou ld be allowed for the units utilizing emissions averaging.

Response to Comment 27: The agency disagrees with the comment er, and the rule co ntinues to exclude those units associated with emissions averag ing from reduced emissions testing frequency.

Comment 28: Commenter 9738 states that the inclusion of an alternativ e compliance provision within the proposed rule that would allow owners and oper ators of existing affected sources to average the emissions by sources within the same category allows more flexibility for ow ners. According to the commenter, this may increase the feasibility of the comp liance deadlines in two ways: First, if cost is a concern, owners and operators may be able to stra tegically implement technol ogy to bring their plant into compliance on only some of the smokestacks. The co mmenter states that while this could ultimately balance the total emissions of the plant, it would re quire the owners and operat ors to raise fewer funds, which should thus decrease the amount of time needed to prepare fiscally for the new standards. The commenter states that second, if an owner or opera tor chose to selectively implement such technology, less work would need to be performed, as only a portion of the smokestacks w ould require retrofitting. Thus, according to the commenter, this should also require less time to bring the facility into compliance, and this alternative provision allows fo r companies to strategicallystagger their compliance efforts and increases flexibility. The commenter states that further, for facilities which have already implemented some such technology, this alternativ e provision may eliminate the need for additional action. According to the commenter, this would achi eve the goals of the proposed bill by promoting the same reductions in emissions, thus havi ng the same societal impact overall.

Response to Comment 28: The agency appreciates the commenter’s support of emissions averaging within a subcategory.

4. Clarifications and modifications to emissions averaging.

Comment 29: Commenter 17402 suggests clarifications to improve emissions averaging for compliance. Commenter 17402 notes that s ection 63.10009(f)(3) and section 63.10022(a)(1) are somewhat contradictory and could be interpreted as requiring comp liance in the first month of collecting data. Several commenters (17725, 17402, 17775, 17881) recommend clarifying in section 63.10009(f)(3) that the first compliance period begins af ter 12 months of data have been accumulated, and in section 63.10022(a)(1) that compliance is demons trated each month, and that compliance is first determined after 12 months of data are collecte d. Commenter 17775 states that requiring compliance with both a monthly average and a 12-month rolli ng average of those values makes no sense.

Comment 30: Several commenters (17821, 17856, 17902) recommend that the EPA allow sources to demonstrate compliance with an averaging plan over a 12-month period and not on 30-day rolling average basis. Commenter 17821 further states that the primary reason for this is that the EGUs require periodic outages for scheduled and unscheduled main tenance. 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 ba sed on only one month’s data. The commenter states353 that if however compliance with anaveraging plan were based on the average of 12 consecutive months, a facility would be in a better positio n to absorb the effects of individu al unit outages over the course of a year. Commenter 17856 further states that revisi ng the rule as suggested would provide needed flexibility to the regulated community, eliminate co mpliance and enforcement uncertainties, and achieve the same emissions reductions that the EPA seeks.

Response to Comments 29 - 30: The agency has reviewed the comm enters’ suggestions, and the rule has been revised so that the results of the emissi ons testing are used for each 30 boiler operating day rolling average during the quarter in whic h the emissions testing is conducted.

Comment 31: Several commenters (17402, 17775, 17881) recommend operating parameters be removed from the averaging plan required under sect ion 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 recommen d that in calculating the ESP power operating parameter, the calculation should use the lowest (o r highest) value obtained during the performance test as opposed to the average low (or high) values of the performance testing. Commenter 17881 further states that the references in section 63.10022(a)(2 ) through (a)(7) to the “3 hour average paramete rs” established during the performance test does not clearly line up with the requirement s of Table 4 or Table 8 and is confusing.

Response to Comment 31 : The commenters’ suggestions are m oot, for the rule no longer requires monitoring of control de vice operating parameters.

Comment 32: Commenter 17174 states the EPA should clarif y the deadline to established emission caps to demonstrate compliance with the emissions av eraging option for the emi ssion level or control technology. The commenter notes that section 63.10009(c) and section 63. 10009(g)(2)(i) appear to have a contradiction in dates (30 days vs. 60 days), an d the EPA should correct th is 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 [INSERT DATE 3 YEARS AFTER PUBLICATION OF THIS FINAL RULE IN THE FEDERAL REGISTER ], or the date on which emi ssions testing done to support your 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 be gin emissions averaging, whichever is earlier).

Comment 33: Commenters 17648 and 17881 request clarifica tion of emissions averaging provisions, with assertions that the preamble indicates emission averaging provision s do not apply to units that share a common stack with units in a different subcategor y, while the rule text in section 63.10009(h)-(k) is confusing, and arguably may allow sources with units in different subcategories emitting through the same stack to average emissions to demonstrate co mpliance, without clarifyi ng that all of the other relevant averaging provisions, such as the emissions cap, apply.

Response to Comment 33: The agency considered the comment ers’ suggestions but the rule is unchanged. What the rule prohibits is units from differing subcategor ies being included in emissions averaging, not only units from differ ing subcategories sharin g common stacks. The rule provisions cited describe how EGUs sharing common stacks can de termine compliance with an emissions averaging
program.354 Comment 34: Several commenters (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 compliance, 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 commenter s’ suggestions, and the rule has been revised to include SO 2 as eligible for emissions averaging.

Comment 35: Commenters 17623 and 17775 suggest the EPA include more flexibility in the submission timing of the emissions averaging pla n, and notes that submittal 180 days prior to compliance is a lengthy lead time that limits the effectiveness of the EPA program because facilities may not have yet finished control technology insta llation to formulate the emissions averaging plan.

Response to Comment 35: The agency considered the commenters’ request, and the rule has been revised so that an emissions aver aging plan must be developed by 3 years after the rule has been promulgated. In addition, results fromall initial emissions testing must be received and ready for use in compliance calculations by 3 years afte r the rule has been promulgated.

Comment 36: Several commenters (17655, 17718, 17795, 18429) ag ree that 30-day block averaging should supplant rolling averages in a unit averaging plan, as there are in consistencies that would accrue from varied operating schedules of the affected un its. Commenter 17795 further states that lengthening the averaging period would help ac hieve the flexibility the EPA inte nded by granting facility averaging. Commenter 18429 recommends that emissions averag ing should be based on annual mass emissions rather than on a rate basis, and should be allowe d between any groups of s ources that contractually commit to an emissions averaging program similar to the original NO X compliance program under the Acid Rain Program.

Comment 37: Several commenters (17718, 17775, 17795, 17800, 18031) state that the EPA must clarify ambiguities in the proposed rule and explain exactly how the provisions must be implemented. According to the commenters, it is unclear how to account for units which are shut down for an outage or whether individual unit baseline testing is necessary. Commente r 17775 suggests that in the event of a unit outage, the EPA should allow use of at least a 3-month average. Commenter 17795 further states that if one unit operates slightly above the limits c ould not operate during the fi rst year of compliance, and the unit used to average it into compliance was in outage, this would negate any benefit or flexibility the EPA intended by incorporating the averaging provision into the proposed rule. Commenter 17800 recommends that the EPA adopt the averaging time of a 12-month rolling aver age that the State of Illinois has determined to be appropriate in their Mercury Rule. Acco rding to the commenter, lengthening of the averaging time would help to acc ount 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 commen ters’ suggestions, and the rule now allows a 90-boiler operating day rolling averag e period for mercury emissions from EGUs in the EGUs designed for coal ≥ 8,300 Btu/lb subcategory that are incl uded in an emissions averaging group, along with the existing 30-boiler operating day rolli ng average periods for other pollutants in other subcategories. Should these requirements prove too di fficult for an EGU owner or operator, he or she should choose another compliance demonstration option. Note that the final rule includes work practice standards during periods of startup or shutdown, so the request to leng then the averaging time to account for such periods is moot.355 Comment 38: Several commenters (17718, 17737, 17775, 17821, 18031) state that all of the equations (Eq.1, 2, 3 and 4) seem to specify that the emission rates to be used are “determined during the most recent performance test”. According to the comment ers, the EPA should clarif y that if CEMS (i.e., PM, HCl or Hg) are being used to determine compliance with the limits, values from those monitors could be used. Commenter 17775 r ecommends that the EPA should revise 40 CFR 63.10009 to include procedures for CEMS, and make clear that units us ing CEMS to calculate average weighted emissions do not have to comply with the operating lim its for control devices in proposed 40 CFR 63.10022.

Comment 39: Commenter 17718 states that if SO 2 data via CEMS is bei ng 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 agen cy agrees that units using CEMS, including SO 2 CEMS, are eligible to partic ipate 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) boil er operating day period e nding at the end of each month s at the end of each calendar month in their calculations. Note that as mentioned elsewhere, operating limits are no longer required for units using CEMS.

Comment 40: Commenter 17718 recommends that in dete rmining an emission limit from different subcategories that emit from a common stack (40 CFR 63.10009(j)), it would be more appropriate to use the maximum rated heat input (or capacity) for th e combined units to allow more flexibility in determining the common stack emission limit.

Response to Comment 40: The agency disagrees with the comme nter’s suggestion that the rule’s emission averaging provisions need more flex ibility, and the rule has not been changed.

Comment 41: Commenter 17718 requests the EPA to clarify wh ether a “pre-test” be conducted so that a comparison can be made between a “30 day after” va lue and the initial compliance test. The commenter states that the EPA should specify the notification and submittal requirements for such a test and that the EPA should clarify what kind of documentation is n eeded for the “control technology” option to prove that it has not become “less effective.”

Comment 42: Commenter 17881 states that the provisions of section 63.10009(c), require that “the HAP emission rates observed during the initial compliance test must not exceed those being achieved on the date which is 30 days following rule finalizati on or that the control t echnology employed during the initial compliance test should not be less effectiv e for the HAP being averaged than the control technology employed on the aforementioned date.” Acco rding to the commenter, the existing units have no inherent requirement to conduct te sting or control device removal effi ciency evaluations prior to the compliance date, which is 3 year s following rule finalization.

Response to Comments 41 - 42: The agency considered the co mmenters’ 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 anEGU owner or operator needs to ensure that the “design efficiency of the emissions control technology has not changed” , as opposed to ensuring that the “control technology” has not become “less effective,” but does not sp ecify the kind of documentation an EGU owner or operator woul d be required to provide.356 Comment 43: Commenter 17718 states that the EPA should cl arify why the presen ce of an ESP would require monthly fuel content determinations.

Response to Comment 43: The comment is moot, as the rule no longer requires fuel analysis for pollutants.

Comment 44: Commenter 17725 requests revision to the compliance timeframe and the addition of a definition of an oil-fired facility. Th e commenter states that clarificati on 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 ava ilability of natural gas is often re stricted, 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 co mpliance because it may not meet the proposed limits for the initial 12-month peri od on a month-by-month basis.

Comment 45: Commenter 17725 requests that the use of liqui d fuel should not count towards the site averaging compliance demonstration when the gas s upply to the EGUs is unavailable due to factors outside of the facility’s control or when the EGU must use o il rather than gas to comply with environmental or market ba sed testing requirements.

Response to Comments 44 - 45: The agency reviewed the commente r’s suggestions, but no changes to the rule were made. The rule already defines an o il-fired electric utility stea m generating unit, and the rule maintains the eligibility criterion of having onl y those EGUs in the same subcategory as available for inclusion in emissions averagi ng. Should the commenter find that hi s EGUs would be unable to meet all emissions averaging criteria, he or she shoul d use another option to demonstrate compliance.

Comment 46: Commenter 17730 states that the emissions aver aging plan is an unnecessary element of the proposed rule and should be eliminated from the final rule.

Response to Comment 46: The agency disagrees with the comme nter’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 wh at is to be done, which units are to be included, and how compliance is to be determined, as well as help ing regulatory agencies understand a site and its emissions averaging program. Note that the rule al so requires plan submission and, in some instances, plan approval should the Administra tor or a delegated authority request one or both of those activities.

Comment 47: Commenter 17736 states that the emissions averaging provisions do not provide operational flexibility due to th e short 30-day co mpliance period.

Response to Comment 47: As mentioned elsewhere, the agency and other commenters believe the rule’s emissions averaging provision s 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 ope rating day rolling average period. Should an EGU owner or operator disagree, he or she should choose another compliance demonstration method.

Comment 48: Commenter 17775 opposes the requirement for the source to document the type, design, and operating specifications of the control devices installed on the effective date of the rule if performance test results are not available.357 Response to Comment 48: The agency reviewed the comment er’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 a pplicable emission level or control technology that is in place 60 days after the publica tion of the final rule. According to the commenter, that would require stack testing and other forms of monitoring, which a number of sour ces 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 comment er’s suggestion, and, as mentioned elsewhere, the rule now requires information, includi ng applicable emissions le vel or control technology as well as emissions test results, to be av ailable within 3 year s after promulgation.

Comment 50: Commenter 17881 states that it is not clear about how to apply emission averaging for CEMS versus stack testing results; i.e, how to compare a 30-day aver age from a CEMS to monthly stack test results.

Response to Comment 50: The agency agrees with the comment er, and the rule now describes how 30- day average CEMS values will be used with quarterly stack testing data to demonstrate compliance.

Comment 51: Commenter 17821 states that itis the EPA’s intention to prevent units from using a lower, less restrictive emissions value in an averagi ng program based on the initi al performance test than a unit was able to achieve when the final rule beco mes effective. According to the commenter, from a practical point, this provision is flaw ed and unenforceable for two reasons:

a. The EPA has specified no practical way to dete rmine what level of HAP emissions each unit is achieving on the date of the final rule without having a battery of performance te sts on each affected unit and/or a program of extensive monitoring.

b. Many units will be undergoing control retrofits, su ch as the installation of FGD systems, sorbent injection, ACI, and fabric filters th at will change the configuration of a unit. Some projects on their own could cause an increase in a unit’s emissions, such as the potential for additional particulate related to ACI.

Response to Comment 51: As mentioned elsewhere, the rule now requires information from emissions testing be received and available fo r use in emissions averaging calcula tions on or before 3 years after promulgation. As the emissions averaging complian ce approach may require additional testing or retrofits, an EGU owner or operator will need to include such factors in deciding whether or not to use emissions averaging as a means of demonstrating compliance.

Comment 52: Commenter 17881 states that the EGUs located at a single stationa ry source may not always have identical owners and/or operators contrary to sec tion 63.10009(a). The commenter states that the language at 63.10009(a) would not precl ude emission averaging amongst units under partial owners and/or operators, but perhaps the EPA should clar ify this concept in the fi nal rule preamble so as to eliminate 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 elsewher e, could be included in an emissions averaging group.

Comment 53: Commenter 17881 states that it is not clear if these provisions apply to each individual unit included in the averaging plan or all units in a ggregate and notes that if multiple pollutants are being averaged, it is possible that new control devices target ing a given pollutant (i.e., acid gases) could result in a decrease in the control efficien cy of another pollutant (i.e., PM or metals) and that control of a specific HAP could necessitate a reduction in the control efficiency for a different HAP.

Response to Comment 53: The agency believes EGU owners or operators are in the best position to weigh considerations mentioned by the commenter when deciding which compliance option to use. No change has been made to rule language regarding this comment.

Comment 54: Commenter 17881 states that the calcula tions at 63.10009(e)(1) and (2) should be dropped in their entirety as there is a major flaw in th e initial qualification cal culations, specifically, equations 1 and 2 require that the maximum rated hourly heat input (i.e., MMB tu/hr) or steam output (i.e., pounds) for each unit is to be us ed in the calculations. The commen ter states that as long as the HAP emission rate for at least one of the EGUs to be included in the averaging plan is less than the applicable HAP limit, it is theoretically possible for the average HAP emission rate for the group of units to be compliant, but that if the EPA persists in maintaining some form of these calculations, the heat input or steam output used inthe calculations should represent th e 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 comme nter’s concern, and the rule has not been changed. An EGU owner or oper ator 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 test ing. If an EGU is unavailable, an EGU owner or operator could exclude that unit from the emissions averaging group or choose another method of demonstrating compliance.

Comment 55: Commenter 17881 states that the term “heat ca pacity” is improper incontext of section 63.10009(f)(1) and (2), as heat capaci ty generally refers to the amount of heat required to change a substance’s temperature by a specified amount; the term “heat capacity” should be replaced with “heat input”. The commenter states that for Equation 3, th e term Hb is currently specified as “The average heat input for each calendar month of EGU, in units of MMBtu”; the units of MMBtu represent the total monthly heat input, not the averag e monthly heat input (which would generally be expressed as MMBtu/hr); and thus, the term “average” in the defi nition for Hb should be replaced with “total.”

Response to Comment 55: The agency agrees with the comment er that the equations 1 and 2 should refer to heat input, while equation 3 should refer to total monthly heat input, and the rule has been revised with these clarifications.

Comment 56: Commenter 17881 states that insection 63.10009(e) and (f), the equations 1 through 5 must be revised or clarified. The commenter states that all emission rates ar e 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 complian ce with pound per unit of el ectrical output limits, it359 may be appropriate to include additi onal equations which use electrical output as opposed to heat input or steam output for weighting purposes.

Response to Comment 56: The agency agrees with the commenter that an emissions rate based on electrical output, as well as on heat input, is appropriate for emi ssions averaging, and the rule has been revised to include rates ba sed on electrical output.

Comment 57: Commenter 17881 states that the paragraph (g)(2 )(vii) is confusing, wh ich states that the averaging plan must include a demonstration that co mpliance with each of the applicable emission limits will be achieved. Commenter is confused about what emission rates should be used to make this demonstration.

Response to Comment 57: The rule’s emissions averaging plan is intended to describe how each EGU emissions averaging group meets its emissions limit. One way of accomplishing this is to provide the results of each emissions test, al ong with requisite heat input inform ation and the equations and results of the equations, in the emissions averaging plan.

Comment 58: Commenter 17881 states that sect ion 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 63.10 009(i) stipulates th at individual units sharing a common stack must vent through a common emissions control system. Commenter recommends that if EGUs associat ed with the common stack are all affected units within the same category, compliance should be allowed at the comm on stack based upon treati ng such averaging group as a single stack.

Comment 60: Commenter 17881 states that equation 6 of 63.10009(j)(1) is supposed to be used to determine the common stack emission limit in case s 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 co mply with the most stringent of the applicable emission limits, this would negate the need to ca lculate custom common stack emission limits based upon prorating the emission limits for applicable subcategories.

Response to Comments 59 - 60: The agency agrees with the commen ter’s first suggestion, and the rule has been revised to treat emissi ons from a common stack used by only EGUs eligible for emissions averaging as a single unit. The agen cy disagrees with the commenter’s second assertion, and the rule has not been changed. Existing EGUs from the same s ubcategory can share a common stack and be included in emissions averaging provided that EGUs not in the emissions aver aging group (perhaps because they are new or they belong to a different subcategory) can be turned off dur ing emissions testing of the units within the emissions averaging group or that ev ery 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 co mpliance demonstration option.360 Comment 61: Commenter 17881 requests that the heat i nput/steam output records as required by section 63.10032(e) should be kept on a monthly instead of daily basis, as all related calculations in 63.10009 are on a monthly rather than daily basis.

Response to Comment 61: The agency disagrees with the comme nter’s suggestion because the rule contains a 30 boiler operating day rolling average, m eaning that heat input is required on a daily, not monthly, basis.

Comment 62: Commenter 17913 states that the emissions averaging demonstration should only be based on an averaging period consis tent with the given emission sta ndard. According to the commenter, for example, if emissions averaging is used to de monstrate compliance with a 30-day emission standard, then the compliance demonstrati on should only be based on each 30-da y compliance period. There is no need or benefit to requiring inst antaneous 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 elimin ates much of the benefits of a llowing for an emissions averaging approach and doesn’t provide benefits for faciliti es that wish to limit use of less-controlled units.

Response to Comment 62: The agency agrees with the comme nter’s suggestion to clarify how compliance is demonstrated. As rule contains a quarterly compliance assessm ent based on results of quarterly 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 co mpliance with the 30 (or 90, as discussed elsewhere) boiler operating day rolling averages for those EGUs that rely 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 c hoose another compliance demonstration option.

Comment 63: Commenter 19120 requests revision of the rule to allow for PM CEMS emissions data to be used in emissions averaging to show complian ce with metal HAP emissions. The commenter states that this request could be comp leted through a site-specific alternative monitoring request per 40 CFR 63.8(f), but due to the potentially large number of f acilities 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 appr oval from the EPA is required before a source may use the alternative monitoring procedur e, this could hinder the ability for sources to plan in advance and be proactive with installation of compliance monitoring equipment.

Response to Comment 63: As mentioned elsewhere, the rule now allows EGUs that use CEMS, including PM CEMS, to be eligible for emissions aver aging. Note that data from a PM CEMS would be used to show compliance with the filterable PM, not non-Hg HAP metals, emissions limit.

5. Opposition to discount factor.

Comment 64: Numerous commenters (17714, 17718, 17402, 17623, 17689, 17705, 17716, 17725, 17730, 17731, 17737, 17774, 17775, 17816, 17820, 17821, 17885, 17904, 18014,18025, 18449, 18498, 18023) disagree with use of a discount factor. Acco rding to the commenters, imposition of a discount factor effectively lowers the al lowable emissions for those sources without any justification. The commenters note that the EPA has used discount fact ors in other NESHAP where the agency believed there was variation in the types of units enga ged in averaging. The commenters states that361 the EGUs covered by this rule are fairly homoge neous, and the current proposal does not allow averaging between units of different subcategories. Commenter 17904 states that a discount factor will simply act as a deterrent to emissions averaging.

Comment 65: Commenters 17402 and 17716 notes the discount f actor 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 th e standards by any percentage for sources that emissions average makes an impossible compliance situation even worse. Commenter 17402 notes that the discount factor is not being appl ied in the Utility MACT to account fo r variation in types of units, as was the case where discount factors have been applied for other NESHAP. Commenters 17402 and 17623 agree with the EPA that the “homogeneous” nature of the sources eligible for the Utility MACT averaging provision makes a discount factor unnecessary. Commenters 17402 and 17623 agree that requirements to monitor and demonstrate compliance assure environmental bene fits are achieved and also make the discount factor not appropriate. Commenter 17705 conc urs that emissions averaging for EGUs that are co-located at a single facility should be straight-forwa rd. Commenter 17705 indicates that the NESHAP numeric limits and the additional requirements for control device operating parameters and fuel limits already reduce the useful ness of emissions averagi ng as a compliance option, and if the EPA further adds a discount factor, th e commenter suspects emission averaging will not be a viable compliance alternative for any sources.

Comment 66: Commenter 17648 states that usin g a discount factor would be more consistent with the HON Rule. Commenter 17648 notes thatthe HON Rule was clear that the cost savings for sources choosing emissions averaging should be considered in determining the appropr iateness of a discount factor. 59 FR 19430. The commenter st ates that more recently, the EP A relied upon its reasoning in the HON Rule to apply the 10 percent di scount in the emissions averaging provisions for ICI Boilers (see 76 FR 15619; 75 FR 32035), and that its decisions in the HON and ICI Boiler NESHAP were well founded and necessary to assure that sources opting to us e emissions averaging were emitting at levels no less stringent than would be required under a unit-by-unit MACT standar d. The commenter states that the EPA offers no rational basis for failing to adopt the same approach in this rule.

Comment 67: Commenter 17714 states that allowing averag ing without discounti ng would provide a positive incentive to encourage companies to upgrade or install controls that would achieve reductions beyond compliance requirements and a llow the utilities to achieve more cost-effective reductions overall by investing resources where the gr eatest reductions can be made.

Comment 68: Commenter 17768 states that applying a disco unt factor would essentially penalize averaging and disincentivize sources from using this option and that is also possible that averaging may lead to fewer reductions in emissions and thus fewer benefits to the general public.

Comment 69: Commenter 17928 states that averaging provid es valuable flexibili ty but is already constrained by the differing schedule s of plant outages at the same facility, as well as emissions variability. The commenter states that a ten percent penalty further limits the utility of this option.

Response to Comments 64-69: The agency reviewed the commente r’s concerns and suggestions, but decided not to change the rule by including a discount factor for t hose EGU owners or operators who choose to use emissions averaging. The agency agr ees 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 cove rs a broad number of unit types, products, and processes need not be forced upon EGUs which differ generally only in the fuel used to362 produce electricity. The agency believes that difference is accounted for in this rule by prohibiting units from differing subcategories – whic h are fuel based – from particip ating in emissions averaging. The agency believes the EGU owner or operator flexib ility coupled with the lo wer cost advantage of emissions averaging makes such a program a viable c hoice, particularly for li ttle used or soon-to-be retired EGUs. Should an EGU owner or operator di sagree, he or she should choose from among the other compliance demonstration options.

6. Support of discount factor.

Comment 70: Commenter 17648 supports the four criteria required by the EPA to participate in emissions averaging and states thatthe EPA should go further and also apply a discount factor, as it has done in prior NESHAP. Commente r 17648 states the proposed emissi ons averaging provisions do not sufficiently recognize and compensate for the fact that aver aging may not assure th at all units are being controlled aggregately to a degree no less stringent than they would need to be controlled if they were controlled individually. In failing to incorporate a discount factor , Commenter 17648 states the EPA may unfairly advantage multiple-unit sources ov er 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 va riability of single-unit, single measurem ents 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 thUPL for facilities that average would be closer to the actual average of the top 12% than the 99 thUPL 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 operati ng controls that would be required for individual sources. The commenter states that incorporating a discount factor is important to maintain a level playing field, to ensure that sources will in fact in stall controls that reduce emissions while providing flexibility to do so in the most cost-effective manner possible and that it is al so 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 th e subcategory.

Comment 71: Commenter 17648 disagrees with the EPAs s uggestion that homogeneity of sources makes a discount factor unnecessary, and notes that the substantial subcategor ization into 11 different subcategories in the ICI Boiler NESHAP undercuts the EPA’s rationale for not proposing a discount factor in the Toxics Rule. In th e ICI Boiler NESHAP, commenter 17648 st ates that the subcategorization reduced variation among sources within the subcat egory, and that NESHAP nonetheless retained a discount factor. 76 FR 15612. Commenter 17648 states that the EPA’s rationa le also fails to account for the mathematical/statistical basis for requiring a lo wer limitation when averaging is allowed. According to the commenter, by basing the in itial limit on the 99% UPL rather than the more conventional 95 percent UPL in both rules, the EPA has already accounted for any greate r variability with in 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 so mewhat smaller discount, and would not support eliminating the discount altogether.

Comment 72: Commenter 17648 supports the emissions cap fo r any individual regulated unit operating above the emissions limitations thatwould apply to that unit at th e level achieved 30 days after promulgation of the Toxics Rule, however, this ca p alone will not achieve sufficient assurance that emissions averaging will be at least as stringent as the conventional MACT.363 Comment 73: Commenters 17648 and 17789 state that prio r NESHAP have relied on additional safeguards such as the cap only as a supplement to th e 10 percent discount and ur ge the EPA to continue to use the criteria to limit averaging.

Comment 74: Commenter 17718 states that imposition of a discount factor effectively lowers the allowable emissions. According to the commenter, a discount factor is unnecessary because the proposed rule incorporates a number of other safety factors that obviate the n eed for a discount factor.

Comment 75: Several commenters (19536, 19537, 19538) states that the EPA should add a discount factor requiring lower emissions from plants which comply by averaging the emissions of multiple units. According to the commenter, the agency’s variability an alysis is based on emissions from three test runs from a single boiler, operating over a 2 (Hg and PM ) or 3 (acid gases) hour period, and by allowing averaging, the EPA is effectively allowing compliance to be measured based upon a far larger number of test runs, and operating hours – over which there will be far less variability and thereby allows sources to emit hazardous pollution well in ex cess of the actual emissions of the best performing similar plant or plants. The commenter states that the EPA should, as a general matter, establish standards that are consistent in their form with t hose the agency uses when it assesse s variability; its standards will not otherwise reflect the performance of the best source or sources. According to the commenter, in this instance, if the EPA allows units to combine thei r emissions for purposes ofcompliance, it should recalculate the variability associated with multip le-unit emissions, and establish a corresponding “discount” in the standards for multiple units.

Response to Comments 70-75: The agency considered the commente rs’ suggestions but did not change the rule to include use of a discount factor. As mentioned else where, the agency agrees with the suggestion that other safety factors in the rule obviate the need for a discount factor. The agency notes that while emissions averaging could begin upon promulgation of the rule, it must start within 3 years of promulgation. Finally, the agency disagrees with the suggestion that another variability component need be considered for those EGU owners or operators who choose to engage in emissions averaging; the current UPL analyses was develope d to take factors such as thos e mentioned by the commenter into
account.

7. Facility averaging provisions should be mo dified to allow for alternative mass limits.

Comment 76: Commenter 17877 supports the idea of facility emission averaging, in as much as it may provide real operational flexibilityto sources. According to the commenter, however, the averaging provisions of the proposed rule are so restrictive that they are unlik ely 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 complicat ed task of compliance even more difficult. The commenter states that there is no legitimate reas on for imposing a 10 percent penalty on sources that seek to average emissions.

The commenter states that total emissions from a si ngle facility have the same impact on public health regardless of whether each unit at the facility meet s the MACT limits or all units meet the MACT limits in the aggregate -- the total emissions from the facility are the same, and the 10 percent penalty on operational flexibility has no public health benefit.

Comment 77: Commenter 18788 finds that in practice the draft model for source averaging would penalize a facility when the best performing units are not operating. The comm enter states that at a facility where eligible units ar e combined under a weighted averag e emission rate, the emission rate364 average of the operating units will calculate higher when the best performing un it(s) are shut down and emitting no HAP what-so-ever, and that this effect is especially pronounced when the best performing unit is the largest among the group.

The commenter presented Example 1 below of a hypothetical facility, with all units online and in compliance with the total particulate limit of 0.03 lb/MMB tu on a facility basis.

Example 1: All Units Online

In the second example, the newest and best perf orming unit is offline and mass emissions from the facility are decreased by as much as 30% as compar ed to Example 1, but the facility is now out of compliance with the total PM limit on a weighted average basis. According to the commenter, the facility is therefore penalized for emitting less.

Example 2: Unit 3 Offline

Commenter 17877 suggests that EPA could address the av eraging penalty in one of two ways: First, the EPA could allow for the facility total heat input to be fixed at all times inthe denominator of the averaging equation for each unit. Ac cording to the commenter, for the hypothetical facil ity, the hourly averaging calculati on 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, th e facility is actually encouraged not to operate units and emit less, and enforceability is strengthe ned and facility compliance is simplified since the MACT limit can be clearly and consistently compar ed to the Facility Average Emission Rate at all times. According to the commenter, as currently draf ted, the facility average me thod is of little use and creates a constant moving target for th e agency and the regulated facility.

The commenter states that as an alternative, or inaddition to the above, the rule could be written to include an alternate mass emission limit for the facil ity. According to the commenter, in this case, the annual mass emissions would be based on the allowed emission rate multiplied by the hourly heat input of the unit over the course of a year (included in document).

The commenter states that both of the proposed change s to the facilityaveraging provisions listed above fit squarely within the generally applied limits on the “scope and nature” of past rulemakings where facility averaging is allowed. The commenter asse rts that if the EPA is serious about providing operational flexibility to facilities, then it must make substantial revisions to the averaging provisions of the rule.

Response to Comments 76 and 77: : While the agency appreciates support for use of emissions averaging without a discount factor, as mentioned elsewhere, the agencydisagrees 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 intr oduce a new emissions limit based on mass only without appropriate notice and comment on that suggestion. The rule’s emissions limits remain unchanged. Should an EGU owner or operator find the rule’s existing emissions averaging procedur es 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, 19537, 19538, 18023

1. Coal switching.

Comment 1: Several commenters (16705, 17400, 17697, 18038, 18575) point out that the proposed rules assume that all coal types canstill 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 ve ry restricted in fuel choices, and the GPA must rely on oil for the near to midterm.

Comment 2: Commenter 18023 states that while decisions w ill be made to change the fuel supply for some coal-fired units to natural gas-fired units based on the economics of available alternatives, it is important to note that any decisions to change the fu el for an existing coal unit to natural gas or oil would never be economic when compared to business as usual and would only occur because of the requirements imposed by the proposed rules. Commenter states that changing fuel to natural gas also presents important reliability cons iderations, including the capability fo r back-up fuel, such as oil, in case of supply disruptions because natural gas cannot be stored on-site.

Comment 3: Commenter 17881 states that rail congestion an d increasing transportation cost limit the viability of the PBR coals option. Commenter adds thatthe 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 th at plants burning Texas lignite will need to remove mercury at high leve ls to comply, and switching to western subbituminous coal could significantly decrease mercury emission s due to Hg content of coal and improved ACI performance.

Response to Comments 1 - 4: The EPA has not mandated fuel swit ching as a compliance option – nor has the EPA used fuel switching to set emission floors or as a ‘b eyond-the-floor’ option. The EPA does, however, recognize that fuel switchi ng is a legitimate compliance opti on that will be considered and likely implemented by some facilities. Low sulfur sub- bituminous is now widely available and is burned across the contiguous U.S. states to comply with 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-f iring sub-bituminous coal. The EPA maintains that control technology options are available to retrof it existing facilities to allo w them to meet the existing source emission limits without having to switch fuels.

2. Opposition to fuel switching to natural gas.

Comment 5: Commenter 17881 states that natural gas transmission and storag e infrastructure does not exist to support the op tion of fuel switching to natu ral 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 (currently rated at 6 38 MW each, but less than 5 percent capacity factor) would require these units to be de-rated 50 percent to about 300 MW each or have significant boiler modifications to allow the firing of 100 percent natural gas at the boiler desi gn capacity. According to the commenter, the natural gas supply infrastructure w ould have to be significantly upgraded in order to supply the volume of gas needed to operate the units at full capacity. The comm enter states that these units are called on only when electric load demand is high, as in the summer of 2011, and perform a vital role to meet load demand.

Comment 7: Commenter 17901 states that natural gas units are not covered under the proposed Utility MACT, and the EPA has given no indication that it will establish any stringent limits for natural gas units comparable to those required from coal-fired un its. Commenter states that the proposed MACT is a continuation of an ongoing pattern of disparate treatment for coal util ities. Commenter disagrees with the EPA’s consideration of requiring fuel switching from coal to ga s as a potential “beyond-the-floor” control, although the EPA properly rejected the us e of natural gas as a control option. Commenter disagrees with consideration of fuel switching to an entirely different fu el with totally different delivery systems, types of combustion, and emissions control sy stems 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 ga s may not be available as a fuel for many EGUs.” Commenter also states that the EPA notes that th e relative cost of a switch to natural gas from coal was many times higher than the cost to install additio nal 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 c oncurs with the EPA’s propos al not to require fuel switching as a “beyond-the-floor” op tion for the EGU MACT. Commenter agrees with the EPA reasons for not requiring fuel switching to natural gas, whic h is delivered through pipe lines, is not available everywhere in the U.S., where pipe lines do exist, natural gas may not be available throughout the year (e.g., the heating season), and th e cost of such fuel switchi ng 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 swit ching 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, re cognize that fuel switching is a legitimate compliance option that will be considered and likely implemented by some f acilities. However, the EPA maintains that control technology options are available to re trofit existing fac ilities to allow them to meet the existing source emission limits without having to switch fuels.

3. Concerns with ability to meet liquid fuel-fired limits.

Comment 9: Commenter 17912 disagrees with the EPA’s s uggestion that oil-fired units have the compliance option of using low-HAP o il, citing that the EPA fails to id entify anywhere in the ICR fuel data any oil sufficiently low in HAP that a liquid fuel-fired boiler has used this method to comply.

Comment 10: Commenter 18502 points out that compliance with the proposed metals and HCl limits by residual oil-fired EGUs assumes a level of consistency in flue gas composition that has not been demonstrated as compared to coal-fired uni ts. According to the commenter, there are some key differences between coal and oil relative to comp liance with the proposed emission limits:368 a. The concentrations of metals and chlorine in coal can be measured, but are generally below analytical detection limits for residual oil. The commenter stat es that during ICR testi ng, quantifiable levels of chlorine were detected in the fuel used by just tw o of the eight EGUs tested and nickel was the only metal detected in more than a quarter of the samples.

b. Coal is supplied to an indivi dual EGU from suppliers in defi ned geologic and geographic areas that have definable fuel characteri stics, whereas deliveries of crude oil to refiners and fuel oil to consumers are based on international market cond itions. The commenter states that while fuel specifications regarding some parameters are possible (e.g., sulfur c ontent), 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 co rrelation between reductions in PM and reductions in metals is not as well defined.

Response to Comments 9 - 10: As noted elsewhere in this document , EPA has reassessed its analysis of the oil-fired EGU data. The EPA believes the limits inthe 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 altern ative for the acid gas HAP of measur ing the moisture in the oil in lieu of testing for HCl and HF.

4. Opposition to conversion of li quid-fired EGUs from RFO to DFO.

Comment 11: Commenter 17725 points out several challenges to converting liquid-fired EGUs from residual fuel oil (RFO, oil grades N o. 4, No. 5, and No. 6) to distillate fuel oil (DFO, oil grades No. 1 and No. 2), and states that thes e 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 requirem ents (e.g., flash point, viscosity po ur point) that affect different storage requirements. According to the commenter, many RFO storage facilities have heated storage tanks, an oil recirculation system, and heated conv eyance piping to the boiler, and conversely, the storage of DFO does not require heated systems.

b. According to the commenter, combustion of RFO and DFO is not interchangeable within a boiler, and a fuel switch to DFO requires significant modificati on. According to the commenter, because of the different physical characteristics, the combustion process equipment is designed and installed to reflect the characteristics of the fuel being combusted. The commenter states that bo iler burners and burner tips used to combust RFO cannot be used to combust DFO and that the converse is also true. The commenter states that once introduced to the boiler, proper combustion of RFO can only be obtained by using steam atomization or mechanical atomization, and c onversely, combustion of DFO does not require an atomization system.

c. According to the commenter, an EGU using RFO w ill not have the same output (steam flow and the resulting generation) using the sa me amount of DFO because of th e 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 w ould entail modifications to the boiler combustion system, as well as a conversion of the oil storag e tank system, including replacement of burners and burner tips and modifications to the burner manage ment system. The commenter states that prior to performing the physical changes, a boiler combustion study must be performed to ensure the burners are properly designed for the boiler’s configuration.

e. According to the commenter, to prevent contamin ation from RFO, an exis ting RFO storage tank and the associated piping must be cleaned.

f. According to the commenter, change out of the piping and pumps are require d so that the required amount of DFO (which has a lower heating value) can be delivered to the boile r 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 storag e tank systems would need retrofitting to provide adequate secondary containment for the lower viscos ity DFO to address regulatory requirements for fuel storage (i.e., SPCC, OPA-90). Acco rding to the commenter, this is a significant undertaking for large RFO tanks, as they typically use earthen secondary containments, since RFO does not permeate into the soil when spilled; whereas, converting to DFO st orage would require expensive impermeable liner installation and other changes. Co mmenter 17725 cites an example cost estimate for liner installation for a relatively small two million gallon tank being from $500,000 to $800,000 and adds that their Oswego facility has multiple 11 million gallon tanks, the cost of which to line one of these tanks would be on the order of two to three million dollars.

i. According to the commenter, the capital invest ment for a conversion to DFO is site specific but, NRG estimates that the conversion cost for th eir facilities ranges from $12 – 17/installed kW per site, and this is only for the capital expense portion.

j. According to the commenter, there are additional costs for testing the un it 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 an d testing will require EGU full load operations for approximately 40 hours. A 400 MW unit can consume approximately 500 ga llons per minute of fuel, and that for the 40 hours of tuning/testing, this relate s 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 th at the additional cost for the 29,000 barrels of DFO is over $500,000, based on the 5-year average price presented (Commenter included Table 2.3.2, FiveYear Average Fuel Prices at New York Ha rbor, Docket No. The EPA-HQ-OAR-2009-0234).

k. The commenter states that beyond the capital expenditures to retrofit units for DFO, the use of DFO rather than RFO will increase the dispatch price of the EGU. According to the commenter, for an EGU with a 10,000 Btu/kW-hr heat rate, the disp atch price for the unit based on fuel alone will increase between 35 and 45 percent. The commenter st ates that as oil-fired EGUs are generally high on the supply curve due to their relativel y high heat rates, they are primarily dispatched for reliability at a low level in preparation for spikes in demand (when their output will be increased), to cover for known outages of lower cost units, or to provide transm ission support. The commenter states that conversion to DFO will increase their production costs up to 45% or more and put significant upward pressure on electric costs during times of system duress.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 emissi ons will be in the same range as those DFOfired units setting the standard. Th e commenter states that it is highl y doubtful that anengineering and construction firm would provide a gu arantee that a conversion to DFO wo uld 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 po ssibility of making a signi ficant capital investment with no assurance of ultimately achieving complian ce, the EGU may be forced to retire as the uncertainty is too great. The comme nter states that EGUs that may or could comply would simply not make an investment that large without reasonab le 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 distil late oil. However, we would also note that other co mmenters indicate that the switch is not as extreme or burdensome as commenters here note. Further, we are not subcategorizing distillate vs. residual oil in the final rule. We note that all of th e distillate oil-fired EGUs for which we have data are in the limited-use subcat egory noted elsewhere in this document. The MACT floor pool for liquid-oil fired EGUS is comprised of sources burning residual oi l-fired EGUs with ESPs. Therefore, EPA maintains the final limits are achieva ble by residual oil-fired E GUs without the need for oil switching, although such switching is always an option to an E GU that does not want to install PM controls.

5. Opposition to use of proposed rule /limits to necessita te fuel switching.

Comment 12: Commenters 17813 and 17930 discourage the setti ng of limits that are so low as to possibly necessitate fuel switching, st ating that this would be a requi rement 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 a dd that lignite-burning pow er 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 deli very, transportation, and storage, not to mention boiler desi gn. According to the commenters, bo ilers are designed for specific types of fuel, as well as ranks with in a fuel type, and there are limits due to the heat values and amount of coal being burned that restrict lignite power-plants from increasi ng non-lignite coal consumption. The commenters state that these issues were obviously considered and given weight when the EPA developed the subcategory for <8,300 Btu/lb coal.

Comment 13: Commenter 17840 states that the EPA should articulate how a future plant can comply with all of the proposed standard s, and draws a conclusi on that the EPA is pr oposing a beyond-the-floor fuel switching measure for new sources, while inc onsistently rebutting manda ting fuel switching from coal to natural gas as “an unreasonable regulatory option.”

Comment 14: Commenter 17930 states opposition to requiremen ts that impose fuel switching and notes that fuel switching is not a viable option for many lignite units in Texas. Co mmenter states that for many, the necessary infrastructure (e.g., rail lines, unl oading stations, transport areas) does not exist to begin burning other types of coal. Co mmenter states that the EPA’s cost estimates for facilities to switch to other coal types and construct th is infrastructure is incomplete and provides the following points as flaws in the EPA cost analysis:371 a. According to the commenter, the EPA’s cost estim ate does not include all re quisite infrastructure costs (e.g., dust collection, conveyors, fire prot ection, ventilation, ESP performance, water cannons, significant boilers modifications to burn 100 percent PRB coal.

b. According to the commenter, the EPA has not ade quately taken into cons ideration the potential escalation of PRB coal and transportation prices once the coal fleet responds to this and other pending regulations (e.g., the Cross-Stat e Air Pollution Rule [CSAPR]).

c. According to the commenter, the EPA’s cost predic tion for the “beyond-the-floor” limit is far too low because the EPA fails to include the cost of installing fabric filters inthe price analysis. The commenter states that the EPA’s cost analysis assumes that a ll units within this subcat egory will require capital investments in fabric filters that are attributable to the proposed MACT standard for PM (as a surrogate for non-Hg metallic HAP). According to the commenter, this analysis determines the marginal capital costs attributable to the BTF opti on requiring installation of ACI syst ems to reduce Hg emissions to 4.0 lb per trillion Btu (Commenter cites a Beyond th e 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 necessari ly be installed at these units. According to the commenter, while surrogates may be a means of complia nce 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 t echnology installed to control Pollutant A (which incidentally controls for PollutantB), while counting the benefits of the limitation on Pollutant B. The commenter states that benefits cannot be c ounted twice, while costs only counted once.

Response to Comments 12 - 14: The EPA has not mandated fuel switching as a compliance option – nor has the EPA used fuel switch ing to set emission floors or as a ‘beyond-the-floor’ option. The EPA does, however, recognize that fuel switching is a legitimate complian ce 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. st ates for compliance with existing SO2 standards. The EPA is aware of facilities in the East (e.g., Flor ida, Georgia, Maryland, Connecticut , and Delaware) and in the West (e.g., Oregon, Washington, and Arizona) that are fi ring or co-firing sub-bituminous coal. Control technology options are available to re trofit existing fac ilities to allow them to meet the existing source emission limits without having to switch fuels. We ma intain that the final limits were established in accordance with the statute and have cons idered costs to the extent required.

6. Request for expansion of provision s for exclusion from requirements.

Comment 15: Commenter 17737 agrees with the provision to excl ude units that did not fire coal or oil for more than 10.0 percent of the average annual heat input during the previous 3 calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar years from subpart UUUUU. However, Commenter r ecommends that this be expanded to include units that have burned coal for more than 10.0 pe rcent during the 3 years immediat ely following promulgation of the final rule, or 15 percent during any one of those year s, but elect to switch to burning natural gas for at least 90 percent of the annual heat input beginning prior to the date the units must be in compliance. Commenter adds that this provisi on should not require the unit(s) to be modified by making the coal burning capabilities inoperable or needing to modifythe permit to remove the coal burning capabilities and cites that the proposed definition of “fossil-fuel fired” unit (76 FR 25020) seems to require that the372 owner physically remove all coal burning capabilities and that coal bu rning would not be allowed in the permit. Commenter states that they (TEP) own a nd operate H. Wilson Sundt (Sundt) Unit 4, which is capable of burning coal and/or natural gas, and TEP w ould like to have the opti on to use this flexibility to bum different types of fuel. TEP w ould like to maintain the ability to continue to bum coal in this unit for the next 3 years but switch to na tural gas prior to the date the unit would need to be in compliance with subpart UUUUU. According to the commenter, unde r the present proposed ru le, TEP would still be subject to the subpart UUUUU mon itoring, reporting, and recordkeeping requirements even if it ceases to burn coal prior to the compliance date, pos ing 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/opera tor should be required to maintain records of the quantity and type of fuel burned to assure that at le ast 90 percent or more of the heat i nput is from natural gas and that the operating permit would be revised to require the owne r/operator to apply for a permit revision to comply with the requirements of subpart UUUUU prio r 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 owne r would need to convert the unit to 100 percent biomass or natural gas within thr ee years and remove all capability to burn coal or oil. Commenter suggests that alternativel y, the unit could convert to biomass or natural gas by 2012 and ensure that the heat input from coal or oil in 2012, 2013, and 2014 is below the annual 15 percent heat input requirement and the 3-year requirement of 10 percent heat input.

Comment 17: Commenter 17756 recommends that the EPA revi se the definition to change the “lookback” period to begin three years after the unit’s final compliance da te. According to the commenter, this change would not penalize a unit that switches to natural gas and re tains the ability to combust coal or oil for having burned coal or o il in the period before compliance. Commenter also suggests that a unit that switches to natural gas and later switches back to highly controlled coal use should not be in violation of the 3-year average for the years it was bur ning 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 provid e absolute assurance that units converted to natural gas or biomass are exempt from the rule.

Comment 19: Commenter 17902 recommends that section 63.9981 further clarify that existing coal or oil-fired EGUs that combust natural gas as of th e required compliance date are not subject to the requirements of subpart UUUUU.

Comment 20: Commenter 17904 recommends that the EPA shoul d revise the appli cability language to allow generators to retain the opti on of simply restricting dual fuel-fired units as a compliance strategy – but they should not be forced to begin fuel restri ctions immediately. Accordi ng to the commenter, this would amount to making the compliance date equivale nt to the effective date of the rule. Commenter recommends that the EPA should revise the definiti on to clarify that any un it which actually burns 90 percent natural gas during a calendar year is excl uded 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 th e EGU MACT that a unit that burns on average at least 90 percent of fuel as natural gas during, “the previous 3-year period,” is considered natural gas-fired and therefore not subject to the EGU MACT. Howeve r, the commenter requests that the EPA add to this provision that units that sw itch to natural gas by the compliance deadline and373 continue to operate that way th ereafter should also not be subj ect to the oil-fired EGU MACT requirements.

Response to Comments 15 - 21: As noted elsewhere in this doc ument, the EPA has revised the definitions to account for the “look b ack” provision noted by commenters.

7. One-year extension for compliance.

Comment 22: Commenter 17852 concurs that a 1- year extension can be appr opriate when a utility is undertaking a technically complex pr oject, such as converting an ex isting coal-fired boiler to burn natural gas or building a new NGCC, but only where the utility has timely gone about such action and can demonstrate that such action does in fact require an extra year to comply. Commenter adds that there are many things that utilities can do to achieve compliance within the 3-year time-frame, and cites the following:

a. Various sources have suggested th at controls can be installed with in the 3-year time-frame, including, Exelon Corporation which has said in reference to the Bo iler 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 un its 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 thatnew natural gas generation can be built within the mandated 3-4 year time-frame.

Response to Comment 22: Responses to comments of this type are provided in the preamble to the final rule.

8. Blending fuels.

Comment 23: Commenter 17774 points out that the proposed Utility MACT definitions of various regulated subcategories seem to overlap in cases where a unit is not exclusively burning coal and requests clarification in the regula tion of sources which blend fuels to clearly delineate which standards apply in cases where fuel blendi ng is employed. Commenter cites an example where a coal-fired unit which burns more than 10 percent petcoke could arguably either fa ll under the solid oil-derived fuel subcategory or the coal -fired subcategory:

a. The commenter states that the proposed rule define s “oil” as “crude oil or petroleum or a fuel derived from crude oil or petroleum, includi ng distillate and residual oil, so lid oil-derived fuel (e.g., petcoke) and gases derived from solid oil-derived fuels (not meeting the definition of natural gas).” The commenter states that the proposed rule further defi nes the “unit designed to bur n solid oil-derived fuel subcategory” as “any EGU that burned a solid fuel de rived from oil for more than 10.0 percent of the average annual heat input during the previous 3 calendar years or any on e of those calendar years, either alone or in combination with othe r fuels.” According to the commenter, consequently, if a coal-fired unit burns more than 10 percent petcoke, it could arguably fall into the solid oil-derived fuel subcategory.374 b. The commenter states that however, the coal-fired subcategory also indicates that it includes units burning petcoke. The commenter states that the proposed rule defines a coal-fired unit as a unit that “burns coal or coal refuse eitherexclusively, in any combination toge ther, or in any combination with other fuels in any amount.”

Commenter 17774 urges the EPA to clarify which standa rds apply to units burni ng coal and petcoke and suggests that the EPA require affectedsources to comply with the standa rd applicable to the majority of fuel burned (e.g.

, greater than 50 percent).

Comment 24: Several commenters (19536, 19537, 19538) provide s comment in response to the EPA’s request to comment on, “whether th e proposed rule should address how sources that change fuel input (e.g., burn solid waste or biomass), or otherwis e take action that would change the source’s applicability...must demonstrate co ntinuous compliance with all app licable standards.” Commenters state that EGUs designed to fire solid fossil fuels burn a mixture of coal types as well as other solid fuels including solid oil-derived fuels (pet coke), biomass, and other solid fu els. Commenters suggest that any subcategorization must be based on design differences which materially affect the availability of cleaner fuels, or other methods of reducing pollution. Co mmenters take the position that where a plant voluntarily (or for economic reasons) chooses to bur n a high-polluting fuel, that decision should not affect the standards applicable to the plant, with one exception: the ag ency is obligated to distinguish between EGUs that are waste combustors (and thus subject to strict er standards governing waste combustors) from EGUs that are primarily fossil-fueled. Commenters concur with the EPA’s proposed rule definitions for the so lid fuel subcategories defining coal fired units as, “electric utility steam generating unit meeting the defin ition of ‘fossil fuel-fired’ that bur ns coal or coal refuse either exclusively, in any combination toge ther, or in any combination with other fuels in any amount (76 FR 25122, Proposed section 63.10042 definitions). The commenters state that “Fossil fuel-fired,” in turn, is defined as, “to the extent that an EGU that is capable of burning primarily coal or other solid fossil fuels to generate electricity, and also el ects to co-fire biomass to meet so me other statutory requirement, it must continue to meet the MACT limits for the sub category in which it is lis ted.” Commenters add that this is particularly important for biomass, as burning green wood produces mo re of various regulated HAP than does burning coal (Commenters cite Fi gure 1 in Docket No. The EPA-HQ-OAR-2009-0234). Commenters also add that it would be unlawful for the EPA to finali ze a MACT subcategory that would worsen the HAP emissions profile of the EGU be yond what it would be absent the biomass burning.

Response to Comments 23 - 24: As noted elsewhere in this doc ument, 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 Ru le 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 ve ry quickly to provide clean en ergy 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 sector. Commenter recognizes that the EPA ma y not consider it realistic to requ ire all coal plants to shift to natural gas by setting a beyond-the-floor standard ba sed on natural gas combustion; however, points out that some owners and operators may find that c onverting to natural gas (r etrofit, repowering, new construction, or use of underutilized existing plants ) is a cost-effective compliance strategy. Commenter concludes that efficiency benef its of NGCC combined with natura l 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 IPM results that no new pulverized co al capacity is added thr ough 2030, even in the base case, while 68 GW of NGCC capacity is added unde r 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 curren t data to appropriately characterize the most up-to-date natu ral gas infrastructure, supply, cost , and technology associated with natural gas availability, and cites several areas of disagreement withthe EPA’s assumptions used in development of the Proposed Rule:

a. For existing EGUs, Commenter 17810 cites that the EPA determined that fu el 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) increa sed fuel costs cause a unit’s total incremental cost of electricity (COE) to be signi ficantly higher compared to the incremental COE of other options. Commenter 17810 states that the EPA included only two documents to justify these conclusions ( Technical Support Document [TSD] for the Transport Rule [sic] , “Coal-to-Gas Conversion (C2G)” (March 4, 2011) and Documentation Supplement for EPA Base Case v4.10_PTox – Updates for Proposed Toxics Rule (March 2011), available at http://www.epa.gov/airmarkt/progsregs/epaipm/docs/suppdoc.pdf , Docket ID No. The EPA-HQ-OAR-2009- 0234). Commenter states that both these documents are associated withthe cost of coal-to-gas conversi on, but that neither addresses the natural gas supply issue, and cites several refere nces to the contrary (D ocket ID No. The EPA-HQOAR-2009-0234). Commenter 17810 states th at there does not appear to be any evidence in the record to support the conclusions that natura l gas pipelines are not available in all regions of the U.S., natural gas may not be available as a fuel for many EGUs, and even where pipelines provide access to natural gas, supplies of natural gas may not be adequate , especially during peak demand (e.g., the heating season). The commenter states that currently availa ble information refutes th e 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 bot h the U.S. Energy Information Administration (EIA) and the MIT Energy Initiative indicate sufficient suppl y to meet increasing demand for natural gas-fired EGU capacity. According to the commenter, the actua l delivery of supply to a specific consuming market occurs hand-in-hand with the development of demand, and the delivery of supplies into the vicinity of an EGU should not be expected to precede the demand from an EGU by a period of years.

i. According to the commenter, the EPA’s analysis of costs of constructing new laterals to distribute gas to existing coal-fired units demonstrates thatsome coal-fired power pl ants have relatively inexpensive access to natural gas mainlines, while ot her coal-fired power plants will have a more difficult time accessing natural gas mainlines, but th e analysis appears to contradict the EPA’s statement that natural gas pipeline s are not available in all regions of the U.S. The commenter states that the average coal-fired boile r at a power plant that does not already have access to natural gas would need 57.4 miles of pipeline to meet natural gas demand, and the median pipeline requirement is 26.2, meaning that 50 percent of coal-fired power plants woul d 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 notsupport the idea that natural gas is unavailable.

ii. According to the commenter, the recentl y released INGAA Foundati on study of midstream infrastructure needs indicates th at natural gas producers are play ing an important role in funding needed pipeline infrastructure as they comp ete 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 highly integrated transmissi on and distribution grid that can trans port natural gas to and from nearly any location in the lower 48 States.”

iv. The commenter states that Department of Energy figures indicate that the interstate and intrastate transmission network feeds over 1.1 million miles of regional lines in some 1,300 local distribution utility networks, collectively delivering natural gas to 62 million customers in the U.S.

v. According to the commenter, the natural gas industry has shown an ability to respond to changing market conditions. The commenter states that ac cording to EIA, 3,893 miles of new natural gas pipelines were a dded in 2008 alone.

vi. The commenter states that the recent INGAA Foundation study includ es FERC data showing from January 2000 to February 2011, interstate pi peline companies received approval to construct over 16,000 miles of interstate pipelines and add an additional 14,600 miles of expansion pipeline. According to the commenter, the INGAA Foundation projects similar development over the next 10 years.

vii. The commenter states that according to a rece nt report issued by the MIT Energy Initiative on the Future of Natural Gas (“MIT Natural Gas Repor t”), the production and deliv ery 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 pipelin e network over the last several years; between 2005 and 2008, pipeline capaci ty additions totaled ove r 80 billion cubic feet per day (Bcfd), exceeding those from the previous four-year period by almost 100 percent. Additions of 44.5 Bcfd in 2008 alone exceeded total additions in the five-year period between 1998 and 2002. According to the commenter, MIT’s Interim Report to the Future of Natura l Gas noted, “On the gas infrastructure side, concerns have been raised about the availability of gas pipeline capacity for the additional gas requirements of this option [displacement of coal generation], but preliminary analysis indicates that the industry has the ability to meet the needs for additional pipeline capacity.” The commenter states that the MIT Natural Gas Report concluded that: (a) there are abundant supplies of natural gas in the U.S., despite their relative matur ity, natural gas resources continue to grow; (b) the role of natural gas is likely to continue to expand under almost all circumstances, as a result of availability, utility, and comparatively lo w cost; and (c) increas ed utilization of existing NGCC power plants provides a relatively low-cost short-term opportunity to reduce U.S. carbon dioxide emissions by up to 20 percent in th e electric power sector and significantly reduce sulfur dioxide, nitrous oxide, particulates, and merc ury with minimal additional capital investment in generation and no new technology requirements.

viii. The commenter states that the FERC also not ed significant recent increases in the storage capacity for natural gas. The commenter states th at more than 107 Bcf of incremental working gas capacity was added in 2009, includ ing more than 50 Bcf in the Gulf region. The commenter states that traditional production area storage allows supplie rs to respond more adep tly to market signals, and as a result, those signals are moderated. The commenter states that reporting on 2010 storage, the FERC said, “Natural gas storage levels were high for much of the year and reached record levels in November.”

ix. The commenter states that generally speaking, estimates of the available domestic supply of natural gas have expanded significantl y over just the past five years. According to the commenter, in a 2009 Report addressing the supply of technically r ecoverable natural gas in the United States at377 2008 year-end, the Potential Gas Committee reported that the currently ava ilable total supply of natural gas was 1,836 trillion cubic f eet (Tcf), which represented an increase of 39 pe rcent (516 Tcf) over the Committee’s year end estimate for 2006. Th e 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 resour ce estimates from several sources, including the 2009 Potential Gas Committee Report, and assume d a mean remaining resource base of approximately 2,100 Tcf. The commenter states that the U.S. EIA recently estimated that annual production of natural gas will increase by 25 percent from 2009 to 2035. According to the commenter, many of these sources attribute this dram atic increase in recoverable natural gas supplies in large part to the discovery of significant shale gas deposits and advances in technology for recovery of gas from these resources.

x. The commenter states that studies have concl uded that not only is there an expanding supply of natural gas, but due to declining costs of recovering that gas, dome stic gas production is likely to increase significantly. According to the commente r, as summarized in a r ecent report issued by the Bipartisan Policy Center and American Clean Sk ies Foundation, “While estimates of supply have increased, the cost of producing shale gas has decl ined as more wells have been drilled and new techniques have been developed and field tested. The co mmenter states that the MIT study estimated that between 250 and 300 Tcf of shale gas can be produced at prices below $8/MMBtu (in 2007 dollars), and more recently, ICF International estimated that almost 1,500 Tcf are available at $8/MMBtu, while 500 Tcf are availa ble at $4/MMBtu and 1,500 Tcf ar e available $5/MMBtu (ICF Figure 1 included in Dock et EPA-HQ-OAR-2009-0234).

xi. According to the commenter, significant changes have occurred both with respect to natural gas supplies and storage infrastructure over the past 10 years that alleviat e heating season supply concerns. With respect to storage, the co mmenter states that FERC reports in the State of the Markets Report that in late November 2009, U.S. inventorie s were 99 percent of capacity, suggesting that there is sufficient gas rese rve capacity to address demand sp ikes 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 pro duction, in which a producing well needs to be kept “on” in order to maximize the amount of recoverable gas, production from shale wells is far more elastic, allowing producers to ramp up produc tion in response to price signals , thereby helping to avoid the dramatic price swings that happen when it takes longer for production levels to respond to changes in demand.

b. For new EGUs, Commenter 17810 states that the EPA fails to consider best available data on supply and cost when identifying beyond-the-floor optio ns. According to the commenter, in making the determination that fuel switching to natural gas is not a reasonable option, the EPA falls back on a generic statement that natural gas supplies are not available in some areas; whereas, commenter posits that it establishes with th e above references that natural gas is widely available throughout the country and new power plants can be site d with pipeline capacityand proximity as a key consideration. Commenter states that the EPA also suggests that “limited emissions re ductions in combination with the high cost of fuel switching and consid erations about the availability and technical feasibility makes this an unreasonable regulatory option th at 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 ga s instead of coal, and suggests that the EPA evaluate the cost of a new NGC C unit for providing base load power as compared378 to a new advanced coal-fired boiler. Commenter c ites the EPA’s modeling in support of the rule, which projects no new advanced coal-fir ed boilers to be constructed th rough 2030, even in the base case scenario without imposition of the rule.

c. Commenter 17810 cites other regulatory contexts wher e it says that EPA has read similar provisions of the CAA to include the use of lower-emitting pr ocesses and practices, including switching to cleaner burning fuels:

i. BACT Guidance issued in March 2011 includes sw itching to clean fuel as a “control option” for purposes of performing a BACT analysis under the PSD program.

ii. BART guidance under the Regional Haze program includes inherently lower emitting processes, such as processes using cleaner fuels, as “potentially applicable retrofit control technologies.”

Comment 26: Commenter 17852 states that switching from coal-fueled electric power generation to generation from natural gas or renewable energy can achieve substantial reductions in toxic air emissions, stating that natural gas plants emit no mercury and negligible other HAP in contrast to coal. Commenter adds that numerous mo dern, high-efficiency NGCC plants with significant unused capacity are available to replace existing coal-fired generation and that dramatically expanded U.S. natural gas reserves and infrastructure have reduced gas price volatil ity (citing several references in the Docket EPA-HQ-OAR-2009-0234). Commenter 17852 recommends that the EPA re-evaluate the docket and issue specific guidance and indicate in the preamble to the utility MACT final ru le that fuel switching to natural gas is a means to comply with the standard, providing guidance how various types of fuel switching to natural gas can allow coal/oil units to comply, including:

a. Converting existing coal boilers to natural gas;

b. Retiring coal plants and building new natural ga s plants (either at the same location or a new location);

c. Increased co-firing with natural gas; and

d. Increasing use of existing, underu tilized natural gas power plants.

Commenter 17852 states that the EPA made several uns upported assumptions in rejecting natural gas as a compliance option and cites several references (included in Docket EPA-HQ-OAR-2009-0234) to support this point:

a. Commenter 17852 states that, in comparing costs for fuel switchi ng to natural gas, the EPA only focuses on one type of fuel switchi ng (converting existing coal boilers to natural gas, which results in a loss in boiler efficiency). Commente r states that a more logical eval uation would be to compare the expensive retrofits facing existing coal plants to retiri ng the aging plants and either using existing natural gas generation from unused capacity or build ing a new NGCC (at same location or new site). Commenter adds that the EPA’s analysis also ignores the possibility of co-firing natural gas in coal or oil-fired boilers. Commenter conducted such an ec onomic evaluation and found that the break-even gas price for increasing use of existi ng 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 approxima tely $5.50/MMBtu. According to th e commenter, thus, using the natural gas prices that the EPA assumes in their fu el switching analysis ( $5.74/MMBtu), increasing the379 use of available capacity from an existing NGCC is the economical choice, and building a new NGCC is virtually equivalent. Commenter a dds that the economics for using na tural gas improve when including additional costs that may be imposed on coal-fired power plants under other regulatory initiatives.

b. Commenter 17852 states that the EP A finds coal to gas retrofits mo re expensive than other retrofit options based on fuel prices of coal at $2.13/MM Btu and natural gas at $5.74/MMBtu, despite the capital and O&M costs of the coal to gas retr ofits being less expensiv e than other options.

c. Commenter 17852 states that it should be reco gnized that the EPA’s assumed natural gas price ($5.74/MMBtu) only assumed installation of scrubbers and SCR, but if additiona l controls are required (e.g., coal ash, cooling water issues), it can become more economical to shutter old coal plants and build new NGCC plants.

d. The commenter states that with respect to co-firing with natural gas, the EPA notes that, ”For the oilfired subcategory, we did not includ e data obtained from EGUs co-firing natural gas in the existing source MACT floor analysis because those emissi ons are not representati ve of EGUs firing 100 percent fuel oil (76 FR 25045). Commenter 17852 r ecommends that the EPA should clarify in the guidance that co-firing with natura l gas can reduce the emissions of e ither coal or oil-fired units and may be an effective means of compliance.

e. Commenter cites that the EPA has found that re gulation of HAP emissions from natural gas power plants, “is not appropriate or nece ssary because the impacts due to HAP emissions from such units are negligible.”

f. Commenter refutes the EPA’s cont ention that natural gas may not be a cost effective option, stating that fuel switching to natural gas is made more fe asible by the fact that dramatically expanded U.S. natural gas reserves and infrastruc ture have reduced gas price volat ility and are projected to make natural gas affordable for the foreseeable future. Commenter cites that the EPA RIA for the proposed rule includes projections th at natural gas prices ar e 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, wh ich is a negligible increase and shows the ability of natural ga s to provide fuel to power plants without dramatically increasing natural gas prices (Figure 1, 2010 to 2011 Annual En ergy Outlook of the EIA included in Docket EPAHQ-OAR-2009-0234).

g. Commenter 17852 cites their own reports and studies, adopted by a task force that represented natural gas producers and distributors, consumer groups, large industrial users, and inde pendent experts, which found that abundant natural gas supplies coupled with increased storage and import capability, as well as the ability to use long-term contr acts and hedging arrangements, provide for a stable natural gas price horizon and opportunity to expand use in the U.S. Co mmenter states that the EPA must take into account their recent studies, which show that ava ilable gas-fired generation capacity exists in most regions of the U.S. According to the comment er, their report found that in 2008, CCGT plants operated with only a 33% capacity fact or. If only the more efficient gr oup of CCGT plan ts (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) indi cates that could replace up to 60,000 MW of out-of-compliance base load units that may be retired. The commen ter states that the ge ographic distribution of this available CCGT capacity is rather well aligned w ith the location of most vul nerable coal-fired units (Figure 2, Docket EPA-HQ-OAR-2009-0234).380 h. Commenter 17852 cites that the MIT report also found that there is sufficient surplus NGCC capacity to displace roughly one-third of U.S. coal generati on. The commenter states that according to MIT, substitution of this NGCC capacity would reduce CO 2 emissions from the power sector by 20 percent and yield a major contribution to th e control of criteria pollutants.

i. Commenter refutes the EPA’s contention that natura l 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 inte rstate natural gas pipelin e system.” According to the commenter, this study found that the median c onnection length is only approximately 26 miles and the median incremental cost is only approxi mately $14 million. The commenter states that given that environmental retrofits for coal pl ants may cost hundreds of millions of dollars, $14 million for the median cost of a new gas lateral connection is comparativel y minor. Commenter adds that the EPA may have used assumptions that overstated the length and cost of these new gas connections. Commenter also cites that the Department of Energy ( DOE) has found that that natural gas lines can, “deliver fuel to power plants in most locations in the lower 48 states.” Commenter recommends that the EPA correct the record.

j. Commenter refutes the EPA’s contention that, “even where pipelines provide access to natural gas, supplies of natural gas may not be adequate , especially during peak demand (e.g., the heating season).” Commenter points out that the development of shale gas has vastly increased onshore gas production, gas storage capacity has increased over the last few years, and the FERC has been responsive to the need for additional pipeline cap acity to bring gas to new markets. Commenter acknowledges that, while it is possi ble that unforeseen emergencies may create temporary curtailment, these types of emergencies are manageable, and not unlike other energy delivery issues that occasionally

occur.

Comment 27: Commenter 17853 states that the EPA has the authority granted in section 112 of the CAA to consider fuel switching as an alternat ive 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 adequa te” with the following points:

a. According to the commenter, at current consump tion rates, North America has over a 100-year supply of natural gas.

b. According to the commenter, natural gas drilling and extraction technologies (including shale gas) have dramatically improved over the last 5 years, and the lead time to respond to increased demand has been significantly decreased thus reducing price volatility. The commenter states that the Potential Gas Committee of the Colorado School of Mines releases a biennial assessment of the nation’s natural gas resources, and review from the 2006 assessment to th e 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 availabl e within the U.S., the natural gas pipeline transmission systems of the U.S. and Ca nada are highly integrated, providing access to Canada’s vast gas reserves, which coupled with Canada’s relatively small population, provides the U.S. with an additional reliable sour ce to help meet rising demand.

d. The commenter states that according to the U.S. EIA Annual Energy Outlook 2011 projections, production from shale formations in the U.S. grew by an average annual rate of 17 percent per year from381 2000 to 2006, and in the years from 2006 to 2010, U.S. shale gas production grew by an average annual growth rate of 48 percent.

e. According to the commenter, the natural gas industry has proven the ability to develop and distribute natural gas required to meet increased demand from the EG U sector into the future.

f. Commenter states that the EPA’s analysis on fuel switching is flawed because it mistakenly presumes retired generation must be replaced bybuilding a gas-fired unit in the same footprint. According to the commenter, with greater reliance on lo cal resources, retiring coal-fired EGU capacity can be replaced by natural gas-fired EGUs built closer to load, reducing dependence on interstate pipelines.

g. The commenter states that historical trends also demonstrate that c oncerns over natural gas availability and abundance are unfounded. The commenter states that according to the July US EIA Natural Gas Monthly report, “nearly 237 GW of natural gas-fired power generation capacity were added between 2000 and 2010, re presenting over three-fourths of total generation capacity additions over that period.” The commenter assert s that despite this growth in natural gas-fired generation capacity additions, natura l gas prices in 2010 remained rela tively low and production rates of natural gas continue to grow.

Commenter 17853 states that an i mmediate HAP benefit to the e nvironment can be realized by increasing utilization of existing and new natural gas-fired EGUs and cites the results of the Utility Study and the preamble to the proposed rule as accurate ly 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 alternat ive. According to the commenter, si nce 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 provi des offsets for increasing zero HAP base-load generation directly towards a corresp onding decrease in coal-fired generation.

Response to Comments 25 - 27: The EPA declined to propose as a beyond the floor level of control a requirement that coal- and oil-fired EGUs convert to natural gas. For ex isting sources, we indicated that we did not believe the supply of and transmission infras tructure for natural gas were sufficient to convert all existing units to natural gas. 76 FR 25046. We also de termined that the incremen tal cost of electricity (COE) for converting all existing coal- and oil-fire d 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 E GUs be natural gas-fired even if we concluded that natural gas supplies were availa ble because it would effec tively prohibit construction of new coal-fired EGUs and we did not believe thatto be a reasonable appr oach to regulating HAP emissions from EGUs. 76 FR 25049. We are not revising our deci sion in this final rule in response to the comments and we address commen ters’ specific points below.

Commenters cite studies and reports that show that the supply of na tural gas is growing, that the cost of natural gas is generally stable, and that the availability of natural gas is expanding. One commenter even notes that one study specif ically considered such issues in the context of the proposed EGU NESHAP. Even assuming all the studies are accurately char acterized, 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 currently sufficient an d that the transmission capab ilities are expanding, but no commenter indicates that the current situation (o r the situation within three years) would allow a wholesale conversion to na tural gas. The highest estimate providedby 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 clearly falls short of the am ount of fuel switching that would be necessary to set a beyond the floor standard at le vels that would require al l existing coal units to switch to natural gas. In addition, we continue to believe th at a final rule that expressly prohibits new coal construction is not reasonable. For all these reasons, we maintainthat our proposed determination not to require switching to natural gas as a be yond the floor level of control remains valid. We also note that commenters appear to conflate the availability of natural gas as a cost effective compliance alternative with the availability of natural gas as a beyond the fl oor requirement applicable to all sources in a particular subcategory. We acknow ledge that some sources will co-fire natural gas with coal or oil as a complianc e option and that other EGUs will be converted to burn 100 percent natural gas. Both approaches are valid means to comp ly with the standards contained in the final rule; however, the availability of these compliance alternatives does not s upport a determina tion 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 th at all new natural gas un its 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 s ubject EGUs would have to do to comply with the beyond the floor standard.

10. Concurrence and caution for delegation of state programs.

Comment 28: Commenter 17810 recognizes the EP A’s authority to delegate authority to implement section 112 rules and regulations in section 112(l) to states, provided th at 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 progr ams, including the Colorado Clean Air-Clean Jobs Act, and concurs with the EPA that these type of programs will ultimately result in significant emission reductions from coal-fired EGUs, as companies implem ent strategies (e.g., retirement/replacement with natural gas or other “cleane r” generation) and/or tec hnologies (e.g., state-of-the-artcontrols) to meet the requirements. Commenter cautions th at they expect thatthe EPA should look very closely at state programs or rules that have compliance dates beyond those contained in the federal rule to ensure that these programs merit greater re ductions 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 non-continental EGU sources.

Comment 29: Commenter 18477 expresses concern that the proposed rule mistakenly assumes that switching to natural gas or co-firing with natural gas is a valid and cost-effective compliance option for liquid oil-fired units; however, there is no natural gas or liquid natural gas resource in Hawaii. The commenter states that as a remote island utility, it does not even have acce ss to the small amount of refinery gas available to the refine rs addressed by the Boiler MACT.

Commenter 18477 states that all oil-fired EGUs operating in Hawaii, Guam, and Puerto Rico exclusively combust residual fuel oi l 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, p our point, flash point, API gr avity and viscosity, which the refiners are able to meet pr imarily by blending and some sulfur removal. However, they do not and cannot economically control for metal content. The co mmenter states that as the agency noted in the preamble to the Boiler MACT, the quality of the fuel produced by non-continental refineries is limited by the quality of the crude slate used in the refining process (76 FR 15,635).

Commenter 18477 states that it is not feasible for non-continental liquid oil-fired EGUs to comply with the proposed numeric emission standards based on th eir survey of equipment control vendors. The commenter states that the vendors surveyed unifo rmly responded that they cannot guarantee their equipment can meet the proposed HAP limits for liqui d oil-fired EGUs. The commenter states that the ability to achieve HAP control with residual fuel o il applications and ESPs or multi-cyclones in utility type boilers is currently being researched a nd is not a commercially demonstrated technology. According to the commenter, bag-houses are not a su itable technology for particulate matter control for residual fuel oil applications. The commenter states that reputable dry and wet ESP suppliers, such as Alstom, Babcock & Wilcox, PECO, Siemens, Southe rn Environmental Inc., Clyde Bergemann, Hamon Research-Cottrell, and Allied Enviro nmental Solutions, Inc. were contacted to determine their current position on providing ESP guarantees to meet the proposed emission limits for liquid oil-fired units, and the companies that have provided feedback thus far will not guarantee that currently available technology can achieve the proposed emissions limits for residual fuel oil applications. Commenter included Attachment C as a summary of the vendorresponses in the Docket No. The EPA-HQ-OAR2009-0234.

Comment 30: Commenter 18502 states that because they are a non-continental facil ity, the availability of alternate fuels is limited. The commenter states that there are no fossil fuel resources on the island (Puerto Rico) and that the fuels presently used are delivered by ocean tankers, which is a possible source chloride contamination of the fuel as indicated by the erratic HCI measurements made during the ICR testing (HCI emissi ons varied by a factor of 20).

Commenter 18502 states that it has a long term plan for converting their steam generators, CCs, and CTs to co-fire natural gas (NG), but the infrastructu re needed to deliver natural gas does not currently exist. The commenter states that the long term plan involves particip ation in expansion of a local LNG facility operated by EcoEiectrica and actively purs uing installation of a NG pipeline. The commenter states that engineering evaluations and permitting for the pipeline is underway, but completion has not been established yet.

Response to Comments 29 - 30: As noted elsewhere in this docum ent, the EPA is establishing a noncontinental liquid oil-fired s ubcategory 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 testing.

Comment 1: Commenter 17402 requests that the EPA allow faci lities to set the capacity level at which a plant operates during a performance test. The comm enter stated the EPA in allowing this will be providing another option for compliance, particularly as facilitie s transition and install new control equipment. According to the commenter, this appro ach will not cause an incr ease in emissions given that the facility would be limited in its ability to exceed the capac ity level at which itis operating during the test.

Response to Comment 1: Pursuant to section 63.10007(c), performance tests are to be conducted under normal operating conditions. Unlike the proposed rule, there is no operating limit es tablished in terms of 110% of the capacity level used during the most recent performance test.

Comment 2: Commenter 17754 states that the proposed rule shoul d be revised to clarif y that an affected source may elect to perform and/or rely on performance testing for the PM surrogate as the basis for initial and continuous compliance with to tal non-Hg HAP metals emission limit.

Commenter 17754 states that the EPA should not requ ire an owner/operator of an affected EGU who elects to demonstrate compliance with total non-Hg HAP metals using the PM surrogate to conduct performance testing for both PM and total non-Hg HAP simultaneously. According to the commenter, the EPA should revise the rule to allow that if an owne r/operator elects to comply by using the PM surrogate, the owner/operato r is not required to conduct performan ce tests for both PM and total non-Hg HAP. The commenter states that the rule should be revised to provide thatif a facility elects to conduct simultaneous performance testing of the PM surroga te 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 inappr opriate to require units relyi ng on a surrogate to also conduct performance testing for the associated surrogate pollu tant(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 witha surrogate standard will conduct the performance test for that standar d, and not for the corresponding HAP (and vice versa).

Comment 3: Commenter 17796 objects to the initial performa nce test requirement for all source owners and proposes that once the initial performance test is conducted for PM and non-HAP metals, fuel sampling will be adequate to demonstrate compliance in lieu of stack testing. According to the commenter, stack testing should be no more frequent than every 6 months.

Response to Comment 3: The final rule does not contain the proposed fuel sampling and analysis compliance demonstration approaches. See the fina l preamble and discussion under Comment Code 5A. The final rule uses either CEMS, where applicable , quarterly performance te sting, reduced testing under385 the LEE provisions, or annual testing with a PM CP MS for the filterable PM or non-Hg HAP metals limits that apply.

Comment 4: Commenter 17881 states this requirement creat es 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 performan ce testing for both PM and multiple metals, what would happen if one or more of th e 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 witha surrogate standard will conduct the performance test for that standar d, and not for the corresponding HAP (and vice versa).

2. Test methods and methodology.

Comment 5: Commenter 17621 provided discussion of tes ting methods recommended for ICR data collection and compliance w ith 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 test er must estimate in advance the minimum sample volume that will provide adequate mass of Hg for analysis for the specific source and analytical technique. This commenter states it is possible to state a minimum mass of Hg that must be collected on a sorbent tube to obtain an accurate measurement by a given analytical method. The commenter states that based on EPRI’s reviews of many ICR Part III test reports, almost all samp les were analyzed using thermal desorption/CVAAS. According to the commenter, this research indicate s 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 de sorption peak shape, and 2) to rais e the sample mass sufficiently above the background sorbent mercury level. The commenter states that test runs with loadings below 10 nanograms generally failed method quality criteria for one or more of the three samples.

Commenter 17621 states that EPRI has classified the adequacy of Method 30B to measure at the proposed MACT limit for new coal EGUs as uncertain based on reports from severa l stack testers that at high sample flow rates leakage and equipment failure has occurred.

Commenter 17621 believes it is uncertain whether Me thod 30B can, for liquid oil-fired EGUs, measure Hg accurately at the proposed MACT limit for existing EGUs, and will be unable to measure Hg for new units without excessively long (about 30 hours) test runs.

b. Method 5: Commenter 17621 states that it is not certain wh ether Method 5 sensitiv ity is adequate to support compliance monitoring at the MACT limits for total PM, as that will depend upon the relative proportions of filterable PM and condensable PM in the stack gas. According to the commenter, for a stack gas where PM emissions are predominantly f ilterable PM, the above methods will be able to measure accurately at the proposed total PM lim it (0.03 lb/MMBtu) for existing coal-fired EGUs. The commenter states that at the proposed limit for new EGUs (0.05 lb/MWh, approximately 0.005 lb/MMBtu), Method 5 should still be sufficient to measure accurately by gravimetric analysis and whether the overall method accuracy, considering sampli ng variability, will be adequate at that emission rate is unknown. Commenter adds th at field studies conducted by EPRI and others have identified problems with the accuracy of Method 5 at low em ission 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 materi al used for the particulate filter (glass fiber versus quartz fiber filter) can produc e a significant bias in the resu lts due to acid gas sorption on the alkaline material of glass fiber filters (EPRI, 2011) . According to the commenter, the temperature of the sampling probe and filter also affects the amount of filterable PM collected, w ith the lower temperature collecting more filterable PM. The co mmenter states that the ICR Part III data include tests conducted at two different temperatures (250 °F and 320 °F) and withboth types of filters, and that these variables introduce additional uncertainty into conclusions drawn from the ICR data, in addition to normal method variability.

c. Method 202: Commenter 17621 states that it is not certain whether the Method 202 sensitivity is adequate to support compliance monitoring at the pr oposed 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 predominantly condensable PM, the mass collected in a 4-hour test will be sufficient for an accurate gravimetri c measurement at the proposed total PM limit (0.03 lb/MMBtu) for existi ng coal units. The commenter states that at the proposed limit for new EGUs, approximately 0.005 lb/MMBtu, the collectedPM residue is also sufficient to measure accurately by gravimetric analysis, but limited results of field testi ng indicate that the overall method accuracy may not be adequate at that emission rate . Commenter adds that a field study conducted by AEP at several coal-fired power plants found that revised Method 202 has high between-run variability (EPRI, 2011). The commenter states that in four replicate tests conducted with the same sampling conditions (probe temperature, PM filter type, an d sampling duration), the relative percent difference (RPD) of the CPM measurements ranged from 25–78 pe rcent. The commenter states that these were samples taken at different times and were not parallel train samples; how ever, process monitoring indicated that there were no upsets during the sampling periods. The comment er states that filterable PM samples taken from the same sampling trains ha d lower (6–27 percent) variability. Condensable PM emissions in the samples ranged from 0.00 32 lb/MMBtu to 0.013 lb/MMBtu. The RPD of the replicates at the lowest emissi on 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 precisi on at the proposed limit for existing coal-fired EGUs. Commenter also adds that an EPRI laboratory study of OTM-28 determined that modifications from the original Method 202 had reduced the positive bias due to aqueous-phase conversion of gaseous 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 effectively. According to the commenter, as sulfuric acid is the predom inant condensable PM species in coal-fired power plants, this finding may indicate that th e revised Method 202 has a negative bias.

d. Methods 5 and 202: Commenter 17621 states that the combina tion of Methods 5 and 202 is sensitive enough to provide accurate gravimetric measurement at the proposed MACT limits for both existing and new coal-fired EGUs. According to the commenter, the precision of Method 202 may not be sufficient at the new EGU limit to support that determination.

Response to Comment 5: The EPA does not agree that all com ponents of a test method composed of composite analyses need to be above the mini mum detection limit to provide reliably accurate quantification of the total emissions. While the co mmenter focuses on the four components used to quantify total particulate matter, other test methods and pollutants would present similar influences. While it is common to collect less than a measur eable mass in the nozzle and probe portion of particulate sampling trains, this has an insignificant im pact 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 da ta from the mix of PM tests performed under the Part III ICR, there were few indi vidual runs where the mass of particulate was below the mass that has routinely been determined to be the minimum detectable mass for the different components. For filterable particulate, only 51 test runs out of 1252 ha d less than 1.3 mg of part iculate on the filter and probe wash. For inorganic condensab le particulate, only 19 of the 772 runs reported a mass of less than 1.5 mg. Last, for organic condensable pa rticulate, 30 test runs out of th e 772 runs reported a mass of less than 0.5 mg. These weights are the approximate de tection levels for thes e components of total particulate. There were no sources where the mass for all component s 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 leve l we proposed. Since we have selected filterable particulate as the alternate equi valent standard for non-Hg meta ls, there are only two measured components and the filter component is expected to have the majority of the PM. In reviewing the filterable PM data, a 4-hour source test with 5 mg pa rticulate 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 filt er selection and filtration temperature on the determination of mass on the filter. Sources and source test contractors w ill 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 sim ilar 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. Acco rding to the commenter, use of a PM filterable surrogate would also allow a direct compliance determination via the use of PM CEMS (which are only capable of measuring PM filterable emissions).

Response to Comment 6: In response to comments, the final rule has removed all requirements for duplicative testing of a HAP and its surrogate. Facilities complying witha surrogate limit do not have to perform periodic testing for the corresponding HAP. We agree with the commenter in that Method 29 provides the ability to concurrently quantify f ilterable PM and the non-Hg metals which we are regulating. The final rule uses a PM CPMS appro ach. See the final preamble and Comment Code 5A07a for further discussion.

Comment 7: Commenter 18444 states that the particulate filt erable temperature is defined as 320 °F ± 25 °F, which is the temperature currently used for non- sulfate filterable PM test ing, and this appears to be because the sulfate is to be counted with the condensables. Acco rding to the commenter, this is different than most of the EPA testing (248 °F ± 25 °F), so the filterable part iculate results measured under these new requirements would likely be lower than what would be currently measured. The commenter states that since the lim its are for the total PM (filterable and condens able) the total catch should in theory be the same regardless, but this w ould impact the PM CEMS (if used) since they will be measured on the filterable only. The commenter states that companies would have to test separately for compliance with different federal particulate limits based on these temperature di fferences, adding to the testing workload.388 Commenter 18444 states the filter temp erature for metals testing is defined the same as for particulates (320 °F+ 25 °F) instead of the currentpractice (248 °F + 25 °F). The co mmenter states that the proposed rules mention determining filterable metals separatelyfrom total metals, and as with PM, this impacts limits set for Hg CEMS or sorbent monitoring (if us ed) since particulate Hg is not measured by these methods. According to the commenter, in this case, there will be highe r mercury results on the CEMS or sorbent monitoring since the higher filter temperature would allow more Hg to pass through the filter. The commenter states th at as long as the EPA adopts stringent PM limits, that particulate Hg emissions will not be significant; monitoring gaseous Hg should be sufficient and the filter temperature should not change the gaseous Hg results significantly.

Response to Comment 7: While we deliberated what filter temper ature 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 unde rstanding of the within source variability of emissions. It also provided a more direct ability to establis h a particulate level for correlation or alternative applicatio ns of PM CEMS. The absence of SO 3 on the filter and the collection in the impinger provides for more consistency inobtaining constant weight s. Since little or no SO 3 is retained on the filter, the highly 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 thereby making it easier to achieve constantweight. Lastly, it provided a pa rtitioning of the components of particulate similar to the majority of the existing emissions controls.

Comment 8: Commenter 19033 states that the proposed re gulation section 63.10005(b) specifies that performance tests are to be conduc ted; as specified in Table 5. W ith respect to the proposed PM limit, the commenter notes that the testing re quirements are Method 5 a nd 202, with the specific provision that tests using Method 5 mu st be performed at a filter temperature of 320° F. However, some state permit conditions require thatfilterable PM, as measured by Me thod 5, be conducted at a filter temperature of 250 °F. Commenter adds that filterabl e PM measured by Method 5 at 250 °F is expected to provide different (and higher) resu lts than filterable PM measured by Method 5 at 320 °F, because of the condensation of sulfuric acid at 250 °F. Accord ing to the commenter, consequently, a mechanism is needed to allow EGUs required to perform Method 5 tests at 250 °F to c oncurrently demonstrate compliance with the proposed PM limit based on a Method 5 filter temperature of 320 °F. Commenter 19033 suggests the following mechanism to accomplis h 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 filte r 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 co rrelate to 250 oF) will become the filterable concentration limits, rather than the three-run filterable PM con centration limit measured at 320 °F.

Commenter 19033 recommends revisions inTables 4 and 7, in order to implement the above described mechanism. In conjunction with the changes recommended for Tables 4 and 7, Commenter 19033 also recommends that proposed regula tion 63.10011 (d) be amended as follows:

... You must determine an operating-limit (PM concentration in mg/dscm) during performance testing for initial PM compliance. The operating limit will be the average of the PM filterable results of the th ree Method 5 performance test results, unless the state agency requires the Method 5 tests to be perf ormed at a filter temp erature of 250°F. If389 the Method 5 tests are required to be cond ucted at 250°F, the operating limit will be the average of the PM filterabl e results reported by the PM-CEMS rather than the PM filterable results of the three Method 5 te sts performed at 320°F, provided compliance is demonstrated by the Meth od 5 tests conducted at 320°F.

Comment 9: Two commenters (18444, 19033) express concern over the EPA requirement that the stack test filter temperature is set at 320 °F when other regulatory authorities and/or State agencies may require a different lower temperature of 250 °F.

Response to Comments 8 - 9: The final rule has been revised to remove the requirements for Method 202 and PS-11, so those comments are moot. The 320° F filtration temperature was chosen for the determination of compliance with the standard due to match the data collection temperature. If sources would like to harmonize their testing requirements with other limits at lower filtration temperatures, they may request to do so per 63.7. The EPA agrees that th ere are biases associated with improper selection of filter material. Method 5 states that sources with SO 2 or SO 3 should select an unreactive filter to handle such issues. The EPA disagr ees that Method 30B cannot measur e the levels specified in the emission standards. The data used for the new source MACT limit were based on Method 30B 4 hour test runs that met all QA criteria with a catch under 10 nanograms. The EPA disagrees that we should set a specific ng catch for the method, but welcomes sources to devise test plans with those DQOs.

3. Test methods unreliable or inadequate.

Comment 10: Commenter 17736 states that including conde nsable 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 meta ls emissions. As a result of that evaluation, we have selected filterable particulate since it offers several advantages withrespect to continuous monitoring and ease of demonstrating compliance. The comments regarding a supposed lack of condensable PM data and potentially inaccurate conde nsable 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 materi al is in solid or liquid form butalso the size distribution of the particulate matter. By establishing a truly standard collection hardware , conditions for the separation of the water and sample gas, temperature for collection and analytical finish we have also established the material which is retained and measured as PM.

Comment 11: Commenter 17881 states as currently written, section 63.10006(e) requires that the fuel factor methodology and equations in sections 12.2 and 12.3 of Reference Method 19 (40 CFR 60, Appendix A-7) be used to convert the results of the performance te sts into units of lb/MMBtu of lb/TBtu, as applicable. This sec tion should recognize that such calculations need not be conducted if an EGU has chosen to demonstrat e compliance with the mass per unit of electrical output emission limits. The EPA should also allow the use of fuel f actors 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 c oke) or tire-derived-fuel, any of which could be fired in solid fuel-f ired boilers subject to the proposed rule.390 Response to Comment 11: The EPA agrees, and has made corresponding changes to section 63.10007(c) in the final rule.

Comment 12: Commenter 18449 expressed the concern that, if the + 1 μg/m3 alternate specification is tightened, an increased frequency of testing errors will cause even CEMS that are operating properly to fail. According to the commenter, the EPA should consider a mandatory periodic QA/QC program where it or another impartial agency loads sorbent traps s upplied by the test group with the output from a NIST traceable elemental calibrator. The commenter st ates 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 pr oposed rule creates a double standard, facilitating potentially inconsistent enforcement practices. The commenter states that non-Hg HAP metals compliance provisions should be written to pr ovide 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 witha surrogate limit do not have to perform periodic testing for the corresponding HAP, and vice versa.

Comment 14: Commenter 17881 states Table 4 of the propos ed 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 m onth. 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 ba rred 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 generally required by one or more of the following: 40 CFR Part 60, 40 CFR Part 75, and State Implementation Plans.

Response to Comment 14: In response to comments, the final rule has removed all requirements for duplicative testing of a HAP and its surrogate. Facilities complying with a surrogate standard will conduct the performance test for th at standard, and not for the corre sponding HAP (and vice versa). The specific provisions cited in this comment have been clarified in the final rule such that only the HCl testing would be required under such circumstances.

5. Test requirements.

Comment 15: Commenter 17772 submits that the testing requ irements 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, wh ich is unjustified and costly. This commenter also states it is unclear how compliance is determined under the multiple testing scenario.

Comment 16: Commenter 17796 supports testing for filterable particulates as well as condensable PM.

Comment 17: Commenters 17638 and 17681 state that the EP A 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 testfor non-Hg HAP metals. EGUs using SO 2 as a surrogate for HCl should not be required to stack test for HCl. Co mmenters also state that the EPA should not require stack testing of surrogates when a source chooses to comply with the HAP limit.

Commenter 17790 submits there is no justification for test ing for the HCl surrogate (Method 502) if a company is complying with the HCl standard.

Commenter 17868 states that the EPA has no basis to require HAP stack testing for EGUs using surrogates or to require surrogate testing for EGUs not relying on surrogates. The commenter states that the requirements are duplicat ive and should be removed.

Commenter 17881 states it is inapprop riate to require units relying on a surrogate to also conduct time consuming and costly performance testing for the a ssociated surrogate pollutant(s). According to the commenter, this approach is whollyinconsistent with other 40 CFR Part 63 standards which allow the use of surrogates, and the EPA has provided no rationale for the need to collect this additional data. The commenter states that if the EPA is concerned about the relationship between the chosen surrogates and their associated HAP(s), then the EPA should initiate an additional ICR effort which will allow them to further study the relationships between HAP(s) and their potential surrogates.

Commenter 17881 states that the provisions of secti on 63.10006(i) are very similar to those in section 63.10006(d) in that they require test ing of both the surrogate (i.e., SO 2 ) and the associated HAP (i.e., HCl) even though the surrogate cannot be relie d upon for compliance for solid oil-fired and coalfired EGUs without a SO 2 CEMS and without wet or dry FGD controls.

Commenter 18498 states that the requirement to stack test for both the poll utant and surrogate is redundant, and requests the EPA to remove the require ment that both the pollu tant and surrogate be stack tested. According to the commenter, a performa nce test should only be required for the pollutants and surrogates with which a source is choosing to show compliance.

Multiple commenters (17638, 17681, 17754, 17772, 17781, 17790, 17800, 17881) express the concern that requiring testing for both a pollutant and its surrogate is unnecessary when only one should be adequate for demonstrating compliance.

Commenter 17800 states that requiri ng sources to test either for the actual HAP in cases where surrogates are being used for compliance is duplicative, has no rational to be required, and will increase the cost of compliance.

Commenter 17881 states that the provisions of se ction 63.10006(d) require that petroleum coke and coal-fired EGUs without PM CEMS (but with PM c ontrol devices) conduct all applicable tests for PM and non-Hg HAP metals testing during the same co mpliance 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 othe r month. The commenter states that the PM surrogate only applies 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 regulat ed pollutant for such units. The commenter states that as discussed in re lation to 63.10005(a), the EPA should conduct an additional ICR if they feel it is necessary to coll ect additional data on the relationship between PM and non-Hg HAP metals emissions.

Response to Comment 15 - 17: We agree that a reduction in the fr equency and types of measurements and monitoring that we proposed is appropriate and will still provide an assurance that sources are maintaining reasonable emissions control of HAP metals and acid gases. First, in response to comments, the final rule has removed all requi rements for duplicative testing of a HAP and its surrogate. Facilities complying with a surrogate limit do not have to perform periodic testi ng for the corresponding HAP, and vice versa. Second, we have changed all requirem ents for periodic monthly or every other month performance testing to quarterly, with an exception for quarters with very low operating hours. We have clarified that no performance stack te sting 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 approachfor ensuring compliance with a filterable PM or HAP metals emission limit.

Comment 18: C ommenters 18014 and 18498 state that the mi nimum sampling time of four hours required by section 63.7520(d) for comp liance tests is excessive. Accord ing to the commenters, the EPA should re-evaluate the required sampling times for each method and/or provide alternative minimum volumes for each method.

Response to Comment 18: We have selected the appropriate test duration that we believe is required to achieve the necessary measuremen t precision needed to determin e compliance. Source testing companies are encouraged to perform an assessment of the ability of an a lternative sampling duration, sampling rate and analytical finish which provides for comparable reliable, precise and accurate measurements and that is repres entative of the sources operation.

Comment 19: Commenter 18018 states that the EPA’s propos ed compliance requirements are overly burdensome and should be modified due to certain compliance requirements for the proposed air toxic rule that may result in periods of noncompliance by some EGUs that may be capable of complying with the emission limits under normal operations. Accordi ng to the commenters, the following change would facilitate compliance with the proposed rule: PM compliance testing should involve only filterable particulates. Including soluble particulates w ill complicate compliance testing without providing significant additional compliance assurance.

Response to Comment 19: The final rule uses filterable PM as the surrogate for non-Hg HAP metals. See further discussion of this issue in the preamble and elsewhere in this document.

5. Other.

Comment 20: Commenter 17902 states the proposed rule defi nition 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 applicat ion of Table 1 and Table 2 emissi on limits needs to be clarified including how emission limits will apply for units that move from one subcategory to another. According to the commenter, the relevant MACT emission limits should be applied based on the majority of fuel actually combus ted annually on a heat input basis.393 Response to Comment 20: According to the definitions of coal-fired electric ut ility steam generating unit and oil-fired electric utility steam generating unit in §63.10042, should an EGU that co-fires pet coke and coal such that more than 10 percent of the annual heat input for 3 years or 15 percent of the annual heat input for one year is from coal, the EGU is a coal-fired electric ut ility and would be subject to the coal-fired emissions limits.

Comment 21: Commenter 18502 expressed concer n that natural sources of atmospheric chlorine in coastal areas that a facility cannot control can cause wide variations in emission rates. The commenter states that these include chloromethane formed by action of sunlight on marine biomass and chlorine from sea foam, possibly influenced by wind direction.

Response to Comment 21: The rule has been revised to address th is concern for liquid oil-fired EGUs, such that an owner or operator need not conduct HCl or HF emissi ons measurement if the owner or operator conducts fuel moisture analysis or provides certification from a fuel s upplier 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-unit control.

Comment 1: Commenter 15678 supports the EPA’s application of emission standards to each operating EGU instead of to the overall site consisting of seve ral EGUs. This commenter stated that this approach is especially important for areas with large am ounts of impervious land cover where increased stormwater runoff will contribute more land depos ited Hg to the food chain via bioaccumulation in seafood. The commenter strongly supports ap plying 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 su bcategory elsewhere in this document.

Comment 2: Commenter 17733 states that in order for the EPA to meet its res ponsibilities 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 cont iguous area and under common control. The commenter states that this approach is n ecessary to be consistent w ith the rule’s description of a source and helps insure the rule can take advant age of economies of scale by having all IB units at a source apply the same level of control technology. A ccording to the commenter, this approach prevents IB unit owners from avoiding stringent EGU MACT rule requirements by di smantling shared pollution control device exhaust stacks. The co mmenter states that the EPA should require all IB units as a source to meet the most stringent EGU MACT sta ndard 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 a ddressed. To the extent co mmenter is referring to EGUs, we have addressed comments related to emissi ons averaging across EGUs at a common site in a given subcategory and to common st acks elsewhere in this document.

2. Use of combined stack data.

Comment 3: Commenter 17739 states that the EPA’s use of comb ined stack data is inconsistent with its treatment of data below the MDL. The commenter states that in th e Boiler MACT, the EPA concluded it was inappropriate to use values below the MDL for th e simple and correct reason that “such values have not been demonstrated to have beenmet” (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 emissi ons is a fiction that represents the combined performance of the suite of contro l trains and boilers, and there is no basis to know whether one unit would measure higher and the other lower if tested separately, rather than assuming they would both measure exactly the same. The commenter states th at in fact, the one result of which we can be absolutely sure is that both units would not produ ce identical emissions. The commenter states that the EPA’s creation of multiple data points from a single co mbined stack data point are simply a fiction that is not permissible under the MA CT standard setting criteria.

Comment 4: Several commenters (12991, 17739, 18023) disagree with the EPA’s use of data from multiple units exhausting through a common stack. Commenter 17739 states that the EPA makes two errors: 1) EPA unreasonably treats data from multiple units exhausting through a single stack as multiple data points, and 2) EPA applies this incorrect appr oach 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 stra tegy that could be a be st performer, thereby entitling the agency to use the data at all, the fact is there is only one performer not two. Ap art 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 variab ility and over represents the emissions data by creating multiple “performers” or sources when ther e is in fact only one. In the Boiler MACT, the EPA argues its approach of creating tw o 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 so urces and there is only a single so urce. Indeed, the opposite is true. Commenters state that the EPA cannot determine what amount of the overall performance of a combined stack data point is the specific result of the combination. The EPA also argues that applying the emissions equally to multiple units exhaustin g through a single stack “accurately represents the emissions of those units on average. Commenters assert that is si mply 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 howeither 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 wh ere the EPA’s databases are sparsely populated. Commenter states that counting a single stack unit twice to have more data is not necessary in the utility MACT, which is not lacking for data. Commenter also states that counting as two a single stack may dampen variability unlike the EPA’s claim in the Bo iler MACT. Commenter states that the practice of treating plants that have multiple boilers exhausti ng through a single stack as if they were separate sources is fairly systemic and resu lts in a widespread population of th e database with fictional values.

Commenter 12991 disagrees with the use by the EPA of duplicate records for determining the Hg MACT floor. The commenter states that in several in stances 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 sele ct the units; that is, the selection of units was not entire ly random nor was it purposefullyintended to identify the bestperforming units within the tota l population of units. According to the commenter, the EPA did randomly select some units while inte ntionally selecting some of the be st performing units resulting in a biased selection represented by a gr eater percentage of baghouse-contro lled units than exists in the population of coal-fired utility sources. The commente r states that the duplicate records are redundant and should not be included because they cannot be c onsidered 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 th e 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 re sulting from each unit. This error is not limited to Georgia Power Company’s Plant Hammond. This error occurs in 19 of the 130 lowest emitting units for Hg, 25 of the lowest emitting units for PM, and 19 of the lowest emitting units for HCl. The EPA should treat the emission value from un its 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 an alyzed Plant Hammond, the EPA has considered at least five multiple-unit, single-stack plants as be ing 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 orde r to avoid additional methodological error.

Response to Comments 3 - 4: The EPA disagrees with commente rs. As in the Industrial Boiler NESHAP, the EPA continues to believe that the emi ssions from the common stack represent the average emissions of the EGUs exhausting to the common stack and are represen tative of both EGUs. Commenters have provided no data to support the contention that th is assumption is false. In addition, commenters contention that distinctEGUs (i.e., boilers) are one sour ce 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 reasonabl e in light of that definition to consider the emissions from two boilers to a common stack as the emissions of one EGU. The EPA used data from combined stacks only where both EGUs we re 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 sa mpling 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 re ceived and does not believe that there are any inconsistencies in the data set used for the final ru le. In the MACT floor anal ysis, the EPA used data only from stacks that were tested or for which testdata were provided. These stack measurements were not used to represent emissions from other, non-tested, stacks in the MACT analysis.

The ICR required owners or operato rs to provide the agency with information from individual EGUs, and those owners or operators certified the results submitted to the agency as being true, accurate, and complete. The agency has no ability to and needs not change such submitted data, for if after submission, an owner or operator be lieved his/her EGU data from a combined stack were inaccurate, he or she could have and should have conducted additional testing to isolate emissions. The agency maintains its use of submitted data for rulemaking purposes remains valid.

3. Common stack provisions.

Comment 5: Several commenters (15678, 17733, 17796) support the approach of applying the most stringent standard to each EGU when they shar e the same stack and/or controls. Commenters (17733, 17796) add that this should apply when there are similarly fueled units. Commenter 17796 states this would eliminate any possible confusion about the app licable regulatory requireme nts for both regulators and source owner.

Response to Comment 5: We agree with the commenters and ha ve included such requirements in the final rule.

Comment 6: Commenter 17775 states that the EPA’s proposed common stack provisi ons fail to provide sufficient flexibility for EGUs with different control technologies that ve nt to a common stack. The commenter states that under propos ed section 63.10009(h)(i), two or mo re units that vent through “a common control system” to a common stack may be trea ted 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 prop osed emission limit at the common stack during normal operation, any significant outage at one unit could make compliance on a 30-day rolling average basis impossible. The commenter states that the EPA addr essed the issue of outages for single stack units participating in averaging pl ans under section 63.10009(b) by pr oviding a 12-month rolling average compliance period and should provide the same for co mmon stack units that us e averaging to comply.397 Response to Comment 6: We have addressed common stack issu es elsewhere in this document. We continue to believe that the emissions of the comm on stack represent those of all of the EGUs ducting through that common stack. Should this present probl ems for the owner/operator, they are free to conduct their compliance or CEMS testing in the ductw ork prior to the common stack so as to measure emissions from the individual EGUs.

Comment 7: Commenter 17781 states as currently written, pa ragraphs (h), (i) and (j) do not seem to address the likely situation where each of the EGUs associated with a common stack are affected units within the same category, but theydo not utilize common control de vices (i.e., each EGU is equipped with its own control device(s)). The commenter stat es 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 stip ulate 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 test ing frequency requirements and there may be fewer situations of multiple and different te sting frequencies applying to units sharing a common stack. We agree with the commenter that in any case the more frequent testi ng requirement must apply to testing for that common stack.398 5C06 - Compliance: Startup, Shutdown, and Malfunction

Commenters : 15678, 16849, 17174, 17197, 17283, 17316, 17383, 17386, 17402, 17622, 17623, 17627, 17637, 17638, 17648, 17675, 17677, 17689, 17691, 17702, 17704, 17705, 17712, 17714, 17715, 17716, 17720, 17722, 17724, 17725, 17728, 17729, 17730, 17732, 17736, 17737, 17740, 17752, 17755, 17756, 17757, 17758, 17761, 17767, 17772, 17774, 17775, 17776, 17795, 17796, 17801, 17807, 17808, 17813, 17815, 17816, 17820, 17821, 17851, 17856, 17868, 17870, 17876, 17877, 17878, 17880, 17881, 17885, 17886, 17902, 17904, 17909, 17912, 17923, 17925, 17928, 17930, 17975, 18014, 18018, 18021, 18025, 18034, 18037, 18428, 18429, 18447, 18449, 18450, 18498, 18500, 18539, 19032, 19040, 19114, 19120, 19121, 19122, 19536, 19537, 19538, 18023

1. Emission standard applicability during SSM.

a. Support or oppose SSM approach.

Comment 1: Commenters (15678, 17880) support the EPA’s appr oach that emissions standards apply at all times. Commenter 17648 states that the EPA proposed reasonable and appropriate emission limitations applicable to SSM periods, and cites the Sierra Club decision. Commenter 19536/19537/19538 states that sources must comply withemission standards atall times, including startup, shutdown and malfunctions. Sierra Club v. EPA , 551 F.3d 1019 (D.C. Cir. 2008). Commenter 18450 supports that emission limits include startup and shutdown, since these emissions are readily quantifiable.

Comment 2: Commenter 17851 states that the EPA’s requireme nt to meet steady-state standards during SSM events is not logical and is not lawful. Co mmenter 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 includ ing performance during periods of start-up, shut-downs, malfunctions. Instead, the EPA started with verylimited data from EGUs operati ng under ideal conditions- generally three hours of operation at full load. As a result, the data were sk ewed 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, ha s start-ups, shut-downs and malf unctions where emissions will be substantially higher than the pe rformance that can be achieved under full load and ideal operating conditions.

Commenter 17868 states that the test operations and statistical treatment of the test data do not represent periods of startup, shutdown, or malfunction. Therefore those periods of operation should not be subject to the standards. A work practice approach, simila r to that promulgated for industrial boiler HAPs, would be appropriate for these abnormal ope rating periods. Second, the continuous compliance assurance requirements – which include enforceable li mits on various fuel and hardware variables like the pressure drop across a control device – are effectively more stringent than the emission standards that they support, and therefore were not “ach ieved 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 co al- and lignite-fired units to m eet and still remain economically operational (17930)

 SSM makes the standard mo re stringent (17730, 17868, 17902)

 SSM is a significant burden (17774, 18447)

 Concerned that the emission limits apply at all times, including SSM periods (17197, 17675, 17725, 17728, 17729, 17732, 17736, 17737, 17756, 17758, 17761, 17774, 17775, 17808, 17815, 17870, 17886, 17904, 17912, 17928, 17930, 17975, 18037, 0234-19536/19537/19538, 0234- 18023)

 State limits should not apply duri ng SSM periods (17383, 17704, 17712, 17724, 17720, 17725, 17730, 17736, 17752, 17774, 17813, 17820, 17868, 17876, 17885, 17904, 17909, 17925, 18014, 18429, 18498, 19032, 19120)

 SSM data should not be included inthe 30-day average (16849, 17627, 17767, 17772, 17774, 17904, 18428, 19120)

 Including SSM could result in exceedances of the 30-day standard or noncompliance (17730, 17868, 17930)

 Requests an exemption duri ng SSM periods (17637, 17820, 18498).

Comment 4: Commenter 17930 states that the EPA has a l ong history of exempting SSM periods from NSPS and NESHAP, and this should continue. Co mmenter 19121 states that startup and shutdown emissions have historically been exempt . Commenter 17851 states that before the Sierra Club v. EPA decision, the D.C. Circuit consistently held that technology-based standards must contain exemption or less stringent standards during SSM than would apply during steady state periods, and cites several court cases regarding the EPA’s previous treatment of SSM events, including, Portland Cement Ass’n v. Ruckelshaus (1973), Essex Chem. Corp. v. Ruckelshaus (1973), NRDC v. EPA (1988), Marathon Oil v. EPA (1977), and National Lime Ass’n v. EPA (1980). Commenter 17851 states that now that the court decided that MACT standards mu st apply during SSM, the EPA must develop standards that are “achievable” during those events.

Comment 5: Commenter 17856 sees many compliance and enfor cement issues arising from the startup and shutdown provisions. Commenter suggests th e EPA adopt reasonable startup and shutdown provisions.

Comment 6: Commenter 17868 provides an example calcu lation and a graph showing the hours of SSM it would take to exceed the 30 -day standard as a function of normal emission rate, given various SSM emission rates in lb/MMBtu. In the example ca lculation, commenter 17868 stat es that if the normal emission rate is 0.02 lb/MMBtu and the startup emi ssion rate is 0.45 lb/MMBtu, then a unit could have only 16.7 hours in startup before ex ceeding 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 Industria l Boiler MACT, which requires work practice standards be met during periods of startup and sh utdown, the Utility NESHAPs Rule requires numerical emission limits. The EPA asserts th at startup and shutdowns are pred ictable and routine aspects of source operations; thus, a 30-day av eraging period should be suffici ent to smooth any startup and shutdown emissions. The commenter disagrees with this assertion. Startups and shutdowns are not always routine and a 30-day averaging period will not always be enough to smooth out the emission400 averages. The EPA has not provided justification as to why the work practice standards, as allowed under CAA 112(h), should not appl y during periods of startup and shutdown. The commenter recommends that the EPA should adopt work practice standards during periods of startup and shutdown for sources subject to the rule.

Response to Comments 1 - 6: For periods of startup and shutdow n, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the propos ed rule and this final action.

b. Economic.

Comment 7: Commenter 17772 states that the capital co st 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 ad ditional multimillion dollar controls that may not otherwise have been nece ssary. Commenters (17815, 17904) state that installing additional APCDs to target startup/shutdown emissi ons does not make economic sense considering the startup/shutdown time and the amount of emi ssions 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 preambl e for discussion.

c. No APCD experience.

Comment 8: Commenter 18498 states that facilities have no experience with the APCD and additives necessary to comply with the standards, and facil ities cannot predict what emissions may occur during startup/shutdown or how compliance can be achie ved 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, wh en the facility has no way of knowing through any scientific means or method what the “compliance st andard” for continuous compliance will be until the equipment is first tested. Accordingly, the commenter requests that the agency remove this requirement and replace it with a number derived from the ICR da ta base with a reasonable allowance added for the operational flexibility needed to assure compliance under the “worst fore seeable circumstances.”

Response to Comment 8: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the propos ed rule and this final action.

d. Not able to achieve the standard.

Comment 9: Multiple commenters (17383, 17689, 17712, 17740, 17813, 17876, 17885, 17930, 19032) state that applying MACT limits dur ing startup/shutdown places the so urce at risk of noncompliance. Commenter 17775 states that limited data from startup and shutdown events show these events can cause significant compliance concerns. Commente rs (17774, 17877) state that the EPA has no factual basis to conclude that even the best performi ng sources can achieve the standards. Commenter 17736 states that the EPA’s flawed assumptions are deva stating in that some of the most technologically advanced units (controlled with overfire air; SCR; F GD; and FGD plus SCR) will not be able to achieve the MACT limits during SSM periods. Commenter 17795 states that some units may be forced to operation at economic loss for no reason other than to generate enough full lo ad operating data to comply, and potentially displacing units that have 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.

 Commenters (17383, 17689, 17712, 17724, 17813, 17876, 17885) note that more than one outage could mean noncompliance.

 Commenter 17868 states that one outage could cause an exceedance.

 Commenter 19032 states that outages could put a unit in noncompliance.

 Commenter 17868 states that forced outages are out of the utility’s control.

 Commenters 17756, 17775, 17820 state that units with more than one SS will be penalized with significantly higher emissions and also a smaller number of operating hours.

 Commenter 17767 states that if a unit that expe riences a difficult, lengthy startup, compliance with the 30-day averages would be difficult or unachievable.

Response to Comment 9: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the propos ed rule and this final action.

e. 30-day average not sufficient.

Comment 10: Commenter 17904 believes the EPA has taken a positive step in establishing a 30-day average. Commenter 19121 generally supports the 30-day average, if non-Hg HAP are to be regulated.

Comment 11: Commenter 17877 states the 30-day averagi ng period is not sufficient to allow compliance. Commenter 16849 states the 30-day av erage period is too short. Commenters (17807, 17886, 17925) state that the EPA has not demonstrat ed the 30-day averaging period will enable compliance. Commenter 17740 states that varying operating modes experienced by EGUs make a 30- day averaging period impractical or impossible. Commenter 17930 states that 30-day average is not sufficient to account for the variability of lignite.

Comment 12: Several commenters (17775, 17795, 17877, 17925) st ate that a 30-day averaging period is not sufficient to account for startu p/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 suffi cient to account for varying load conditions and SS.

 Commenter 17728 states the EPA cannot assume that a longer averagi ng period accounts for startup/shutdown, and the EPA provide s no data to support the assumption.

 Commenter 17740 states that examination of EGU operations demonstrates that a 30-day average is insufficient to account for variable emissions from multiple startups and shutdowns.

 Commenter 16849 states that every SSM produces em issions that will be problematic for the averaging period.

Comment 13: Commenter 17740 states that EPA’s statement that EGUs “do not normally startup and shutdown frequently” effectively, and incorrectly, assumes that all units are operated as base load units. As the Seventh Circ uit recognized in United States v. Cinergy , “[u]tilities operate power generation equipment in three general ways: base load, cy cling, and peaking.” 623 F.3d 455, 459 (7th Cir. 2010). Non-base-load units start up and s hut down frequently, and even s upposed “baseload units” are often,402 and unpredictably, shut down for un it “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 shutdo wn. The EPA made this same faultyassumption 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-da y rolling average will address the substantial operating variations among EGUs or even within anEGU. 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 theywere newly constructed. Thus, an older EGU with highly efficient controls may not be able to meet a 30-day standard in months in which it experiences a number of forced outages.

Response to Comments 10-13: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission li mits. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is discus sed in the preambles to th e proposed rule and this final action.

f. Normal plant operations/ou tages/describe SSM periods.

Comment 14: Commenter 16849 states that SSM are part of power plant operations and facilities should not be penalized for these occurrences. Further, commenter asserts th at providing no exemption during startup/shutdown is an unr ealistic expectation. Commenters (17878, 19114) state that SS(M) are part of normal operation. Commenter 17737 states th e EPA should consider st artups part of normal operation. Commenter 17772 states that even top perf ormers 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 requi re an extended period of startup during which equipment (boiler, control devices) ar e not operating in their normal conditions, and this extended period cannot be shortened or avoided. Commenter 17737 states th at several factors can lead to multiple startups or long periods of startup, including equipment pr oblems (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 co mpliance standard based on 30 boiler operating days. Commenter 17737 provided a list of startups and co rresponding bypass times allowed in their Title V permit in 2010.

Commenter 17795 states that their un its startup and shutdown frequen tly, 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 star tups during the first 30 days of 2010 for several typi cal units: unit 1 had 12 startups; unit 2 had 5 start ups; 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 star tup, 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 requi re a period of time to reach peak performance (temperature and flows). Commenter 18498 states thatadequate time is needed for APCD to operate prior to measurement of filterable PM.

Commenter 17774 states that many units have multiple startup/shutdown events within 30-day period due to varying load demand or maintenance, and out ages that may or may not meet the criteria of malfunction. Commenter 17740 states it is not uncomm on for their plant and other similar units to experience more than one startup within 30 days due to forced outages and planned maintenance. Commenter 17316 states that the averag ing period is only appropriate if the number of startups is small and the duration is normal. Commenter 17877 states it is unreasonable to assume a large EGU will only SS once during a 30-day period.

Commenters (16849, 17923) describe th e 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 emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is discussed in the pr eambles to the proposed rule and this final action.

g. Peaking units.

Comment 15: Several commenters (17725, 17820, 18014, 18498) stat e that even with relatively long averaging periods (30-day rolli ng averages), the emissions from nonrepresentative periods could significantly affect averages, especially for peaking units or other units that come online and offline frequently. Commenters (17715, 17757, 19114) state that including star tup/shutdown periods have a great effect on peaking units thatstartup 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 pe riod will not work for EGUs (e.g., dispatchable) that are in service for short periods (e.g., part of a day) and startup/shutdo wn periods represents a significant portion of the operating day.

Commenter 17820 states that units that are requ ired to follow load de mand will be penalized. Commenter 17774 states that the EPA does not accountfor load-following units or units used on a sporadic basis. Commenter 17774 states that a number of their units foll ow load, cycle, or are otherwise subject to numerous startup/shutdown periods. Comm enter 17623 states the EPA’s analysis is flawed because it did not account for load following or load cycling facilities, which startup and shutdown on a more frequent basis and ha ve 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 deci sions by distant RTOs. Commenter 17772 states that many EGUs are RTO members and mustfollow RTO directives to shutdown or run at minimum loads.

Comment 16: Commenter 17930 agrees generally that coal -fired baseload units do not SS often, however this is likely to be less of the norm. Commenter 17704 agrees that base load units do not typically startup and shutdown fre quently, however, that is changing and cite a new nodal system in Texas that may increase the frequency of startup/ shutdown events. Commenter 17795 states that recent404 regulation changes, Cross State Air Pollution Rule (C SAPR), could cause units to cycle more in the future placing greater emphasis on potent ial effect on SSM on average emissions.

Comment 17: Several commenters (17720, 17758, 16849, 17930) disc uss the use of renewable fuels. Commenter 17720 notes that the EPA’ s assumption that startup/shutdow n periods are predictable and routine does not take into account the increasing impact of renewa ble 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 predictabl e and routine, the incr eased cycling (unplanned outages) to accommodate renewables results in in creased startups and shut downs. Commenters (17758, 16849) note that the overall impact of cycling reduces overall emissions because fossil units are used less and renewables are used more. Commenter 17758 states the small emission increase during startup/shutdown periods is likely dwarfed by avoi ded emissions due to renewable facility operation. Commenters (17758, 16849) state the EPA should not penalize envir onmentally friendly practices. Commenter 17758 states the emission benefits asso ciated with increase operation of renewable resources exceed those realized by imposing numer ic standards during startup/shutdown periods. Commenter 17868 states that includi ng SSM activities are a concern be cause 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 al low an emission calculation based on an emission factor for SSM, and suggested a simple calculation based on fuel feed rate multiplied by a predetermined emission factor will give an accurate measurement of emissions, rather than the onerous requirement to monitor fuel flow rates and sample fuel to determine heat content and composition.

Response to Comments 15 - 18: For periods of startup and shut down, the EPA is finalizing work practice standards instead of numeric emission li mits. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is discus sed in the preambles to th e proposed rule and this final action.

h. Monitoring plan/suggested startup/shutdown approaches.

Comment 19: Commenter 17316 recommends thatfacilities establish a maximum allowed duration for startup/shutdown periods in the Monitoring Plan. Commenters (17316, 17386) st ate if startup/shutdown hours exceed a certain proportion of total operating hour s in the 30-day operating period (e.g., more than 20 percent), then startup/shutdown periods s hould 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 preambl e for discussion.

i. Not clear how SSM included/no basis for standard.

i. General.

Comment 20: Multiple commenters indicate that data used for the MACT floors are not representative of startup/shutdown conditions, and pr ovided 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 re quired shutdowns (17761)

 EPA does not have emissions data for st artups/shutdowns for EGUs (17732, 17756, 17851)

 EPA never collected and analyzed a sufficient amount of data (17736)

 Facility does not have startup or shutdown emission data (17722, 17737)

 EPA does not have sufficient information or data on SS(M) emissions (17795, 17736, 17402)

 Data was during regular operation (17732)

 Application of the MACT st andards during SSM periods is inappropriate (17623, 17774, 18037)

 EPA has not accounted for emissions, or hi gher emission levels, from SS (17730, 17736, 17761, 17772, 17816, 17821)

 EPA cannot apply a single standard th at 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 cons ider whether performance standards would be practicable at EGUs during star tup/shutdown periods. Commenter 17722 questions whether the EPA has correctly evaluated startup/shutdown periods in setting the li mits. In addition:

 Commenters (17197, 17627, 17704, 17715, 17716, 17722, 17724, 17725, 17728, 17730, 17732. 17736, 17752, 17757, 17761, 17767, 17774, 17775, 17808, 17820,17870, 17876, 17877, 17878, 17886, 17904, 18014, 18037, 18428, 18498, 19114, 18023) state that stack testing data submitted (under the ICR) did not include SSM pe riods but was for normal, steady-state operation. Commenter 17851 states that all data was collected under steady-state conditions. Commenter 17736 states the MACT limits are base d on full load steady state testing, and not on the full range of operating condi tions, including changes in operating variables. Commenter 17736 states that data that is limited to a single operating ch aracteristic under utopian conditions is insufficient and inappropriate for establishing MA CT limits that must be satisfied at all times.

 Commenter 17767 states that no attempt wa s made to quantify emissions from startups/shutdowns during deve lopment of the emission limits. Commenter 17925 states no stack test data exists for startups/shutdown.

 Commenters 17772, 17774, 18428 state EPA analyzed s hort-term testing (snapshot) of EGUs under normal operation conditions. Commenter 19114 st ates it is impossible to declare the MACT floor includes variability adjustments fo r SS when EPA possesses no test data to support the declaration. Commenter 17761 stat es the rules fail to account for operational variability and required shutdowns and do not a ppropriately represent emissions that can be consistently achieved.

 Commenter 17925 assumes EPA used isokinetic st ack testing during normal operation, without regard to actual emissions lim it, or used arbitrary non-isokine tic assumptions to quantify SS emissions.

 Commenter 17925 does not understand how the EPA in tegrated startup/shutdown emissions into the 30-day standard.

 Commenter 17774 notes in particular that no malfunction data was incorporated into the MACT floor.

Commenter 17736 states that EPA should recognize thes e 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 start up emission data, and note that Hg emissions spike during startup. Commenters (17383, 17724, 17876) request that the EPA provide a clear analysis of this406 startup Hg emissions data with respect to the de velopment 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 emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is discussed in the pr eambles to the proposed rule and this final action.

ii. The EPA not demonstrated that limits are achievable.

Comment 21: Commenter 19114 states that by setting a limit to include startups/shutdowns but basing the limits solely on full load, steady-state test data, the EPA is violating the requirements of the CAA to set achievable standards. Commenter 17772 notes that the EPA’s approach understates the true average emissions of top 12 percent. Commenter 17878 states th at the emission standard is lower than the rate “achieved in practice” by the best performi ng units. Commenter 17761 states that the EPA inappropriately established standards that do not reflect the “avera ge emission limitation” achieved by the best performing 12 percent of existing sour ces. Commenters (17724, 17876) state the EPA must evaluate startup/shutdown emissions to demonstrat e that the limits are ach ievable. 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 establ ished an emission standard that can actually be achieved during SSM, as required by statute. Co mmenters (17851, 17878) state that MACT standards must be based on evidence that sources have ach ieved them. Commenter 17851 states that standards must be achievable under the most adverse circumstan ces which can reasonably be expected to recur.

Comment 22: Commenter 17732 states the EPA should explain what data was used to come to the conclusion that a single standard can be met at all times, in cluding startup/shutdown periods. Commenter 17737 states that EPA provides no data or an alysis to demonstrate that coal-fired EGUs will be able to meet the standard including SS peri ods. Commenter 17851 states the EPA must demonstrate why facilities can comply with th e final standards. Commenter 17851 st ates 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 evalua te the ICR data to identify startup/shutdown emissions. Commenter 17722 requests that the EPA de monstrate how the ICR data is inclusive of startup/shutdown emissions for each regulated po llutant. Commenter 17772 states the EPA failed to quantify the level of any start up/shutdown adjustment, explain its methodology for taking SSM into account, and has not used real data for an adjustme nt, and thus the emission limits are arbitrary and capricious. Commenter 17815 states it is unclear how much SSM data was included in the analysis.

Comment 23: Commenter 18023 states that the impact of a single startup or shutdown event is unknown. Commenter 18428 states that representations by the EPA and other stakeholders that a number of units already meet the proposed limit are based on stack test dataand not on continuous monitoring over 30-day periods, so these represen tations are incomplete at best. Commenter 18023 states that the EPA has not shown through analysis that startup and shutdown events will not have a significant impact on the 30-day averag es 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 lo ad during SSM and load swings by use of a 30 day averaging period is not s upported by data. Commenter 17758 states the EPA has not demonstrated that the 30-day average will enable compliance, and the EPA’s assumption is unsupported by data from actual units. Commenters (17728, 17729, 17775, 17756) state the EPA has no way of knowing if the 30- day average is sufficient to addres s unpredictable startup emissions. If the EPA cannot demonstrate, then407 commenters (17724, 17876, 19032) state thatstartup/shutdown periods sh ould be excluded from 30-day
averages.

Response to Comments 21 - 23: For periods of startup and shut down, the EPA is finalizing work practice standards instead of numeric emission li mits. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is discus sed in the preambles to th e proposed rule and this final action.

iii. Burner inspection outage.

Comment 24: Commenter 17761 states that at a minimum, with the mandatory burner inspection requirements that impose an additio nal startup and shutdown on facili ties, the EPA should take into account the emissions from the mandatory startup and shutdown precipitated by its own rule in establishing the “best performing” sources. Commen ter 17930 states that rule requirements for annual shutdowns, for burner tune-ups, will increase the frequency of base load units being shutdown, along with the suit of other EPA regulations. Commente r 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 treatme nt of startup and shutdown periods discussed in the response s under this section (see Responses to Comments 1-23, above), EPA also notes that the final rule adjusts the fre quency of burner inspections to once at least every 36 months (or 48, in certain circumstances), so that the inspections can be tter coincide with planned unit outages. See further discussion under section 4D 02 of this document.

iv. Burner inspection requirement.

Comment 25: Several commenters (19536, 19537, 19538) state that during SSM events, organic HAP emissions are known to increase for short periods due to low boiler combustion temperatures, poor mixing, and low excess oxygen levels. Commenters state that the proposal is sile nt as to how an annual tuneup would assure organic HAP emissions remain controlled during SSM periods.

Response to Comment 25: Under the general provi sions 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 (inc luding 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 un its under the same conditions to verify emissions are repeatable and sust ainable over operating periods that include startup/shutdown periods. Commenters (17732, 17772, 17774, 17877) state the EPA shoul d collect and analyze data for emission standards during SS(M). Commenter 17737 states EPA should collect a nd analyze emissions data to evaluate the compliance risk associ ated with inclusion of startup periods in the MACT standard for normal operations. Commenters (17815, 17904) state that the EPA should analyze excess emission reports to determine the frequency of startups/shutdowns and include that analysis in the standards.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 applying adjustments to the limits to allow for differences in operation conditi ons. Commenter 17930 states the EP A 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 fo reseeable 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 comm ents. See the preamble fo r discussion. The EPA’s rationale for its approach to malfunctions is discus sed in the preambles to th e proposed rule and this final action.

vi. Variability component.

Comment 27: Several commenters (17725, 17820, 18014, 18037, 18498, 18539) state that the EPA does not have sufficient data (either reference me thod or CEMS data) to a ddress variability during SS(M) periods and load changes (17820). Co mmenters 17730 and 17761 state startup/shutdown emissions must be adequately accounted for in th e variability component. Commenter 17886 states the EPA should revise its variability adjustment to account for long term unit emissions variability. Commenters 17724 and 17876 state that the variability component of the MACT floor calculation drives the final emission limit more so than the mean value of the data set. Commenters 17724 and 17876 further state that the variability component coul d be drastically differe nt with inclusion of startup/shutdown emissions data, resulting in a hi gher limit. Commenter 17722 states the EPA would develop a much different emission limit if startu p/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 emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is discussed in the pr eambles to the proposed rule and this final action.

j. SSM results in increased emissi ons/distinct operating modes.

Comment 28: Commenters 17730 and 17740 state SS(M) periods are distinctly different modes of operations from normal operation. Commenters 17705 and 17757 state that startup/shutdown periods have different emission characteristics than em issions during normal operations. Commenters 17715 and 19114 state that startup/shutdown em issions are not similar to st eady state full load emissions. Commenter 17878 states that SSM pe riods result in increased emissi ons rates. Several commenters (17715, 17757, 17856, 19114) state increased emissions duri ng 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 transi ent conditions such as significant load changes will result in emissions in excess of those measur ed during initial performa nce tests. Commenter 17851 states that emissions during non-steady st ate conditions may vary significantly.

Several commenters (17808, 17870, 18025) note that, as in the Boiler MACT, ma lfunctions should not be considered a distinct opera ting mode. Commenter 17851 disagrees with the EPA that malfunctions are not distinct operating modes.409 Commenter 18023 states that start up is a distinct operating peri od and it should be considered independently. Commenter 18023 provide s Hg CEMS data showing two distinct emission profiles for periods of startup (when SCR is off line due to low temperature) and for periods of steady-state with full control (when both SCR and FGD AP CD systems are operating). Comm enter 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 re viewed 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 c oncentration for a short amount of time, most likely from Hg deposited on ducts an d 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 emissi ons 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 av erages of pollutant concentration and hourly average of stack flow; these probl ems are worse when the mass is normalized to lb/GWhr using a 5 percent of full power output, which will artificially in flate 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 f acility has 18 months of PM CE MS data with startups/shutdowns included that shows fully controlled units will not be able to comply with the emissions limit. The commenter provides graphs of 30-day boiler operati ng 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, Do cket Item No. The EP A-HQ-OAR-2009-0234-17772.) The commenter indicates that 0.018 lb/MMBtu is represen tative value for filterable PM, however, with startup/shutdown values included, th e representative value is 0.29 lb/M MBtu (includes low flow rates, high concentrations, and CO 2 diluent of 5 percent), which is 16 times higher.

Commenter 17795 provides average SO 2 emissions data for 30 boiler operating days that include two startups, showing that SSM occurred for 10 perc ent of operating hours during the period and that including SSM emissions results in an increase of 13 percent in the 30-day average emission rate.

Response to Comment 28: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed 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 provi sion 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 b ecause we are establishing work pr actice standards for such periods. Because the proposed 5 percent f actor does not apply to malfuncti on 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 m easure emissions during ma lfunctions periods. We believe that it is important to collect data during a ll process operating periods including SSM periods, as the rule requires when conducting any continuous monitoring (see additional responses below relative to the accuracy and utility of such data). The agency also believes EGU owners or operators strive to minimize periods of malfunction and should a malfuncti on period occur, its duration will be brief, as410 noted by the commenter. Any impact of potential excess emissions occurr ing during a period of malfunction should be offset to some degree throu gh use of the rule’s 30 bo iler 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 e rror, the owner or operator can demonstrate that the source complied with the standard notwithstandi ng the CEMS measurement using any available information. See also responses below that addr ess the issue of determining compliance during malfunction events.

k. Use of CEMS during startup/shutdown.

Comment 29: Several commenters express concerns rega rding the use of CEMS for measurement during startup/shutdown. Commente rs (17677, 17728, 17729, 17775) also indica te it is not feasible to measure compliance with CEMS during startup; commenters cited the following issues for startup/shutdown, including temperature i ssues (17728, 17729, 17815), low flow rate (17815, 17728), and varying moisture (17729). Commenter 18498 states that part iculate size varies during startup/shutdown and cannot be measured accurately by PM CEMS. Comme nter 18498 states that startup/shutdown periods present wide variations depending on the process and control equipment. Commenter 17728 states the EPA does not account fo r the absence of correlated PM CEMS during startup/shutdown periods. Commenters ( 17728, 17736, 17752, 17772) state the PM CEMS correlation curves do not include any data during SSM peri ods. Commenters (17728, 17752) state the PM CEMS cannot be correlated and the accuracy of PM CE MS data during those conditions is unknown, and commenter 17736 states the correlation can only be done during normal operating loads. Commenter 18498 states that PM CEMS are calibrated for no rmal operating conditions. Commenter 18498 states that startups/shutdowns present si gnificantly different conditions th at are not part of PM CEMS calibration.

Commenters 17677 and 17775 state that CEMS are not correlated to startup/s hutdown periods because the EPA reference test methods we re not designed for transient or dynamic plant operations. Commenter 17677 questions the enforceable value of these data, and states the EPA needs to consider the ability for CEMS to accurately monitor emissions in startu p/shutdown periods. Commenter 17772 states the PM CEMS data from startups/shutdowns are not reliable and highly variable. Commenter 17886 states they do not know of valid test or CEMS measuremen t techniques for HAP during startups/shutdowns. Commenter 17736 states that most units do not start up on coal but use other fuel s (e.g., fuel oil), and a PM CEMS that was correlated for coal does not m easure emissions accurately. Several commenters (17725, 18014, 18498) state that particle size distribution or unburned leve ls during startup affect PM CEMS measurement accuracy, particul arly those using light scattering or optically-based technologies; commenter 17728 states that the part icle size distribution may differ fr om those in the correlation.

Several commenters (17725, 17820, 18014, 18498) state that including SSM is critical for units using PM CEMS to demonstrate continuous compliance, since part 63 no longer includes exemptions for SSM.

Commenter 17925 states that there ar e very few CEMS in operation to provide data to confirm that limits can be met during startup/shutdown.

Commenters 17774 and 17821 relay thatthere are operation problems for sorbent trap CEMS to demonstrate compliance with Hg limits during startup; Commenter 17774 cites the following for sorbent trap CEMs: demonstrate poor performance, flue gas conditions are unacceptable, and interferences cause breakthrough.411 Response to Comment 29: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emissi on limits and thus commenters con cerns related to reliance on CEMS during such periods is moot. See th e preamble for discussion. The EPA’ s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule a nd 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, s ee responses below that address the issue of determining compliance during malfunction events.

l. The EPA assumptions/justifications.

i. Support or oppose EPA’s assumptions.

Comment 30: Multiple commenters (17728, 17740, 17758, 17774, 17775, 17807, 17808, 17851, 17870, 18023) disagree with the EPA’s rati onale and assumptions for includi ng startup/shutdown in the MACT standard. Commenter 17740 states that the EPA’s justification for not establishing different requirements for startup/shutdown (include (1) EGUs do not normally startup and shutdown frequently, and (2) EGUs typically use cleaner fuels during startup) are unsupported and do not reflect actual EGU operating practices). Several commenters ( 17728, 17729, 17756, 17775) state the EPA’s rationale does not account for the variety of ways EGUs startup and shutdown (types of fuel, duration varies), and is not based on actual emission observations dur ing startup/shutdown (17728, 17775). Commenter 17807 states the EPA has not justified these assump tions based on actual startup/shutdown data.

Multiple commenters cited concerns about EPA assumptions regarding SSM and made statements such as the following: startup/shutdow n periods are predictable and r outine (17691, 17821); startup/shutdown periods are not predictable and routine (17807, 17758); EGUs do st artup and shutdown frequently (18447); base load units do have startups and s hutdowns (17772); EGUs do not startup frequently (17851); solid fuel-fired EGUs st artup infrequently (17815); the dur ation of startup/shutdown is reasonably predictable (17316, 17386); the duration of startup can vary significantly (17756); the emissions during startup are variable (17316, 17386), due to transient combustion conditions (17386), affected by length of time unit has been shutdown (17316, 17386), and affected by ambient conditions at lite-off (17386); the number of startu ps in a given period can vary ( 17756); frequency and duration of startup/shutdown varies by unit a nd fuel blend (17758, 17807); base load units generally operate for long periods without an outage (177 37); and historically, planned outag es for maintenance and repair were fairly predictable and routine (17720, 17758).

Response to Comment 30: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is discussed in the pr eambles to the proposed rule and this final action.

ii. Cleaner fuels.

Comment 31: Commenter 17740 states that units burn a wide array of fuels and the EPA cannot assume without additional justifi cation that EGUs rely on cleaner fu els during startup. Commenters 17740 and 17774 also state that emissions may be higher than normal during startu p periods, even when alternative (cleaner) fuels are used. Commen ter 17728 states the EPA cannot assume that use of cleaner fuels accounts for startup/shutdown periods, and the EPA pr ovides no data to support the assumption (flue gas conditions and particle size distri bution may differ significantly duri ng startup/shutdown than other periods). Commenter 17737 takes little comfort in th e 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 bypass (FF, ESP) to a void oil residue fouling, and Commenter 17737 states that bypass occurs until flue gas en tering the FF is 160 oF. Commenter 17756 states that they use oil for some units and use NG for others during startup. Commenters 17702 and 18018 state that many EGUs use oil for startup when NG is not available. Commenter 17702 states the EPA should consider an exception during startup/shutdown when an EGU is fo rced to use oil or when NG is not available. Commenter 17758 states the EPA has not provide d support that use of different fuel for startup/shutdown would minimize emissions. Commenters 17815 and 17904 agree that solid fuel-fired EGUs typically startup on cleaner fu els, however note that some fire and transition to solid fuel during startup.

Commenters 17808 and 17870 state that most EGUs will switch fuels during startup, but for shutdown some will not switch fuels. Commenter 17702 states th at manufacturer protocols for control equipment require additional delays for equipm ent startup when oil is used.

Response to Comment 31: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. See the preamble for discussion.

iii. Combustion inefficient.

Comment 32: Commenter 17925 states that combustion is unstable (during startup), and design emission rates may not be achieved. Commenter 19114 states there are incr eases in products of incomplete combustion (PICs) (during startup). Co mmenter 17851 states that even when using cleaner fuel, the combustion process is inefficient during startup. Comm enter 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 preambl e for discussion.

m. APCD not operated.

Comment 33: Numerous commenters (17316, 17386, 17402, 17623, 17675, 17715, 17740, 17757, 17774, 17820, 17851, 17904, 17930, 18539, 19114) state that APCDs do not operate during startup or most of startup; commen ters (17725, 17757, 17820, 17904, 18014, 18498) stat e 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 br ought 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 excep tion 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 recommendati ons and/or good engineering practices for APCDs. Commenters (17815, 17904) state that solid fuel-fired EGUs operate with ma nufacturer-established constraints on APCDs during st artup. Commenter 17815 states that manufacturer limits on APCD constrain an EGU’s ability to comply with th e standard during start up/shutdown. Commenter 17925 states that APCDs are not designed for highe r loadings during startup/shutdown. Commenter 17930 states that manufacturer’s recomm endations protect APCDs against failure, explosive conditions, and413 ensure long-term functionality. Commenter 17740 st ates 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 bypasse d under certain operating conditions. Commenter 19114 states that APCDs need to achie ve stable operating temperatures or other conditions. In general, fabric filters must have a specific stack gas temperature to avoid dama ge or failure of the bags (17851, 17740, 19121), and damage to the FF (17740, 19121). Comm enter 19121 states that FF use during high loading of fuel oil cause bag blinding. Commente r 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 efficien cies. In general, ESPs must have a specific stack gas temperature (17740, 17930) to avoi d short-term stability problem s (17740), unsafe actions and longterm degradation due to fouling (17740), increased chances of wire damage (17740), or increased corrosion in chambers (17740). Commenter 17930 states that ESPs are on 85 percent of the coal-fired fleet. Commenter 17740 states that SDA require a minimum temperature, b ecause the slurry feed rate is limited by the amount of moisture that the flue gas can evaporate. Commenter 17881 states that requiring the FGD system to operate during SSM, if technically feasible, is a waste of reagent, increasing ratepayer costs while providing no emi ssion reduction or environmental benefit, damaging equipment and further resulting in unplanned shutdowns.

Commenter 18447 cites concerns for th e safety ramifications of the rule. Commenter 18447 states that the EPA does not understand how to operate a boiler and the procedures that ar e necessary to operate safely during startup/shutdown. Commenter 18447 states that during shutdown or malfunction, the fuel to the boiler is shutdown and the ESP is powered down, to preven t unburned fuel from exiting the boiler and passing into the ESP where it would be ig nited by the ESP if it remained powered up.

Commenter 17740 states that the warm-up time could theoretically be reduced by ramping up the fuel rate, but plants closely follow OEM warm-up peri od recommendations to avoid severe refractory damage and excessive metallurgical stresses due to rapid changes in te mperature and wide variations in temperature across boiler and duct parts. Commente r 17740 states inconsistent heating could cause immediate failures such as tears or ruptures in su pport steel or heat transfer surfaces, posing risk to personnel. Commenter 17740 notes that failure rates w ould increase if rapid heat ing and cooling cycles were conducted, which would further increase startups and shutdowns.

Commenter 17772 states that if cool ing pumps fail at shutdown, immedi ate bypass is necessary to avoid melting fiberglass tubes.

Commenter 17740 provides an example facility, a single unit plant that has upgraded with installation of new control equipment (SCR, FGD, and PJFF) that is considered BDT, modification of plant heat rejection system, and improvements to the boiler. Commenter 17740 states that the plant cannot operate the SCR and FGD during startup when the flue gas temperatures and boiler steam pressure are lower than required. The commenter indicates that the current permit limit requires lb/MMBtu for SO 2 and NO X on a 30-day rolling average; the plant can meet th e permit limits if there is only one startup within a given 30-day period, however, additional startups significantly 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 emission limits. These work practices take in to 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 pr oposed rule and th is final action.

n. APCD not efficient.

Comment 34: Numerous commenters (17402, 17623, 17705, 17715, 17725, 17736, 17757, 17758, 17772, 17774, 17807, 17808, 17820, 17821, 17870, 17877, 17902, 18014, 18498, 18539, 19114) state some APCDs do not operate efficiently (or optimum performance) during SS(M) periods. Commenter 17736 states that even the most advanced techno logies have lower removal efficiencies during startup/shutdown periods. Commenter 17736 states that the EPA failed to recognize that control technologies cannot achieve the re lied-upon result every hour of eachday 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 woul d be required when APCD is fullyfunctioning. Several commenters (17758, 17772, 17774, 17807, 17821) state that emissions ma y be greater duri ng startup/shutdown periods because APCDs do not operate efficien tly until steady-state is achieved. Commenter 17856 states SO 2 emissions are higher fr om the scrubber and NO X and Hg emissions from SCR are higher during first few days of startup. Commenter 17725 stat es there may be periods when a source would not be able to comply with the standards because the control device does not operate at peak performance until certain operating conditions and flue gas temp erature are achieved. Commenter 17821 states that FGD systems require 24 to 36 hours fo r startup to develop the proper sc rubber liquor chemistry, and to achieve the SO 2 emission reduction.

Commenter 17736 states that ESPs yield lower rem oval efficiencies during startup due to low temperatures; Several commenters (17736, 17772, 17821) state that SCR effectiveness cannot be realized until the unit reaches a specific temperature. Commenter 17821 notes that the SCR performance impacts Hg oxidation and stack Hg emissions and therefore impacts the ESP performance. Commenter 17772 states that SCR contribution to Hg removal is high during normal operation, with the scrubber and ESP achieving 90 percent Hg removal, but is minimal during startup where the scrubber and ESP achieve approximately 65 percent Hg removal.

Commenter 17975 states that the EPA has failed to consider whether FF or other APCDs can substantially reduce emissions during startup/shut down and maintenance. Commenter 17975 states that if other APCDs can reduce emissions , the PM limits must be based on superior techno logies and not those APCDs that are not de signed to operate effectiv ely during startup/shutdown.

Response to Comment 34: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. These wo rk 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 pr oposed rule and th is final action.

o. Rule clarifications.

i. Definition for SSM.

Comment 35: Several commenters (19536, 19537, 19538) state that the EPA does not define startup, shutdown, or malfunction.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 malfunction contained in general provisions (40 CFR Part 63.2) applies.

ii. Period for emissions averaging.

Comment 36: Commenters 17808 and 17870 state that aver aging emissions ove r 30 boiler operating days is only relevant for CEMS but is not re levant for units conducti ng monthly or quarterly performance testing because these EGUs are not av eraging emissions during startup/shutdown periods.

Commenter 17772 suggests that an annual limitation meas ured could be established for SSM periods for uncontrolled emissions for some limited number of hours.

Response to Comment 36: The commenters are correct that th e 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 mech anisms. 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 ap propriate for malfunction events. The EPA’s rationale for its approachto malfunctions is discussed in the preambles to the proposed rule and this final action.

iii. Definition of boiler operating day/subpart Da.

Comment 37: Several commenters (17756, 17775, 17820) state th e “boiler operating day” definition is not flexible to account for periods of shutdown, and recommends the EPA specify a minimum number of operating hours necessary to calculate a 30-day ro lling 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 calc ulate an average. Commenters (17820, 17886) suggest the EPA define a “boiler operating day” as operating 75 percent of the day, or 18 hours or more. Commenter 17886 states that operating days should be defined as 18 hours or more operation and if less than 18 hours should be excluded from the 30-day average.

Several commenters (17316, 17386, 17772) indicate that 40 CFR part 60 subpart Da rule revisions exclude startup/shutdown periods from 30-da y averaging. Commenters (17715, 19114) state that excluding startup/shutdown periods from emi ssion limits would follow precedent in numerous rulemakings.

Response to Comment 37: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits so this comment is moot. These work practice standards take into account operation of APCDs. See the preamble for discussion.

iv. Other.

Comment 38: Commenter 17675 states there should be allowa nces for alternative compliance limits or alternative monitoring for startup/shutdow n periods, especially for acid gas and SO 2 , when APCD are416 being brought online (or kept online during shut down). Commenter 17675 recommends that section 63.9991(a)(1)(iii) be modified to allo w a short, 8 to 12 hour, startup.

Commenter 17761 suggests, in conjunction with a longer emissions averagi ng period, that the EPA impose a work practice relative to a time limitati on on what constitutes a st artup or shutdown (e.g., 20 hours for startup, etc.), and to the extent that the startup exceeds the defined time, the facility would either have to abandon its startup e fforts, justify a claim of malfunction, or utilize such emissions during that extended period in the em ission averaging calculation to demonstrate compliance.

Response to Comment 38: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. These wo rk practice standards take into account operation of APCDs. See the prea mble for discussion.

p. Weighting startup/shutdown.

Comment 39: Several commenters suggest that the EPA we ight 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, subpartDa. Commenter 15678 states that fuel specific CO 2 concentration should be used for cal culating emissions in lb/MMBtu during startup/shutdown periods.

Commenter 17886 states that the 30-da y average should be a heat input average, so that emission rates for low fuel burn and heat input are appropriately weighted with higher fuel burn an d 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 wei ght as high flow rates for normal operation. Commenter 17772 states that if there ar e short-term high emissions during shutdown, the emission rate on subsequent days when the unit is not operating (and the emissi ons are zero, but are not recorded because they are not measured during a “ boiler operating day”) will remain elevated, creating additional days of apparent non-compliance.

Commenter 17820 suggests weighting the startup/shut down emissions by adding the mass emissions for each hour (lb/hr) for a total mass (lb) for the 30-day periods and dividing by the sum for each hour of the heat input (mmBtu/hr) for a total heat input (mmBtu) for the 30-day period, resulting in a lb/mmBTU 30-day average that more accurately accounts for startup/shutdown with less impact for startup/shutdown events.

Response to Comment 39: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. See the preambl e for discussion.

2. Separate standards/work practice standards for SSM.

a. Support separate standards.

Comment 40: Several commenters (17730, 17886, 19120) stat e the EPA must establish emission standards for startup/shutdown peri ods. Commenter 17740 stat es that if the EPA does not establish a 12- month rolling average, the EPA s hould establish work practice standa rds for startup/shutdown periods. Several commenters (17730, 17737, 17930) state the EPA mu st establish separate emission standards for417 startup/shutdown periods, or must extend the av eraging time. Commenter 17677 states the EPA should consider removing startup/shutdown data from the c ontinuous compliance demonstration data, or allow manufacturer’s/site best work pr actices. Commenter 19122 recommends hi gher alternative PM limits or a work practice standard.

Numerous commenters (16849, 17383, 17402, 17627, 17638, 17677, 17689, 17712, 17715, 17716, 17720, 17722, 17724, 17725, 17728, 17729, 17730, 17736, 17737, 17740, 17756, 17758, 17772, 17774, 17775, 17795, 17808, 17813, 17815, 17820, 17821, 17870, 17876, 17877, 17878, 17885, 17886, 17902, 17904, 17909, 17925, 17928, 17930, 18025, 18037, 18428, 18429, 18498, 18539, 19032, 19114, 19122, 18023) recommend work practice standards duri ng periods of SS(M). Many commenters (17402, 17627, 17638, 17715, 17716, 17720, 17725, 17736, 17737, 17740, 17756, 17758, 17774, 17775, 17795, 17808, 17815, 17816, 17820, 17856, 17870, 17878, 17886, 17902, 17904, 17925, 17928, 17930, 18014, 18025, 18037, 18428, 18429, 18498, 18539, 18023) note that work practice standards are required in the Boiler MACT rule; Multiple commenters (17383, 17689, 17712, 17724, 17740, 17757, 17758, 17774, 17813, 17876, 17885, 17909, 19032) state that previous (HAP) ru lemakings required work practices for startup/shutdown events. Commenters 17627 and 17816 st ate that the EPA determined in Boiler MACT rule that MACT emissions limits do not apply to startup/shutdow n. Commenter 17740 states the same reasons that the EPA established work practice sta ndards for startup/shutdown periods in Boiler MACT apply here for EGUs, and the EPA offers unsupporte d assumptions as its onl y grounds for continuous compliance with emission standards. Commente r 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 appr oach. Commenters (17878, 18428) state the EGU and Boiler source categories are similar. Commenter 17930 states that wo rk practice standards are more appropriate for startup/shutdown.

Commenter 17623 states the EPA should propose a work practice standard during SSM periods because: emission standards are not practicable; data collected during SSM periods are from CEMS but do not include all pollutants regula ted, particularly Hg from cert ain kinds of CEMS; and emission standards are not economically pr acticable because collecting SSM period data would involve significantly altering measurement techni ques and may require manual monitoring.

Response to Comment 40: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the propos ed rule and this final action See also responses below that address the issue of determining compliance during malfunction events.

b. Sierra Club Decision.

Comment 41: Multiple commenters (16849, 17402, 17691, 17732, 17736, 17740, 17758, 17761, 17774, 17775, 17807, 17808, 17815, 17851, 17904, 17930, 19536/19537/19538) cite the Sierra Club court decision that vacated SSM exemptions . Multiple commenters (17383, 17689, 17712, 17724, 17813, 17876, 17885) agree that court decisions indica te that HAP regulation must account for startup/shutdown events.

Several commenters (17732, 17775, 17904, 17930) state that section 112 only requires that some section 112 compliant standard apply at all times. Seve ral commenters (17732, 17775, 17930) state that section 112 does not require that one standard apply to a ll periods. Commenter 17772 stat es that the court case418 clarified that providing continuous em ission reduction did not mean that a single standard for all periods was required. Commenter 17930 does not s upport the Sierra Club d ecision, and states th at it is clear that the decision does not require one un iform standard at all times.

Commenter 17758 points out that the disc ussion of CAA sec tion 112(h) in the Sierra Club decision and the decision itself do not c onstrain the EPA’s ability to choose wo rk practice standards in lieu of numeric standards. Commenter 17736 states that Si erra Club decision should not be treated as authoritative or supportive of the EPA’s action in th is 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 cas e does not dictate the one rous and potentially unachievable result set forth in the rule. Comment er 17904 states that the EPA has gone well beyond the Sierra Club decision by not only provid ing no exclusions, but also faili ng 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 st andard during SSM is consistent with section 112. Commenter 18539 states that the c ourt has held that emissions st andards could be different for SSM and that work practice standards were perm issible. Commenter 19121 states that CAA does not allow exemptions for SSM.

Commenter 17758 states that EPA cited to Sierra Club v. EPA (551 F.3d 1019) in both the boiler MACT and the EGU MACT and came to disparate conclusions that continuously applic able numeric standards are required at all times. According to the commenter , the court did not find th at numeric emission limits under section 112(d) were required during SS periods . The commenter states that work practice standards under section 112(h) w ould satisfy the requirements of Sierra Club and EPA can choose to use work practice standard in lie u of numerical standards.

Response to Comment 41: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the proposed rule and this final action. As explained in those preambles, the EPA has determ ined 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 malfuncti ons would be difficult, if not impossible, given the myriad different types of ma lfunctions that can occur across all sources in the category and given the difficulties associated with predicting or accounting for the frequency, degree, and duration of various malfunctions that might occur. Setting work practice standards under section 112 presents the same issues as setting numerical emission limits given the varied nature of malfunctions.

c. CAA section 112(h).

Comment 42: Multiple commenters (17716, 17730, 17736, 17740, 17758, 17774, 17775, 17815, 17904, 18429, 18023) cite section 112(h) and state that section 112(h) allows work practice standards. Several commenters (17740, 17774, 17775, 17815, 17904, 18023) note thatemissions cannot be measured during SSM, that it is not feasible to prescribe or enforce an emission standard, and refer to the 112(h) CAA definition of the phrase “not feasible to prescribe or enfor ce” which includes any situation in which the Administrator determines that the appli cation of a measurement methodology to a particular419 class of sources is not practi cable due to technological and ec onomic limitations. Commenters (17716, 17720, 18023) state the EPA must provide a separate work practice standard for SSM because it is not technically feasible to comple te stack testing (a nd monitoring, 17720) during these periods.

Multiple commenters (17402, 17716, 17725, 17736, 17740, 17758, 17820, 17870, 17904, 17925, 18014, 18025, 18498, 18539, 18023) also point out that the EPA found in Boiler MACT that it is not technically feasible to complete stack testing or monitor during startup and shutdown. Multiple commenters (17402, 17716, 17725, 17740, 17904, 18037, 18539, 18023) state the same measurement problems (and technological difficulties, 17740) exist for EGUs. Commenters 17740 and 17758 note that Boiler MACT units and EGUs are substantially similar, and commenter 17740 states that the EPA has recognized previously that ICI boilers and EGUs are virtually identical. Commenter 17740 notes that the EPA attributes differen ces between ICI boilers and EGUs to size of units, boiler/furnace technology, and portion of electrical output for sale, but none of thes e differences allow EGUs to complete testing requirements during startup/sh utdown periods. Commenter 17758 states that EGUs have the same issues as ICI boilers with respect to emission testing.

Commenter 18037 states it is not feas ible to obtain sufficient data for startup/shutdown. Commenters 17725 and 17904 state that no technical feasibility for stack testing and monitoring leaves the EPA and the regulated community without a practical way to accurately determine emissions during startup/shutdown. Commenter 18023 has evaluated stack te sting times and relays that total PM testing would require 8 to 10 hours and metal HAP and acid gas testing would require minimum of 16 hours. Several commenters (17725, 17820, 18014, 18498) state itis uncertain whether representative measurements could be obtained during startup/ shutdown due to dynamic flue gas conditions and technical limitations with measurement technology. Co mmenter 18023 states that startups are transient periods where heat input, fuels, and gas flows conti nually change, and stack tes ting is impossible due to load fluctuations. Commenter 17851 states th at testing during transient conditions is difficult. Commenter 17851 states that running EPA Reference Method 5 during startup would require 6 to 8 hours to complete a single test , but the conditions would have ch anged so significantly it would be impossible to understand what the data meant or extrapolate the data. Commenter 17851 notes the same is true for CEMS data during startup.

Response to Comment 42: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the proposed rule and this final action. As explained in those preambles, the EPA has determ ined 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 malfuncti ons would be difficult, if not impossible, given the myriad different types of ma lfunctions 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 addr ess the issue of determining compliance during malfunction events.

d. Performance testing and measurement issues.

Comment 43: Commenter 18034 opposes any requirement s to require stack testing during startup/shutdown. Commenter 18034 stat es that requiring stack testi ng during potentially dangerous plant operations that could place testi ng 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 collec t condensable and filterabl e PM samples. Commenter 17815 states it is not reasonabl e to establish filterable PM as a surr ogate with no reasonable ability to measure. Commenter 17737 states ther e are significant challenges in co llecting accurate emissions data during startup (commenter cites UARG comments).

Commenter 17912 states that the EPA incorrectly a ssumed that measuring and monitoring equipment will function properly under these conditions. Commente r 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 fo r SSM in the test protocols that influence compliance.

Commenter 17736 states control de vice operating characteristics dur ing full load testing is not representative of the range of operating characteristics that a un it may experience on any given day.

Commenters 17725 and 17904 state that monitoring e quipment cannot operate accurately during SSM periods due to transient flow and flue gas condi tions. Commenter 17725 states that since monitoring data for SSM periods are not repr esentative of normal operations and are of suspect quality, the EPA should adopt an approach where they would not be included in data averages used to determine compliance and missing data substitution procedures. Commenter 17725 recommends that the EPA provide clarity in the rule for how such periods would be treated.

Response to Comment 43: CEMS data during startup and shutdow n will not be used for purposes of calculating 30-day averages under th e final rule. For periods of st artup and shutdown, the EPA is finalizing work practice st andards instead of numeric emission lim its and thus commenters concerns related to monitoring during such periods is moot. See the preamble for discussion.

For malfunction periods, the EPA does not agree with the commenters that CEMS will not provide data during malfunction periods (unless the malfunction is related to the CEMS) and commenters provide no support for their assertion that data cannot be obtained. To the extent an EGU owner or operator has not installed CEMS or believes a CEMS reading duri ng a malfunction event is in error (i.e., shows noncompliance) over the averaging period the EGU owne r or operator may use other available means (including engineering judgment) or information to demonstrate that the source complied with the standard.

e. Suggestions for work practice requirements.

Comment 44: Multiple commenters (17677, 17714, 17725, 17808, 17870, 17902, 17925, 17928, 18025) suggest that work practices should include or be based on manufacturer recommended practices. Several commenters (17725, 17870, 18025) recommend that, as in Boiler MACT, the EPA require units to follow manufacturer’s specifications for minimizing emissions during startup/shutdown (as in 40 CFR part 63.7530(h)). Commenter 18025 also suggests that rather than referring to “manufacturer’s recommended procedures”, the EPA could refer to sta ndard industry procedures to account for instances where more than one manufacturer has supplied different components. Commenter 17772 suggests the work practice standard take into account the boiler configuration, boiler type, and safe operation of the unit. Several commenters (17725, 17774, 19032) state the work practice standard should account for421 boiler type and control equipment. Commenter 17816 states that work practices should be specific to a unit’s boiler type, operational characteristics, and APCDs.

Commenter 17774 states that sources should have to a ddress malfunctions as soon as safely practicable. Commenter 17774 states facilities have large incentives to address malf unctions 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 re asoning for not requiring SSM plans. Commenter 18037 recommends a SSM plan be included in the T itle V permit as an appr opriate work practice standard. Commenter 17691 suggests the EPA should re quire startup/shutdown pl ans, for consistency with the recent Boiler MACT standard, since startup/shutdown even ts are predictabl e and routine.

Response to Comment 44: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the proposed rule and this final action. The EPA is setting standards that apply at all times, incl uding periods of startup and shutdown and periods of malfunction. With such standards in place, sources have ample incentive to plan for and achieve compliance during startup and shutdown and during malfunctions, so there is no longer any reason to require sources to develop SSM plans

f. Operating parameters for APCD.

Comment 45: Several commenters (17820, 17821, 17868) stat e that work practices should be established in lieu of operating parameters for AP CDs. Commenters 17821 and 17868 state that the EPA has no basis to expect that operating parameter lim its 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 appl y during SSM. Commenter 17820 states that operating limits for operating parameters for APCD should not apply during startup/shutdown. Commenters 17820 and 17868 state that the EPA requires sources to establish control device operating parameter levels that are dependent upon load duri ng periods of “maximum normal operating load,” or other frequently used loads, a nd then maintain those levels during other periods, including startup and shutdown.

Several commenters (17820, 17821, 17868) state that the EPA assumptions regarding startup/shutdown are not applicable to APCD opera ting parameter limits, which are base d on 12-hr averages established during the performance test (maximum normal ope rating load) and not based on startup/shutdown. Commenter 17820 states that startups on large units take longer than 12 hours, so there is no allowance for periods of startup/shutdown inthe parameter operating limit.

Response to Comment 45: The final rule does not provide for operating parameter limits for air pollution control devices. Please see the final pr eamble and responses to comments under Comment Code 5A05. For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule a nd this final action.

3. Other averaging periods.

a. General.422 Comment 46: Commenter 17774 recommends a longer complian ce period to provide flexibility and accommodate SSM events. Commenter 16849 suggests a lo nger averaging period, as an alternative to not including SSM hours in the 30-dayaverage. Commenters (17737, 17740, 17795, 17904, 17930, 19122) recommend the EPA establish a 12-month rolli ng average or annual average. Commenter 17772 recommends moving to a 90-day or l onger boiler operating day average.

Commenter 17730 states the EPA must establish se parate emission standards for startup/shutdown periods, or must extend the averaging time.

Commenter 17737 states that if the EPA does not es tablish 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 ope rating 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 averagin g and increase the emissions limit fo r all pollutants to better account for SSM emissions.

Commenter 17740 states that because the EPA is in cluding emissions from non-steady state operations, including SSM and load following operations, the aver aging period should be lengthened to a 12-month rolling average, calculated monthly. Commenter 17740 states that especia lly for single units that cannot be part of a multi-unit plant’s averaging plan, the av eraging 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 st ates that a 12-month averaging period would ensure operational flexibili ty, allowing economic consideration to be part of dispatching and operating decisions.

Commenter 17795 states that there is no logical r eason for providing more fl exibility for facilities averaging multiple units than for facilit ies with a single unit or common stack.

Commenter 17761 states the EPA should extend the averaging period to account for routine and required maintenance, such as the required shutdownand startup required to inspect burners under this rule. Commenter 17761 states that the burner in spection outage time alone, along with required adjustments or repairs, could cause a facility to exceed the 30 bo iler operating day average emission limit, particularly since there is both a shutdown and startup. Co mmenter 17761 states that to comply, facilities will have to take outag e both to install controls and to perform assessments required by the rule, so that facilities may be fo rced into a situation that upon st artup they are out of compliance.

Commenter 17774 states the EPA should lengthen the av eraging period to provide needed flexibility to accommodate the range of operating events, includ ing SSM events. Commenter 17761 notes that longer averaging periods for all emissions limits (such as an annual or semi-annual average) to fully account for the emission variability during th ese startup and shutdown periods ar e consistent with the holding in Sierra Club as emissions limits would continue to apply to facilities at all times.

Response to Comment 46: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits. See the preamble for di scussion. The EPA’s rationale for its approach to malfunctions is disc ussed in the preambles to the proposed rule and this final action. As explained in those preambles, the EPA has determ ined that CAA section 112 does not require that423 emissions that occur during periods of malfunction be factored into development of CAA section 112 standards and thus we are not revising the averag ing time in the final rule to account for malfunction emissions. We believe that the 30 day averaging period provides the appropriate level of flexibility for the regulated industry and that long er averaging periods would inapprop riately weaken the standards and limit our ability to evaluate source compliance on an ongoing basis (see RTI memorandum). In addition, the commenters’ expressed concern about including st artup and shutdown period in the averaging is no longer relevant in light of the inclusion of work pr actice standards for such pe riods in the final rule.

b. Kushner letter.

Comment 47: Commenter 17761 states that there is preceden t in the Kushner Letter that the agency would provide compliance flexibility to sources thatimplemented 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 Lette r from Director Adam Kushner, July 22, 2009).

Commenter 17904 cites the Kushner Letter and requests th at the EPA be consistent with the guidance in the letter, by averaging over a long period of time, e.g., yearly.

Response to Comment 47: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. For malfunctions, the EPA is finalizing the proposed affirmative defense language for exceedances of the numerical emission limits that are caused by malfunctions. See the preamble for discussion.

The Kushner letter did not state th at EPA would necessarily provide longer averaging periods in promulgating new standards. In asse ssing the immediate impact of the Sierra Club v. EPA decision, the Kushner Letter merely noted that many sources may not have difficulty complying with existing standards during periods of SSM even if they lost the SSM exemption because of averaging periods built into those rules.

4. Diluent capping and electrical production.

Comment 48: Commenter 17648 agrees with the options for calculating input-based emissions based upon a default diluent value or fuel specific CO 2 concentration, or calculating output-based emissions using an electrical production ra te of 5 percent of ra ted capacity during star tup/shutdown periods.

Commenter 17767 supports use of minimum default values for the diluent and power generation numbers for startup/shutdown for parameters monitored by CEMS and by Low Emitting EGU methodology.

Commenter 17923 recommends the rule allow for alternative unit specif ic lb/MWh emission calculations, given that the 5 percent of rate cap acity value could potentia lly cause overestimates resulting in artificial compliance issues.

Commenter 17821 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 regulate d community as no two companies would choose the same value and lead to discrepancies. Commenter 17715 states that diluent capping during startup/shutdown pe riods is appropriate. Commen ter 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 va lues 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 rules 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 e quivalent values for reporting lb /MWe are too low and should be changed to 10 percent.

Commenter 17904 states that startup/shutdown emi ssions cannot be confirmed by standard methods. Commenter 17904 states that the EPA recognizes meas uring 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 dilu ent values in a 30-day compliance period would appear to disregard both measurement inaccuracies and variab ility of pollutant concentrations.

Several commenters (19536, 19537, 19538) state that no compliance monitoring is required during SSM. The commenters state that th e monitoring provisions do not requ ire any testing during periods of startup, shutdown, and malfunction and thus provide no means to determine if the standards are met during these periods. The commenters state that the default diluen t 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 as sure continuous compliance during these periods. Commenters state that because no testing is require d during SSM periods, even assumi ng 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 actual ly exceeds 5 percent of the rated capacity, so that the default use do es not result in an underestimate of power generated and overestimate of output-based emissions: For calculating emissions in units of lb/MWh or lb/GWh only during startup or shutdown periods, use a nominal electrical production rate of equal to 5 percent of rated capacity until the measured electrical production rate exceeds 5 percent of rated capacity.

Several commenters (17740, 17758, 17776) state that the EPA does not a ddress these concerns (that there are equipment integrity concer ns, technological limitati ons, economical issues, and safety issues]) but accounts for variable conditions by using a default value and spec ifying electrical production rate; by proposing these default values and production rates, the EPA acknowledge s that it is not feasible to test and monitor emissions from EGUs during startup/shutdown. Co mmenter 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 diffe rent during startup/shutdown. Multiple commenters (17758, 17776, 17912, 19536, 19537, 19538) state that the EPA doe s not explain how the default values were selected or why they are ap propriate and accurate proxies for emissions during SS(M). Commenter 17925 does not understand how the EPA determined these parameters.

Response to Comments 48 - 49: For periods of startup and shut down, the EPA is finalizing work practice standards instead of numeric emission li mits. See the preamble for discussion. The EPA’s rationale for its approach to malfunctions is discus sed in the preambles to th e proposed rule and this final action. We agree with the comme nters that the rule does not re quire formal performance testing during SSM periods. However, as note d above, we believe that it is important to collect data during all periods including SSM periods, as the rule re quires 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 timesth e process unit is operati ng and at the intervals specified in the rule, except for periods of monitoring system malf unctions, repairs associated with425 monitoring system malfunctions, required monito ring system quality assurance or quality control activities and any scheduled maintenance as defined in the unit’s site-specifi c 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 a ny available information to demonstrate that the source complied with the standard notwithstanding the malfunction.

5. Reliability issues.

Comment 50: Commenters 16849 and 18023 state that includi ng SSM periods in the rule will cause reliability issues. Commenter 18023 stat es the ability to startup and shut down units in a flexible manner and bypass controls for short periods are critical to operating a reli able electric system. Commenter 18023 states the rule does not provide regulatory relief during modes of operation such as SSM that are likely to result in higher emission rates, this will prohibit APCD bypass, and units will have to shut down if not able to meet MACT rule standard atall times. Commenter 18023 i ndicates that this will cause reliability challenges and will force add itional shutdowns and restarts. Commenter 18023 notes there are additional reliability cha llenges for facilities that have multip le units served by a single APCD. Maintenance outages are scheduled for planned outages at one or more units; however Commenter 18023 states that transmission requir ements may demand a certain amount of generation from that plant that could oblige the remaining units to operate while the control is offline. Commenter 18023 states the prohibition of emissions bypass under even these special circumstan ces could result in transmission consequences for areas served.

Commenter 17902 states the need for EGUs to provide uninterrupted reliable power is contrary to maintaining operations w ith frequent malfunction.

Response to Comment 50: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. These wo rk practice standards take into account operation of APCDs. See the preamble for discussion. Given th e inclusion of the work practice for startup and shutdown periods, we believe those co mments are now resolved as they relate to startup and shutdown periods.

Concerning malfunction, we question the scope of this problem notwithstanding commenters assertions. Commenters have not provided information on the scope of this alleged problem or the likelihood that sources would have the large number of malfunction ev ents that commenters describe. As stated in response to other reliability related comments, we believe we have identified mechanisms to address reliability issues associated with implementation of this final rule.

We address APCD maintenance, bypass stacks, our approach to malfunctions, and reliability issues elsewhere in the final rule record.

6. Malfunctions.

a. Support or oppose malfunction approach.

Comment 51: Several commenters (17772, 17807, 17902, 18428) support the malfunction exclusion. Commenter 17648 states that the EPA decision not to include malfunctions is re asonable, aligns with purpose of section 112, and malfunctions do not refl ect normal variability in operating conditions. Commenter 17648 states the EPA already accounted for variability for typical operating conditions and426 it should not make further accommodations for malf unctions. Commenter 17772 also states they would support some alternative standard that is based on r eal data that recognized em issions are higher during malfunctions.

Commenter 17774 notes that the EPA’s decision not to differentiate malf unction periods is not based on any data. Commenter 17774 notes the EPA’s reference to the precedent that standards that factor in the variability of emissions under all operating cond itions are reasonable. Commenter 17774 went on to state that in this case, it woul d be both reasonable and appropriate for the EPA to based the MACT standard on data that includes ma lfunctions. Commenter 17774 states th at if the EPA chooses not to include such malfunction data, it cannot expect sour ces to comply with general emission limits during malfunction periods.

Commenter 17730 states that if ma lfunctions are included in the co mpliance calculation, the emission standards should be raised to account for the variability or the averag ing times should be lengthened to account for including malfunction emissions.

Commenter 17767 disagrees with the EP A’s statement that malfunction ev ents are unlikely to lead to noncompliance.Commenter 17730 states malfunction even ts will cause sources to violate the standard. Commenter 17775 states that because the EPA does not factor malfunctions (even malfunctions of “best performing” sources) into its proposed standards, it is unlikely the standards will be achievable if a significant malfunction occurs. Commenter 17775 agrees with the EPA that equipment can and will fail unexpectedly, and that some allowance must be made for periods of malfunction. Commenters 17821 and 17877 state that even the best performing uni ts or technology will occasionally fail (and malfunction). Commenter 17851 states that even the bestoperated and maintained facilities will have malfunctions. Commenter 17623 states that malfuncti ons leave the source with uncertainty about whether they will be penalized and vulnerable to citizen suits. Commen ters (17623, 17821) appreciate that the EPA states that not all malfunctions wi ll result in violation; Commenter 17821 states that sources are subject to the discretion of the EPA, st ate, 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 inf easible, while at the same time require compliance with the strict standard during malfunction periods. Commenters note that just because the EPA is not required to account for every conceivable malfuncti on does not mean it can set standards excluding data of any malfunction event.

Commenter 17775 states the applicati on of numerical limits to such malfunctions without a defense to penalties clearly would violate th e Due Process Clause and the Eighth Amendment prohibition on Cruel and Unusual Punishment. Although Commenter 17775 appreciates the EPA’s willingness to exercise enforcement discretion and to provide a defense to civil penalties, the EPA’s refusal to take malfunctions into account when setting standards is not reasonable.

Several commenters (17808, 17870, 18025) recommend the EP A or states maintain current enforcement discretion to address s ituations when a source fails to comply witha 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 malfuncti on events and it opposes EPA’s affirmative defense proposal. The commenter has established a state-appr oved plan that it follows during malfunctions and breakdowns. The commenter believes this approach is preferable to EP A’s proposal, in which there is a427 presumption of non-compliance. The plan incorp orated in commenter’s Title V operating permit application ensures that future malfunction events will be minimized and that best practices will be followed, whereas EPA’s proposed approach is focused on after-the-fact penalty.

Response to Comment 51 : The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this final action. As explained in more detail in the preamble, EPA’s approach to malfunctions is consis tent with CAA section 112 and is a reasonable interpretation of the statute. While the EPA recognizes that malfuncti on 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 determin ing whether and to what extent and enforcement response is appropriate. The commenter ’s suggestion that its state-approv ed plan is prefereable to the EPA’s approach does not explain how an approach based on such a plan meets the requirements of section 112.

b. Work practice specific to ma lfunctions/Sierra Club Decision.

Comment 52: Commenters 17775 and 18023 suggest the EPA work with utilities to develop reasonable work practice standards under sec tion 112(h) that take malfunctions into consideration. Commenter 17623 states the best approach is to require a work practice standard that ensures malfunction problems are addressed as soon as safely practicable.

Commenter 17775 states section 112 doe s not limit the EPA’s standard setting obligation to “distinct operating modes.” The commenter notes th at as the D.C. Circuit ruled in Sierra Club v. EPA , CAA § 112 requires that some “section 112-compliant standard ” apply at all times (not just during distinct operating modes). 551 F.3d 1019, 1027 (D.C. Cir. 2008). Th e commenter states that if the EPA has determined that it is not technologi cally or economically “feasible” to gather emissions data necessary to establish numerical emissions standards that “t ake 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 ma lfunctions into account, and the “infeasibility” of prescribing and enforcing standard s for such events, the commenter states that the EPA’s position is difficult to square with the CAA.

Commenter 17775 states that specifyi ng work practice standards for malf unctions is more consistent with the CAA, and the D.C. Circuit’s interpreta tion 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 ha d “not purported to act under section 112(h),” the commenter states that it al so made clear that the CAA does not require that the same standard apply to all periods. Id. at 1021 (recognizing that “continuous” under CAA § 302(k) does not mean “unchanging”), 1028. In short, the commenter states thatnothing prohibits the EPA from establishing section 112(h) standard s for periods that include a malf unction, even if section 112(d) standards apply at other times. In fact, the commente r states that establishing section 112(h) standards for malfunctions would be more consistent withthe Sierra Club ruling than applying clearly unachievable standards and allowing a defense to pena lties, since an unachiev able section 112 standard is not “section 112-compliant.” The commenter notes that it also w ould be more consistent with Congressional intent. By allowi ng work practice and other requi rements under section 112(h), the commenter states that Congress clea rly intended that sources be provide d the opportunity to be fully in compliance with some standard at all times. The comme nter states that nothing in section 112 suggests that Congress intended to require a source owner or operator to certify “violation” of a section 112 standard as a result of an event the source could not reasonably control. The commenter states that the428 EPA should adhere to that intentand specify reasonable work pract ice or operational requirements for periods of malfunctions.

Response to Comment 52 : The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this final ac tion. The EPA’s rationale does not turn on whether malfunctions should be viewed as a distinct operating mode. Furthe r, the EPA’s rationale for its approach to malfunctions is not base d on the criteria that must be met to justify a finding that it is not feasible to prescribe or enforce an emission standa rd under section under sect ion 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 de signed and constructed to emit or capture such pollutant, or that any requirement for, or use of, such a conveyance would be inconsistent with any Federal, State or local law” or “the application of measurement methodology to a particular class of sources is not practicable due to technological and economic limitations .” The EPA justification for its approach to malfunctions is unrelated to the findings required under section 112(h)(2). Thus, commenters’ claim that the EPA’s atte mpt 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 o ccur during periods of malfunction be factored into development of CAA s ection 112 standards. The EPA has further explained its view that accounting for malfunctions would be difficult, if not impossible given the myriad different types of malfunctions that can occur across all sources in the category. This rationale is not based on the factors set forth in section 112(h)(2).

c. Reporting.

Comment 53: Commenter 17775 states that the EPA’s reporti ng requirements also raise some practical issues. Although some malfunctions w ill 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 st ates that it is possible that elevated emissions from some malfunctions will be sufficiently compen sated for during normal operation such that they do not result in exceedance of a 30-day rolling average. The commenter indicates that determining before the end of a 30-day period whether a malfunction w ill result in an exceedance of a 30-day rolling average may not always be easy. Commenter 17775 stat es that requiring EGUs to keep logs of malfunctions is not unreasonable, ho wever, 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 propo sal to recognize that some malfunctions that ultimately result in exceedance of an emission limit (particularly those with longer averaging times) may occur long be fore the exceedance is recorded. The commenter notes that the EPA should simply require the maintena nce of the appropriate records surrounding any event identified by the EGU as a malfunction and leave the reporting until af ter all of the data relevant to the compliance determination for the affected period are collected.

Commenter 17772 indicates that 40 CFR part 60 subpart Da rule and ot hers exclude malfunction periods from 30-day averaging.

Response to Comment 53 : The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the proposed rule and this final acti on. 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 63.1000 1. The EPA agrees that the notice requirement associated with the affirmative defense may not be practical when a 30- day averaging period applies. The EPA is revising the notification requirement so that it reads “ The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a ma lfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not possible to determine w ithin 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 malfuncti on 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 civ il penalties for that malfunction.”

d. Malfunction definitions.

Comment 54: Commenter 17775 notes that section 63.10005(a) makes a number of references to “excess emissions” however, there is no general definition of “excess emissions” in section 63.2. Commenter 17775 states that accordi ng to section 63.10(c)(7) and (8), “e xcess emissions” are supposed to be defined in the applicable subpart, but pr oposed subpart UUUUU contai ns no such definition. Commenter 17775 suggests the EPA issue a proposal to define “excess emissions” in the context of any final rule that uses the term.

Commenter 17736 notes that the defin ition of “malfunction” is suffici ent for the Utility MACT rule.

Response to Comment 54: We disagree with the commenter. In defi ning 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 standard s that must be met on a 30-day rolling av erage. Emissions in excess of those levels over the established averaging period are considered excess emissions.

7. Affirmative defense.

a. Support or oppose AD approach.

Comment 55: Multiple commenters (17623, 17715, 17740, 17807, 17904, 17909, 17912, 18025, 18428, 19114) support affirmative defense (AD) for malf unctions; commenter 17722 generally supports the AD for excess emissions. Multiple commenters (17689, 17724, 17712, 17876, 17877, 17885, 19032) support affirmative defense concept but believe the EPA shoul d articulate specific reason able provisions in the rule.

Commenter 17975 states that requiri ng agencies to evaluate and re but 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 in dividual situation retroactivity on a ca se-by-case basis based on vague changing guidelines. Commenter 17909 states the EPA should provide detailed guidance on how the provisions will be applied and rely on case-by-case revi ew. Commenter 17912 notes that the EPA properly proposes flexibility for malfunctions. Commenter 17912 supports the EPA finding th at it is reasonable not to account for malfuncti ons in emission standards.

Commenter 17902 states that short of excluding ma lfunctions, they support AD, however, the EPA should make it less burdensome. Commenter 17902 r ecommends the EPA remove items 7 through 9, because the information is redundant with item s 1 through 6, are unnecessary, are not reasonably430 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 malfuncti ons, such as an AD. Commenter 17851 notes concerns that the AD implie s the facility is guiltyuntil proven innocent. Commenter 17851 states concerns that in calling it an AD even before it has been established to be a deviation, improperly shifts the burden to the fa cility. Commenter 17851 suggests the EPA establish a rebuttable presumption, rather than AD, where it is pr esumed the facility did everything in their power to minimize emissions, unless the EPA proves certain facts that are enumerated in rules. Commenter 17851 states the burden of pr oof would be on the EPA.

Commenter 18500 states that the step s associated with AD are highly prescriptive and infer that the failure to meet any step is a willful violation. Co mmenter 18500 states the standard should be moderated to match the risk to the violation, and to recogn ize 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 sta ndard that was unreasonably established. Commenter 17402 recommends a SSM work practice plan in the Title V permit to minimize future malfunctions and ensure best practices are followed, similar to the malfuncti on and breakdown plan they developed for their title V application. Commenter 17902 states that EGUs ar e already required to minimize emissions during SSM under title V operating permit conditions. Commen ter 18447 states that the [AD] response to a malfunction is heavy-handed and threatening. Comme nter 18447 states that facilities are guilty until they go to great lengths to prove innocence. Co mmenter 18447 states that the EPA would do well to realize that even well-trained and well-int entioned employees can and do make mistakes.

Commenters 17402 and 17772 oppose the EPA’s AD pr oposal for malfunctions. Commenter 17772 states that AD for malfunctions is inappropriate , overly complex, and unduly burdens both industry and the EPA. Commenter 17772 states that the EPA has improperly shifted the burden of proof to the facility, but the ultimate burden of proof to justify a civil penalty remains with the EPA, and the EPA should have to present clear evidence sufficient to persuade a judge or independent fact finder that the claimed malfunction should be disregarded for reasons such as poor maintenan ce, careless operation, or other preventable conditions. Co mmenter 17772 states the multi-part process for establishing the existence of a malfunction is overly complex and burdensome. Commenter 17772 suggests that any AD to be used should be limited to the definition insection 60.41Da. Commenter 17772 notes that the rule establishes 12 separate requirements and requires th e EGU operator to carry a burden of proof for each one to comply; this is arbitrary and capricious . Commenter 17772 states that the 12 requirements are vaguely worded and will themselves become a prim ary focus of litigation; after a malfunction occurs, it is almost always possible for someone to allege th ere was some practice that could have been employed to prevent the malfunction.

Commenter 17772 also states their co ncerns that root cause analysis in section 63.10001(a)(9) will be used against the EGU operator, since a potential ar gument may be made that earlier implementation of the recommended correction would have preven ted the malfunction. Commenter 17772 states that proposed rule section 63.10001(a)(5), for example, stat es that the accused must prove that “all possible steps were taken” to minimize the impact of the excess emissions. The commenter asks whether that means that if the EPA or some private litigate can imaginatively identify some step not tried, then the affirmative defense is rejected? The commenter goes on to note that if so, no affirmative defense would ever be successful -- some untried alternative or additional action could always be found by inventive counsel or expert witness. Similarly, commenter 17772 notes that proposed rule section431 63.10001(a)(i)(2) states that the excess emissions “Could not have been pr evented through ... better operation and maintenance practices.” The commenter i ndicates this could be an impossible standard to meet if “better” is used to mean better than th e practices actually employe d by the accused. Commenter 17772 states that this vague and unwor kable standard should, at a mini mum, be modified to allow the accused to meet whatever burden of presentment or proof is applied by a show ing that the operation and maintenance practices were consis tent with good u tility practice.

Commenter 17851 states the requirements in secti on 63.10001 are impossible to meet due to ambiguous terms such as “careful,” “proper,” or “better”, and these terms must be define d 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 restrictiv e and vague. Commenter 17912 urges the EPA to set conditions for AD that a facility can actually achieve ra ther than setting a virtua lly insurmountable bar.

Commenter 17736 objects to the EPA’s attempt to restri ct the definition of “mal function” such that the concept is eliminated albeit the EPA’s proposed “affirmative defense.” Commenter 17736 notes that determining whether no malfunction o ccurred if it “could have been prevented through careful planning, proper design, or better operati on and maintenance,” the EPA should explain what “proper design” and “better operation” is.

Commenter 17775 cites concerns re garding AD. Commenter 17775 states that section 63.10005(a)(1)(i) refers to an “unavoidable” failu re, and although the difference betw een “reasonably preventable” and “unavoidable” may seem small, the EPA’s rule seems to require a stronger showing than the definition anticipates in that it leaves room to argue whether a failure could have been prevented even if the acts necessary to do so were “unreason able.” Commenter 17775 indicates that other provisions in (a)(1), paragraph (ii) (“[c]ould not have be en prevented”), (iii) (“could [not] have been foreseen and avoided, or planned for”), and (a)(5) (“all possible steps”) - also seem to remove the requirement of “reasonableness.” In contrast, the commenter notes that other provisions include references to practicability. At a minimum, Commen ter 17775 states the EPA must revise its criteria consistent with the section 63.2 definition to include the concept of “reasonableness.”

Several commenters (17383, 17712, 17876) state AD for malfunctions should be reasonable and the requirements well articulated. With respect to AD for malfunctions, Commenter 18023 requests that the EPA reconsider the criteria defi ning malfunctions to include the c oncept of “reasonableness” and to defer reporting until an exceedance has been recorded.

Commenter 17722 states that for language in secti on 63.10001(a)(5) “All possibl e steps were taken...” it should be clarified that those steps must be relevant to the excess em issions. The commenter also stated the term “possible” is subjective and could be repl aced by “all steps needed, based on best professional judgment.”

Commenter 17722 states that for language in section 63.10001(a)(9), it should be clarified that written root cause analysis should include all forms of documentation, includ ing 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 commenters (19536, 19537, 19538) state that the EPA’S AD for malfunctions is unlawful. Commenters state that the CAA makes clear how the c ourts are to assess civil pe nalties, whether a case is brought by the EPA or a citizen. 42 U.S.C. § 7413(e). The commenters not e that Congress intended citizens to be able to enforce emission sta ndards under the CAA using the full range of civil enforcement mechanisms available to the government , and, in the HAP context, subject only to the limitation that government not be “diligently prosecuting” its own civil enforcement action, CAA § 304(b)(1)(B), 42 U.S.C. § 7604(b)(1)(B) . The commenters state that the EPA’s rule proposal, by shifting this careful balance and contravening these mandates, violates the CAA.

Commenters state that the AD that the EPA proposes to allow in case of ma lfunctions goes directly against congressional inte nt in two ways. First, the commenters note that Congress expressed a clear intent as to how judges should determine the size of civil penalties whenever they are sought and thus Congress flatly barred the EPA from limiti ng when civil penalties can be assessed. See Chevron, U.S.A., Inc. v. Natural Res. Def. Council, Inc. , 467 U.S. 837, 842-43 (1984). In this proposal, the commenters note that the EPA acts outside of its delegated authority to limit civil penalties available in citizen suits or its own enforcement actions. Second, the commenters state that the proposal w ill impermissibly chill citizen participation, and the ability to win an effective, deterrent remedy, in CAA enforcement actions.

Commenters state that the AD is fatally flawed becau se the EPA cannot decide when civil penalties will not be allowed. The commenters state that the C AA itself spells out the only limits that Congress intended to impose on citizens’ abi lity to seek and recove r penalties in enfor cement suits under CAA § 304, 42 U.S.C. § 7604. See 42 U.S.C. § 7413(e). By attempting to impose additional agency-created limits, the commenters state that the EPA exceeds its authority. The commenters note that Congressional intent on civil penalties is clear- they are a remedy available to ci tizen plaintiffs, and the CAA gives judges a list of factors to consid er in assessing them. As such, th e commenters state the EPA cannot interpret the statute to contravene that intent, and by attempting to re write this provis ion, via regulation, the EPA has done just that.

Commenters state that the CAA grants the EPA mini mal discretion that only applies to administrative penalties, allowing the EPA to “compromise, modi fy, or remit, with or without conditions, any administrative penalty which may be imposed un der [subsection 113(d)].” 42 U.S.C. § 7413(d)(2)(B). However, the commenters state there is no similar gr ant of authority to the EP A to compromise, modify or limit civil penalties that a court may impose under section 113(e) or section 304. The commenters state that section 304(a), 42 U.S.C. § 7604(a), grants c ourts the sole authority “t o apply appropriate civil penalties” in citizen suits. The commenters note that the explicit reference to th e EPA’s ability to modify penalties in one subsection and its absence in the other subsection of the same provision can only be understood as an intentional decision by Congre ss that the EPA cannot contravene by rule.

Commenters state that citizen partic ipation in CAA enforcement also w ill be hampered, in violation of citizens’ rights to protect themselves from pollution and in direct conflict w ith congressional intent. The commenters state that the affirmative defense woul d 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 themselv es 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 prev ent with the simple straightforward enforcement and penalty provisions inthe CAA. As a result, the commenters note that433 enforcement of the CAA could suffer, for civil pena lties provide a powerful deterrent to violators as Congress intended.

Commenters state that the AD also runs counter to two clearly expresse d intentions of Congress: (1) the burden it places on citizens makes it less likely that they will enforce the CAA, see , e.g., Pennsylvania v. Del. Valley Citizens’ Council for Clean Air , 478 U.S. 546, 560 (1986); and (2) several of the factors at issue in the AD undercut Congress’s intent that citizen suit enfor cement should avoid re-delving into “technological or other considerations,” NRDC v. Train , 510 F.2d 692, 700 (D.C. Cir. 1974). The commenters state that both result from the techni cal burden the EPA imposes on citizens with the AD, and both render the defense impermissible.

In addition to these problems, comm enters state there is simply no n eed 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 act s consistent with the CAA to prot ect clean air as its top priority, see 42 U.S.C. § 7401. The commenters state that promul gating this affirmative defense is equivalent to giving polluters “get out of jail free” cards for seri ous emission exceedances and MACT violations. The commenters note that polluters are likely to claim that any violati on 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 re al teeth of the standards - through th is type of measure is likely to lead to polluters simply ignoring or factoring poten tial standard violations into their cost of doing business, rather than actually trying to prevent malfunctions and violatio ns of the standards as a way to avoid financial losses from th e application of penalties.

Commenters state that assuming arguendo that the EPA had authority to promulgate any type of affirmative defense to penalties for malfunctions , the EPA should also promulgate the following provisions:

1. A specific amount of compensatory damages shoul d 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 assuran ce that malfunctions will not happen again.

2. The EPA should modify the regula tions so that the AD cannot be us ed by a specific facility or company more than once within a set period of time, such as 10 years. The AD should become automatically unavailable to a facility that has prev iously had a malfunction within the last 10 years, to ensure that this defense does not sw allow the value of the standards.

3. The EPA should promulgate specific public reporting and notification requi rements for malfunctions, or any emission exceedance that occurs of which an operator is aware. Spec ifically, the EPA should require that when a facility provides the EPA witha notification of a malfunc tion or emission standard exceedance under the regulations, this notice will be made publicly available on the EPA’s website within 14 days. In addition, the EPA should promulgate the requirement that wh en such notification is made, the facility must also provide for community notification of the malfunc tion or emission standard exceedance within 2 business days, through an appropr iate public forum that is designed to reach residents who live near the facility, including but not limited to a notice on the f acility’s own website (if it has one), a written notice to the lo cal municipality and local school dist rict, 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 55: For malfunctions, the EPA is finaliz ing 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 recognizes that even equipment that is properly desi gned and maintained can fail and that such failure can cause an exceedance of the relevant emission st andard. 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 types of air regulation, to ensure adequate compliance while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under circumstances beyond the control of the source. The EPA must establish emission standards that “limit the quantity, rate, or concentration of emissions of air pollutants on a continuous basis.” 42 U.S.C. § 7602(k)(defining “emission limitation and emission standard”). See generallySierra Club v. EPA , 551 F.3d 1019, 1021 (D.C. Cir. 2008) (emissi ons limitations under CAA sec tion 112 must both continuously apply and meet section 112’s minimum stringency requirements, even duri ng periods of startup, shutdown and malfunction). Thus, the EPA is required to ensure that sectio n 112 emissions limitations are continuous. The affirmative defense for malfuncti on events meets this requirement by ensuring that even where there is a malfunction, the emission limita tion is still enforceable through injunctive relief. While “continuous” limitations, on the one hand, are requi red, there is also caselaw indicating that in some situations it is appropriate for the EPA to account for the practical r ealities 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 set ting standards under CAA section 111 “var iant provisions” such as provisions allowing for upsets during startup, shutdown and equi pment malfunction “appear necessary to preserve the reasonableness of the standards as a whole and that the record does not support the ‘never to be exceeded’ standard currently in force.” See also, Portland Cement Association v. Ruckelshaus , 486 F.2d 375 (D.C.Cir. 1973). Though intervening caselaw such as Sierra Club v. EPA and the CAA 1977 amendments calls into question the relevance of these cases today, they suppor t the EPA’s view that a system that incorporates some level of flexibility is reasonable. The affirmative defense simply provides for a defense to civil penalties for excess emissions that are proven to be beyond the control of the source. By incorporating an affirmative defense, the EPA has formalized its approach to upset events. In a Clean Water Act setting, the Ninth Circuit required this type of fo rmalized approach when regulating “upsets beyond the contro l 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 affirmativ e defense provisions give the EPA the flexibility to both ensure that its emission limitations are “con tinuous” as required by 42 U.S.C. § 7602(k), and account for unplanned upsets and thus support the reasonableness of the standard as a whole.

Further, the EPA’s view is that th e affirmative defense is consistent with CAA sections 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 c ourt shall take into consideration in determining the amount of a penalty to be assessed only after it has been determined that a penalty is appropriate. The affirmative defense regulatory provi sion is not relevant to the amount of any penalty to be assessed under section 113(e) because if a court determines th at the affirmative defense elements have been established, then a penalty is not appropriate and penalty assessmen t pursuant to the section 113(e)(1) factors does not occur.

In exercising its authority under se ction 112 to establish emission stan dards (at a level that meets the stringency requirements of section 112), the EP A necessarily defines conduct that constitutes a violation. The EPA’s view is that the affirmative de fense is part of the emission standard and defines two categories of violation. If ther e is a violation of the emission st andard and the source demonstrates that all the elements of the affirmative defense ar e met, only injunctive relief is available. All other435 violations of the emission standa rd are subject to injunctive relie f and penalties. The CAA does not require that all violations be treated equally. Further, a citize n 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 contemplates enforcement of the standards that are defined by th e EPA. As a result, where the EPA defines its emissions limitations and enforcement measures to allow a source the opportuni ty to prove its entitlement to a lesser degree of violation (not subject to penalties) 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 ci vil penalties for exceedances of applicable emission standards during periods of malfunction appropriately balances competing concerns. On the one hand, citizen enforcers are concerned about additional compli cations in their enforcement actions. On the other hand, industrial sources are concerne d about being penalized for violat ions caused by malfunctions that could not have prevented and were otherwise appropriately handled (as reflected in the affirmative defense criteria). The EPA has utilized its Section 301(a)(1) authority to issue regulations necessary to carry out the Act in a manner that appropriately balances these competing concerns.

The EPA disagrees that the affirmative defense pr ovision will hamper citizen enforcement. First, injunctive relief is still available and the threat of pe nalties would not deter viol ations 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 a ffirmative 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, b ecause the 113(e) penalty assessmen t criteria and the affirmative defense criteria are similar and in fact overlap. For example, the requi rement that the Administrator or the court consider “good faith efforts to comply” is bound to generate the type of fact-intensive disputes that the commenter complains of. In addition, several of the affirmativ e defense criteria are exactly the type of criteria the Administrato r or Court might consider in dete rmining whether a source made “good faith efforts to comply.” For example, to take ad vantage of the affirmative defense, the source must prove by a preponderance of the evidence that, among other things, the excess emissions “were caused by an unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner” and “could not have been prevented through careful planning, proper design or better operation and maintenance practices ” and “did not stem from any activity or event that could have been foreseen and avoided, or planned for.”

Thus, the EPA does not expect the affirmative defe nse provision to significantly alter the burden of bringing a citizen enforcement action. Fo r those cases that do proceed to tr ial, even in the absence of this affirmative defense, sources generally raise equitabl e arguments to argue for a low penalty and citizens often rebut such arguments. Therefore, as a practi cal 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 c onsiderations in determining whethe r penalties are appropriate when a violation occurs as the result of a malfunction. As noted above, the affi rmative 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 viol ation is caused by a malfunction, the size of the business is not relevantto whether penalties should be excused. If the violation was436 unavoidable and could not have been prevented, the EP A’s view is that it would be unfair to impose a penalty no matter the si ze 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. It is not clear that EPA has authority to require the automatic imposition of compensatory damages and ev en if such authority exists, the EPA does not think automatic imposition of damages is appropriate . Ensuring that malfunctions do not recur can be handled through imposition of appropriate injunctive reli ef. In addition, the EPA’s view is that it would not be appropriate to limit a source’s ability to take advantage of th e affirmative defense to one time over a specified period of time such as ten years give n that the affirmative defense is only available when the source could not have prev ented the excess emissions. With respect to commenters’ suggested reporting requirements, the reporting requirements in the rules promulgate d today already require malfunction reporting and the affirmative defense provisi ons require that parties choosing to assert the affirmative defense meet additional malfunction repor ting requirements. Any such reports submitted to the EPA are publicly available pursuant to CAA section 114.

Further, the EPA disagrees with comments that critici ze the affirmative defense criteria as being overly vague or unduly restrictive and complex. The EPA be lieves that courts are well equipped and often do evaluate and apply the type of crite ria set forth is the affirmative de fense. Many of the conditions were modeled after the conditions of the affirmative defe nse 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 Shut down (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malf unctions (Feb. 15, 1983)). We do not have any indication that parties to enforcement proceedings have had any significan t difficulties applying the terms of these SIP affirmative defenses. In addition, th e 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 poli cies. The EPA does not find persuasive commenters’ concerns with potential use of the root cause analys is against the source. The purpose of the root cause analysis is to determine, correct, and eliminate the primary causes of th e malfunction 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 n ecessarily mean that malfunction could have been predicted or prevented.

The EPA also disagrees with comments that critici ze the affirmative defense for shifting the burden of proof. The affirmative defense does not require a facili ty to prove its innocence ra ther than requiring an enforcement authority to prove a vi olation of the CAA or change the burden of proof with respect to establishing a violation. The affirma tive defense applies to penalties and thus is only utilized where a violation has been established. The burden of proof remains with the plaintiff in an enforcement action. See , e.g ., 40 C.F.R. 22.24. If a violation has been esta blished and a source wishes to assert the affirmative defense with respect to penalties, the source does bear th e burden of establishing that the elements of the affirmative defense have been me t. This burden-shifting is appropriate because the source is in a better position to determine th e 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 industr y challenge to the EPA’s use of an affirmative defense to addr ess excess emissions during malfunction events).

With respect to the comment that the affirmative defe nse should be stated instead in terms that, once a source has claimed that its excess emi ssions were related to a malfunction, it will not be considered to be in violation of the standards unless the enforcement authority demons trates 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 improperly seeks to shift the burden of proof from the source to the EPA. It is the source, not the EPA, that has th e information relevant to assess whether a particular event qualifies as a malfunction and meets the affirmative defense.

b. AD for startup/shutdown.

Comment 56: Commenters 17904 and 19120 request AD for ex cess emissions during startup/shutdown periods, similar to the AD provided for malfunc tions. Commenter 17904 cites the NSPS (approved FIP for a station) where opacity standards apply at all times except during SSM (40 CFR 60.11), and AD applies to SSM. Commenter 17904 notes that unlike anexclusion, an AD does not excuse a source from continuous compliance. Commenter 17904 states that nothing in the Si erra Club decision precludes the EPA from including an AD for excess emissions during startup/shutdown.

Response to Comment 56: . The EPA is promulgating the affirmative defense for malfunctions only, not for periods of startup and shutdown. As e xplained in the preamble, the EPA believes that malfunction events should be treated differently than periods of startup and shutdown, which are predictable and routine as pects of a source’s operations. In contra st, the EPA has determined that CAA section 112 does not require that emi ssions that occur during malfunctions be factor ed 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, a nd enforcement of, applicable emissions standards during those periods should apply as otherwise applies during a sour ce’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 affi rmative defense provision to startup and shutdown periods.

c. Reporting timeline.

Comment 57: Commenter 17912 states section 63.10001 requires notification as soon as possible but no later than 2 business days, but th e rule text does not allow for ci rcumstances where the facility does not have knowledge of the malfunction until later. Commenter 179212 states that a source must provide a preponderance of the evidence that it has met al l 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-da y statute of limitations on AD is an arbitrarily s hort deadline and should be struck in its entirety. Commenter 17772 states that the accused should re tain its right to defend itself against a notice of violation (NOV) and relevant evidence of a malfuncti on should not be ignored due to a procedural rule. Commen ter 17772 cites an example where emissions are measured by a sorbent trap and the malfunction may not be found until the trap is removed and analyzed.

Commenter 17772 states that for short-term malfunc tions, it may not be known until the end of the 30- day period that there has been a viol ation, and a better approach would be to permit the claim to be made as soon as there is knowledge of the malfunction but no later than 45-days following the event.

Response to Comment 57 : The EPA is revising the notification requirement so that it reads “ The owner or operator of the affected s ource experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Admini strator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the ma lfunction 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 busines s days after the owner or operato r knew or should have known that438 the malfunction caused or contributed to an exceedan ce, but, in no event later than two business days after the end of the averaging peri od, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunction.”

d. Reporting method.

Comment 58: Commenter 17722 states that language in section 63.10001(b) should include “or delegated authority, as applicable” in addition to “notify the EPA Administrator...” and should replace “by phone or facsimile...” with “in an appropriate manner such as phone, fax, email, or other electronic means, as determined by the EPA Admi nistrator or delegated authority.”

Commenter 18034 states that electron ic reporting, such as complies with CROMERR standards, should be allowed for the initial notifica tions, rather than telephone notifications, which should not be allowed, because telephone notifications are difficult to ve rify and enforce. Commenter 18034 states that electronic notification provides quic k and durable reporting that may be relied on for investigative and enforcement purposes.

Commenter 18034 suggests that the EP A allow state rules for AD that are EPA-approved as part of a SIP, to be used in lieu of the federal procedures , to eliminate duplicative or conflicting requirements for both state agencies and regulated entities. Comm enter 18034 states that TAC includes reporting of upsets (malfunctions), startups, and shutdowns, that are substantiallythe same as the EPA’s rule. Commenter 18034 requests that as part of the altern ative EPA-approved SIP procedures, consideration may be given to Texas criteria regarding the per centage of total annual operating hours for emission events in lieu of frequency.

Response to Comment 58: The definitions in part 63.2 Part 63 de fines “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 compatib le with the requirements of the standards. For the affirmative defense provisions, the owner or operator of a facility experiencing an exceedance of its emission limit(s) during a malfunction must notify the Administrator by telephone or facsimile (FAX) transmission of the exceedance. However, the wr itten reports required to demonstrate that the affirmative defense provisions have been met and requests for an extension of the deadline for these reports may be submitted electronically

. Pursuant to EPA regulations at 40 CFR 63.93, states may seek approval of state requirements to substitute for requirements included in final se ction 112 standards if the state requirements are equivalent to the promulgated section 112 standards. States that have SIP approved affirmative defense provisions may seek to have those programs apply in lieu of the affirmative defense provisions applicable to malfunction periods in the final rule.

e. Not require Root Cause Analysis for every malfunction.

Comment 59: Commenter 17923 states that documentation required to assert an AD will impose administrative burden with no environmental benefit. Commenter 17923 states that a facility should not be required to conduct a root cause analysis (RCA) for every malfunctio n for AD. Commenter 17923 states that the ambiguity of the recordkeeping requir ements limits confidence ina facility’s ability to demonstrate compliance.439 Commenter 17851 notes that the rule language assumes that all malfunctio ns are equally significant and need an identical degree of investigation. Commente r 17851 notes that a RCA implies a formal process, and believes a formal RCA should be used only wh en other reasonable methods fail to show what caused the malfunction or when the se rious nature of an event might make such an analysis necessary. Commenter 17851 believes a RCA for every malfunction is unnecessary and requires excess efforts with no environmental gain. Commenter 17851 states that other tools may be more appropriate (e.g., failure mode and effect, fault tree, etc.) or more powerful tools may be introduced in the future, and the facility should decide which tool to use. Commenter 17851 sugge sts the EPA use an alternative term that does not carry a specific meaning.

Commenter 19040 states that RCA is just one of many types of inductiv e analyses, and other inductive techniques should be considered appropriate are the “parts count ” approach, FEMA, FMECA, PHA, FHA, DFM, or RDB. Comme nter 19040 also suggests that deductive methods of analysis, such as fault tree analysis, would be appropriate. Commenter 19040 suggests that the EPA not limit the analysis technique, the EPA should allow the entity to use th e technique that will gi ve 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 admini strative burden will result in sources analyzing their violative emissions to reduce or avoid those emissi ons in the future, which is an environmental benefit. A root cause analysis is only required if a source seeks to assert an affirmative defense. However, such an analys is is beneficial in resolving or preventing violations and excess emissions whether the source seeks to assert the affirm ative defense or not. A r oot cause analysis is one example of what constitutes good air polluti on control practices to minimize emissions.

A root cause analysis is not re quired for every malfunction - - onl y those malfunctions for which the source chooses to assert an affirmative defense. We agree with the commenter that not every malfunction is so significant that it would require asserting an affirmative defense. The EPA believes that sources seeking to minimize em issions 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 tec hniques of analysis to achieve the desired results and c onclusions in the event of a malf unction. The EPA joins the commenter in seeking meaningful results wh ich successfully identify, and addr ess the cause of the malfunction. However, if the malfunction rises to the level of one that the source seeks to avail themselves of the affirmative defense, then a root cause analysis is required.

In the context of part 63 section 112, the term “root cause analysis” was used generically to imply an analysis of sufficient depth and complexity to indi cate whether a malfunction did indeed cause a failure to meet a standard, provide sufficient informati on on the nature and cause s of a malfunction to determine whether the source had a malfunction that met the definition of a malfunction, and whether civil penalties are an appropriate sanction for the violation, if one occurred. The term “root cause analysis” is not defined in subpa rt A (the General Provi sions) or in the subp art being promulgated, Subpart UUUUU. The EPA did not intend to prescrib e a specific methodology, gi ven that “root cause analysis” is not a defined term in the applicable subparts of Part 63.

8. SSM limits should be more stringent; emissions are high during SS events.440 Comment 60: Commenter 17975 states the EPA has not factored SSM emissions into the standards, and the EPA has not evaluated what monitoring can be done or what can be done to limit SSM emissions. Based on EGUs in Texas that have recently submitted permit applications for PM during SSM, Commenter 17975 notes that emission rates for SSM events range from 0.375 to 5.5 lb/MMBtu, which is 12 to 180 times the 0.03 lb/MMBtu limit set for non- g metals. Commenter 17975 states that facilities have requested SSM durations of 48 hours at a ti me and for up to 600 hours per year, and Title V monitoring reports for 2009 and 2010 for these same facilities show actual duration of SSM events frequently exceed 100 hr/yr, and more than 200 hr/yr at one facility.

Commenter 17755 states that a majority of PM a nd opacity excess emissions occur during SSM when the ESP is not operating.

Commenter 17975states that total PM emissions duri ng 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 emissi ons that are currently 946 ton/yr per boiler could emit up to 1,436.4 ton/yr per boiler if the SSM ap plication is granted. Commenter 17975 highlights another facility with current em issions limit of 1,033 ton/yr that c ould emit up to 2,284.4 ton/yr if the SSM application is granted. Commenter 17975 notes the SSM emission limits requested in the Texas applications are high and may jeopardize complia nce with the EPA’s non-Hg metal standard. The commenter presents an example where they assume SSM periods at 24 hours duration, incorporates these higher emission levels into the 30-day rolling average, and shows that the emissions range from 0.034 to 0.053 lb/MMBtu, which is far above the st andard of 0.03 lb/MMBtu. Commenter 17975 states that 24 hours of SSM periods woul d 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. Th e 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 indicato r of PM emissions, at EGUs in other states indicate high PM emissions during SSM events. The commenter cites an Oklahoma facility with 167.1 hr of opacity exceedances per year, and f our other facilities with over 40 hours of opacity exceedances per year due to startup/shutdown. Th e commenter notes that these estimates are conservative since they do not include opacity spik es due to maintenance events during normal boiler operation. Commenter 17975 further notes that these ex ceedances can be extreme, and cited facilities with 80 percent opacity for 25 hours.

Commenter 17755 states that their inspectors have documented signifi cant particulate emissions from COMS data during SSM and offline periods when the boiler may or may not be combusting, with greater than 400 hours per quarter for some units.

Commenter 17975 states available PM emissions and op acity data suggest that plants would have to average 10 percent opacity to achieve 0.03 lb/M MBtu PM, however opacity during startup and shutdown can be much higher, at 60 percent opa city or higher for several hours. Commenter 17975 notes that EPRI data shows PM levels of 0.06 lb/MMBtu with opacity of 15 percent; PM of 0.23 lb/MMBtu with opacity of 25 perc ent. Commenter 17975 indicates there is not much data relating PM emissions to extremely high opacity events, but cited data from a Ge orgia facility that measured 1 lb/MMBtu with opacity at 60 percent, whic h 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 f acilities have estimated. The commenter indicates that emi ssion calculations assume 30 to 80 pe rcent of fine PM are removed441 even when the ESP is not operating, because a frac tion 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, how ever 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 ex ample, an opacity exceedance of 93 percent at over 2,500 MMBtu/hr heat input. The commenter states that these much hi gher heat rates fo r startup suggest the emissions can sometimes be much higher than estimated in SSM applications.

Commenter 17975 states that many ESPs are not tu rned on during startup/shutdown because they require minimum temperature for safe operation and they cannot function effectively until certain inlet gas temperature and flow rates are reached. The commenter indicates th at ESPs are not turned on while coal is burned for extended period of time duri ng startup and in the final hours of shutdown.

Commenter 17975 states it is common for ESPs not to be energized until pr oper operation conditions occur, and it is clear that permits do not contain limits to minimize st artup and shutdown periods of ESP non-operation. The commenter states PM emissions and opacity are high during these time periods. The commenter states that high opacity during SSM time periods indicates high PM emissions, and while no uniform correlation has been developed between opacity and PM emissions, one can reasonably conclude that periods of high op acity during SSM are periods when PM and non-Hg metal emissions are high. Commenter 17975 provides examples of opacity and PM data for coal-fired units (see Table X in EPA-HQ-OAR-2009-0234-17975).

Commenter 17975 states that during startup/shutdown, baghouses can op erate at lower temperatures, may not need to be bypassed at all, and could be bypassed for a much shorter period during startup.

Commenter 17722 states that baghouses do need to be bypa ssed during startup with fuel oil, as fuel oil negatively impacts the bags.

Commenter 17957 states the EPA must evaluate maximum control technol ogies 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 start up/shutdown, or because EGUs have chosen not to explore other alternatives for reducing SSM em issions. Commenter 17975 notes baghouses are more effective during normal operating conditions, giving units a greater margin to accommodate upsets and still stay in compliance with 30-day averaging pe riod. Because more than 30 percent of EGUs are controlled with baghouses, Commenter 17975 states th at if MACT standards are based on the most effective fabric filters as the law requir es, SSM emissions would be greatly reduced.

Commenter 17975 states that while the EPA acknowle dges 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 ep isodes as immovable objects, when technologies that can reduce emission are proven and commercially available.

Commenter 17975 states there are best management practices to reduce emissions during SSM periods, including: new and existing units should be equi pped with baghouse (inst ead 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 technical ly challenging, and has modest cost;442 and the duration of SSM events shou ld be kept to a minimum by defi ning process conditions that denote the start and end of the event in enforceable permit conditions.

Commenter 17975 notes that monitoring of non-Hg meta ls is not required during SSM. The commenter notes that the monitoring methods iden tified in the proposal fall far short of what is need to calculated emissions when boilers are brought down for maintenan ce and restarted after that work is complete. The commenter indicates that stack testing is conducted during “norma l” operation and testing is not required to assure compliance during SSM, when em issions are likely to be highest. Commenter 17975 states that absent the evaluation of SSM events and methods to reduce their fr equency and severity, as 30-day rolling average designed to accommodate SSM events is an arbitrary standard.

Commenter 17975 notes that deslagging of units as partof maintenance contributes to increased opacity even though the unit is not operating. The comment er indicates baghouses can remove deslagging PM far more effectively than ESPs, wh ich would not be energized when the unit is off and when deslagging

occurs.

Commenter 17975 provides examples of drop-out fact ors used for ESPs to estimate PM emissions during startup and shutdown, where even though the ESP is non-operational or non-energized, the collection efficiency is not zero.

Response to Comment 60: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. These wo rk practice standards take into account operation of APCDs. See the preamble and rule for discus sion 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 c ontinuous monitoring devices are required to operate them at all times. Section 63.10020 clearly states that if you are conducting continuous monitoring, “You must operate the monitoring system and collect da ta at all required intervals at all times that the affected EGU is operating...” We believe that it is im portant to collect data dur ing all process operating periods including SSM periods, as the rule require s 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 peri ods of malfunction and should a malfunction period occur, its duration will be brief, as noted by the commenter. Any impact of potential excess emissions occurring during a period of malfunction would be offset through use of the rule’s 30 boiler operating day rolling average requirement. To the extent th e 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 notwith standing the CEMS measurement using any available information.

Commenter’s inference that PM emissions during st artup 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 be lieve that our approach will provide the data necessary to evaluate these emi ssions during the 8-year review.

9. Use of multi-metals CEMS and fuel testing for startup fuels.

Comment 61: Commenter 17283 states that use of a multi-me tal CEMS allows monitoring of all urban HAP metals, including Hg and all phases. Comm enter 17283 indicates that multi-metal CEMS have lower initial and on-going costs th an the EPA’s option of monitoring with two CEMS, and multi-metal443 CEMS use allows monitoring of emissions directly, so it is not necessary to conduct performance testing for individual metals.

Commenter 17675 supports the exemption fromfuel testing for startup fuels.

Response to Comment 61: For the use of multi-metals CEMS, please see the response to all comments under Comment Code 5A07b. The exemption for startup fuels is no longer applicable as the proposed fuel testing requirements are not part of the final rule.

10. Initial startup.

Comment 62: Commenter 17801 states that neither MACT or NSPS limits should apply during the initial startup of a facility, shoul d not apply until after the EGU has achieved its Commercial Operation Date (CCD), or at the earlie st, per 40 CFR 60 General Provisio ns, 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 establis h different limits based on initial startup and commissioning conditions and activities.

Response to Comment 62: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emi ssion limits, and compliance with the work practice at initial startup should not be an issue for sources. Further, comm enters have not explained under what authority EPA would allow a source to not comply with the fina l rule on the compliance date of the final rule; therefore, we are not providing the provision suggested by the commenters.

11. Initial data.

Comment 63: Commenter 17402 states that the EPA cannotestablish that the proposed numeric emission limits represent a reasonable estimate of emissions achieved by the best performers during startup and shutdown as required by the CAA and th e courts in Cement Kiln Recycling Coalition. Commenter states that, as a result, the EPA must es tablish work practice sta ndards for these periods.

Comment 64: Commenter 17776 states that the proposed rule would inappropriately require EGU’s to comply with numeric MACT standards during start ups and shutdowns even though the agency did not consider data for startup and shut down in developing the standards. Th e proposal is therefore arbitrary and capricious because the agency relies on inaccur ate or unfounded assumptions about such events. Commenter 17776-11 states that the EP A assumes incorrectly and without adequate basis that startup and shutdown are predictable and routine, that a 30 -day averaging period will accommodate startups and shutdowns, and that emissions during these period s can be accurately calculated. Commenter 17776-11 states that many outages are unavoid able and unplanned with the effect that the 30-day averaging time is not adequate given the frequency of outages.

Comment 65: Regarding startups and shutdowns, comment er 17914 cites the following as problems with the EPA’s MACT floor analysis:

 No startup/shutdown data were considered.

 Incorrectly characterized solid fuel-fired EGUs as infrequently starting up and shutting down and using cleaner fuels during startup.

 Incorrectly characterize startups and s hutdowns as predicta ble 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 performe rs and use the data to set the standard.

Comment 66: Commenter 18034 states that emissions during startup and shutdown were not evaluated for the proposed emission limits and that the EPA should establish work practices for these periods. Commenter 18034 states that the boiler MACT rule requires work practices in lieu of numerical limits for periods of startup and shutdown.

Response to Comments 63 - 66: The EPA acknowledges that it does no t have data upon which to base numerical emission limits dur ing periods of startup and shutdown. Therefore, the EPA is, in the final rule, establishing work practice stan dards for periods of startup and shutdown. In addition, the EPA is committing to reevaluating this approach during the 8- year review when sufficient CEMS data will be available from the EGU population.

Comment 67: In commenting that the EPA is not adequa tely addressing emi ssions 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 af ter boilers were turned off fo r 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 correspon d to PM emissions greater than the proposed 0.03 lb/MMBtu.

Response to Comment 67: Commenter has not provided data to indi cate the impact of these periods of high opacity on HAP emissions. Further, commenter has not provided, and the EPA does not have, data on HAP emissions during periods of startup and shutdown. In addition, it is not clear what commenter is suggesting the EPA do with this information or how we could incorporate it in to the MACT standard setting process. In the final rule , the EPA has specified work practi ce standards for periods of startup and shutdown. See the preamble for discussion.

12. Other.

Comment 68: Commenter 17402 opposes the application of th e numeric emission limits established for steady state operations to sources during periods of startup and shut down. Commenter states that as a result of the technical infeasibilityof measuring emissions and the im practicability of enforcing numeric emissions limits during those times, the statutory re quirements for the EPA’s authority to impose a work practice standard are met. The EPA should, therefor e, abandon its approach to enforcing identical numeric emissions limits during startup and shutdo wn and, instead, adopt a work practice standard consistent with its own precedent in the Industrial Boiler MACT rule.

The commenter states that even with the proposed 30 boiler operating day averages, emissions from these non-representative periods coul d significantly affect the averages, especially for peaking units or other units that com on- and off- line frequently. Commenter agrees with the EPA that startup and shutdown periods are of short duratio n in relation to the long-term opera tion of control equipment, but it is important to note that to maintain the efficiency of control equipment, they must be run in a certain way during periods of startup and shutdown. The EPA ignores what is well known–emissions control devices typically perform less than optimally during periods of startup and s hutdown. In fact, some air445 pollution control equipment cannot be operated at al l when the boiler is starting up. Commenter provides examples of how control device ope ration 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 emissi ons during the first 24 hours after startup especially for plants using ACI to control Hg from subbituminous coal, which cannot be readily controlled with other technologies. Commenter states that the numeric emissions limitations established for periods of steady state operati ons should not be applied to peri ods of startup and shutdown when controls are not performing at optimal levels (or ar e not performing at all until certain temperatures are reached).

Several commenters (17681, 17714, 17758) also support work practice standards for startup and shutdown events. Commenters note that work practic e standards are consistent with the CAA and has been done in other MACT rules, such as the industrial boiler MACT rule.

Response to Comment 68: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emissi on limits. See the preamble and rule for discussion and requirements. The EPA’s rationale for its approachto malfunctions is discussed in the preambles to the proposed rule and this final action.

Comment 69: According to commenter 17402, the EPA argum ent for not setting emission limits for malfunctions - that it would be di fficult to apply the concept of best performing to a malfunctioning unit and that it would be impracticable to take malfunc tions into account in setting CAA section 112(d) standards for EGUs - actually argues in favor of the EPA setting a work practice standard as an emissions standard for malfunction events rather than the numerical emission limits. Commenter opposes the EPA’s proposal to use its discretion to dete rmine an appropriate res ponse in the event of a malfunction and it opposes the EPA’s affirmative defens e 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, th at it follows during malfunctions and breakdowns, which is preferable to the EPA’s proposal in which there is a presumption of non-compliance and is focused on af ter-the-fact penalty. Furthermore, the EPA’s approach would add yet another burden on the states ata time when states are working with increasingly limited resources and are already ov erburdened with regulatory respons ibilities. Since it would not be technically feasible to accurately measure emissions and impracticable to enforce numeric emissions limits during malfunction and breakdown (for either stack testi ng or CEM monitoring, which would not have the ranges required to have accurate data), the statutory requirements for the EPA’s authority to impose a work practice standard are met and the EPA should abandon its approach to enforcing identical numeric emissions limits during malfunction a nd 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 fa ctored into development of CAA section 112 standards. As the EPA further explained, accounting for malf unctions would be difficult, if not impossible, given the myriad diffe rent types of malfunctions that canoccur 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 crit eria that must be met to justif y a work practice standard under CAA section 112(h). Further, setting work practice standards under section 11 2 presents the same issues as setting numerical emission limits given the varied na ture of malfunctions. In any event, commenter has446 not provided support for its assertion that it would not be technically feasible to accurately measure emissions and impracticable to enforce numeric emissions limits during ma lfunction and breakdown. Sources in this category can and do operate multip le measurement systems that measure different parameters at different points in the generating process and on affect ed 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 whatso ever to determine whether they stayed in compliance during a malfunction. Sources may use othe r available means (including engineering judgment) or information to demonstr ate that the source complied with the standard.

With respect to commenters claim that the affi rmative 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 Excessi ve Emissions During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983)). We do not have any indication that states have had any significant difficulties applying or implementing the terms of these SIP affirmative defenses.

Comment 70: Commenter 18539 recommends that a startup, shutdown and malfunction plan that is incorporated into a unit’s title V permit is an appropriate work pract ice standard for startup, shutdown and malfunction. Commenter 17402 recommends that th e 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 period s 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 av eraging period be increased to a rolling 12-month average time period as opposed to the proposed 30-day rolling averag e. In this way, the increased emissions from periods of SSM would be spread out over a longer averaging period, and the EPA could potentially show that the limits were achievable even during SSM events.

Commenter 17776 likewise believes that a more stri ngent approach for startup and shutdown emissions is not necessary for some types of boilers and en courages the EPA to requi re compliance with work practice standards for EGUs as in the Boiler MACT. Failing that, the commenter suggests that the EPA set special MACT standards for startup and shutdown periods at EGUs based on a reasoned analysis of data concerning such emissions.

Commenters 17790 and 17851 find the EPA’s logic about applying the propos ed standards during startup and shutdown to be flawed because it does not account for the variety of ways in which the EGUs startup and shutdown and b ecause it is not based on actual em issions 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 certifi cation testing and the EP A manual test methods are not designed for transient plant operations. Ther efore, 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 peri ods of startup, shutdown, malfuncti on 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 decisi on ignores that it is well known that emissions control devices typically perform less than optimallyduring periods of startup and shutdown. In fact, some air polluti on control equipment cannot be ope rated at all when the boiler is starting up.

Response to Comment 70: For periods of startup and shutdown, the EPA is finalizing work practice standards instead of numeric emission limits. These standards take in to acc ount operation of APCDs. See the preamble and rule for discussion and requir ements. The EPA’s rationale for its approach to malfunctions is discussed in the preambles to the pr oposed rule and this fina l action and elsewhere in this response to comments document. The requ irements do not include a startup, shutdown, and malfunction plan. See Table 3 to Subpart UUUUU of part 63. Commenter’s suggestion that its stateapproved plan is prefereable to EP A’s approach does not explain how anapproach based on such a plan meets the requirements of section 112.448 5C07 - Compliance: Other

Commenters : 16849, 16850, 17385, 17402, 17620, 17638, 17648, 17689, 17702, 17714, 17716, 17718, 17719, 17729, 17730, 17736, 17737, 17740, 17752, 17754, 17756, 17758, 17761, 17765, 17767, 17768, 17772, 17775, 17790, 17791, 17795, 17798, 17800, 17805, 17808, 17813, 17818, 17820, 17821, 17840, 17851, 17867, 17868, 17871, 17880, 17881, 17886, 17902, 17909, 17914, 17928, 17930, 18019, 18025, 18034, 18424, 18429, 18477, 18498, 18539, 18541, 18963, 19033, 19114, 19214, 19536, 19537, 19538, 18023

1. Support low emitters alternative compliance.

Comment 1: Commenter 17402 supports establishment of a low emitters alternativ e compliance, with modifications. Commenter 17402 states that faciliti es that satisfy the low emitters standards are necessarily demonstrating emissi ons 50 percent to 90 percent belo w the proposed limits, and these extremely low emissions should be encouraged w ith 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 part icular level of emissions during the test.

Commenter 17754 states that if an affected EGU has b een determined to be a LEE (for Hg), it is clear that such unit’s Hg emissions are very low, and as such, these LEE units should not be subject to unduly burdensome requirements for demonstrating continuous compliance.

Commenter 17176 states the fuel sampling requir ements for LEE units are ambiguous, provide no compliance value, do not require th e establishment of a fuel input operating limit, do not address singlefuel units, changes in fuel type, or units that burn or co-fire multiple fuels. Consistent with the non-LEE requirements, Commenter 17176 states that LEE units th at burn multiple fuel types or blends should establish a fuel-input operating limit during the in itial compliance demonstration, and the EPA should remove the monthly fuel sampling requirement and allow multiple-fuel LEE units to conduct fuel sampling only when the fuel type changes. Comm enter 17176 states single-f uel LEE units should not have to comply with any fuel sampling requirements.

Commenter 17754 states the EPA should revise the proposed rule regarding the use of the 90th percentile upper confiden ce level for determining the operating limit for mercury (LEEs for Hg). Commenter 17754 states the rule should be clarified th at, while the initial perfor mance test is conducted over a 2830 day period to demonstrate LEE status, the s ubsequent performance tests (performed every 5 years) shall consist of three 120-mi nute runs, unlike the longer durati on of the initial performance test.

Commenter 17754 notes the rule should be modi fied because it is unclear whether a source owner/operator who demonstrates ini tial satisfaction with th e LEE criteria, but then subsequently fails to demonstrate continuous compliance with the relevant standards, has the abilityto retest the unit to reestablish its LEE status. Commenter 17754 states a s ource owner should be afforded the opportunity to demonstrate that an affected EGU qualifies as a LEE, notwithstanding a prior performance test result exhibiting emission rates in excess of the th reshold. Commenter 17754 in dicates the compliance demonstration methods under the rule provide a highly conser vative estimate of Hg emission rates for purposes of ensuring LEE status, and this conser vatism should not prevent such source owner from demonstrating LEE applicabilit y by more refined analyses.449 Response to Comment 1: The final preamble describes the final rule provisions for LEE. Because the proposed fuel analysis provisions are not part of th e final rule, the approach to maintaining LEE status has changed. For mercury, an existing unit may qualif y based on an initial Me thod 30B test, and then will have to retest annually. If the LEE status is lost based on the resu lts of an annual retest, the rule requires you to install an Hg CE MS or sorbent trap monitoring sy stem, with quarterly Method 30B testing until the monitoring system is certified. You canregain LEE status for that unit if every required performance test for a 3-year period shows that em issions 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 subseque nt 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-estab lish 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 t oxics rule will provide needed regulatory certainty and will spur investment in new generation controls. Co mmenter 17648 notes that today we increasingly rely on aged infrastructure that operates without polluti on controls simply because the federal government has failed to establish le gally enforceable emissions standard s for toxic pollutants. Commenter 17648 states that the lack of a national standard for toxic emissions continues to be a barrier to investment in new, cleaner generation capacity as well as the modernization of existing sources. Commenter 17648 states companies are reluctant to build replacement, cleaner generation or to modernize existing plants when it is not assured that their competitors will be required to comply with modern emission standards, and it has been found that the inst allation of pollution controls w ill raise the marginal costs of production for those early adopters and place them at a competitive disa dvantage relative to those that do not install pollution controls. Commenter 17648 states the regulatory certainty provided by the toxics rule is long overdue.

Commenter 17930 supports the EPA’s decision that it was not appropriate to set numerical emissions limits for organic HAP and that a work practice standard would be more appropriate. As stated by the EPA, the majority of measured organic HAP emissions from EGUs are below the detection leve ls of the EPA test methods. They cannot be reliably measured and cannot be subject to emissions limits.

Commenter 18541 states that technol ogies are available to achieve such reductions, and virtually eliminate some of these emissions, not only though on-site emissions reductions , but also by switching to cleaner sources of electricity generation and energy efficiency, and using improved grid system management within the relevantelectricity balancing area.

Commenter 17718 supports the EPA’s proposed appro ach to streamline the continuous compliance requirements for monitoring, reporting, and recordkeepi ng. The commenter states that the EPA is correct in recognizing that the compliance requirements ar e already applicable to EGUs and eliminating redundancy wherever possible. The commenter ur ges the EPA to remain open to additional accommodations that are identified in the course of implementing the program.

Commenter 19214 states that to de monstrate compliance with both the Boiler NESHAP and the EGU MACT, the more stringent emission limit should be de monstrated. The commenter states that it is the responsibility of the source to s how 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 testing.

Comment 3: Commenter 17808 states the testing requirement s are very burdensome and believes the agency could achieve an equivalent level of comp liance assurance with a lo wer compliance burden with adjustments.

Comment 4: Commenter 18023 urges the EPA to allow annua l filterable PM stack testing as an alternative compliance option. Commenter 18023 notes th at complying with the monthly or bi-monthly PM or non-Hg metallic HAP alternativ es is not practical for the following reasons: (1) both planned and forced outages will make it difficult to obtain prop er unit operating levels, which will stretch the short term capacity of the testing community nationwide; (2 ) it is cost prohibitive, as PM testing will cost approximately $3000 to $5000 per source per month, Hg testing via RM-30B will cost approximately $10,000 per source per month, and non-Hg metal testing via RM-29 will cost approximately $8,000 to $10,000 per source per month; (3) analyt ical results take a minimum of 2 weeks to be analyzed and reported by laboratories, so a unit co uld potentially be out of complian ce for 2 weeks before analytical results could be provided; (4) analyzing this data is a difficult scientific pr oposition – lab technique and experience are important to avoid biasing the da ta; and (5) changing compliance and permit limits monthly based on new test results wo uld place unreasonable operational restrictions on generating units in an effort to comply with a potentially moving target.

Response to Comments 3 - 4: In the final rule, the optional period ic testing has been reduced to once a quarter. Sources have the option to use CEMS or PM CPMS in lieu of compliance testing.

Comment 5: Commenter 17775 states EGUs should have flexib ility to specify when performance tests for CEMS and sorbent trap monitoring sy stems start. Commenter 17775 notes that for CEMS or sorbent trap monitoring system, the “p erformance test” consists of the “first 30 operating days of data collected with the certified mon itoring system.” (section 63.10005(a)); section 63.10005(g) through (j) allows 180 days after the applicable compliance date to “d emonstrate initia l compliance;”and “performance tests” also must be conducte d under specific operating conditions (section 63.10007(c)). Commenter 17775 objects to the proposed arbi trary designation of the “performance test” periods. Commenter 17775 states the start of perfo rmance tests should not be arbitrarily tied to completion of monitor certification, but instead, EGUs should be allowe d to complete certification tests on monitoring systems and to use those certified systems to determ ine whether the shakedown of emission controls have been successful prior to conducing the “performan ce test” to establish compliance with emission limits. Commenter 17775 notes th at EGUs also must be able to time the start of the “performance test” to ensure that it meets the fuel and operating conditi ons the EPA has specified. In fact, proposed section 63.10030(d), which requires submission of a “Notif ication of Intent” to conduct a “performance test” at least 30 days before it is scheduled to begin, s uggests that sources have the ability to specify a date in advance that may be unconnected to the testing of the monitoring system.

Commenter 17775 states that allowing sources flexibil ity to specify at what point during the 180-day period the “performance test” starts not only make s sense, it is in some cases necessary. At a minimum, Commenter 17775 indicates the EPA needs to a llow flexibility for source s 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 outthat otherwise their performance test technically could have begun prior to the compliance deadline (or even prior to this451 rule being promulgated). The comme nter states that in addition, for PM CEMS, which do not conduct anything called “certifica tion testing” (the term “certification” does not appear anywhere in PS 11), there is no clear point at which to declare that the performance test has begun. Unlike SO 2 CEMS, PM CEMS must be correlated by conducting tests with a refe rence method and developing a “correlation curve” that meets PS 11 performance criteria. According to the commenter, once the curve is developed, the PM CEMS must be programmed so th at its output is adjusted consistent with that curve. The commenter states that none of these acti ons are consistent with the concept of a system instantly becoming a “certified” upo n 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 testi ng if the 7-day test is not passed, and as a result, the drift test cannot be used to define when the PM CEMS is ”certified.”

Response to Comment 5: While the EPA does not share the concerns that the commenters have about relating monitoring system certification with performan ce testing, final rule has been revised so that 30 day test is not tied to the certification of the CEMS or sorbent trap monitoring system. In addition, as mentioned elsewhere, the requirements for the manda tory use of PS-11 have been removed from the final rule.

Comment 6: Commenter 17775 notes that the EPA must r ecognize 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 assesse d the capabilities of controls under the c onditions specified in the 2010 ICR testing and establis hed compliance testing and compliance assurance requirements consistent with that assessment. Commente r 17775 indicates the EPA has proposed continuous monitoring, initial stack testing, or pe riodic fuel analysis that it presum ably believes are consistent with that assessment; as long as an EGU is complying w ith one of the options for demonstrating “continuous compliance,” there is no basis to al low the Administrator to specify so me other test be conducted under some other set of conditions.

Commenter 17775 agrees that EGUs should be allowe d to use prior tests, however, the EPA should allow use of any tests conducted under the same condi tions, even if those condi tions have not remained unchanged during the entire period sin ce the test (e.g., if there was a pe riod between the prior test and the current compliance demonstration wh en a different fuel was combusted).

Commenter 17880 supports the EPA to require affected co al or oil-fired plants to conduct performance tests that demonstrate compliance with applicable emissions limits.

Commenter 17928 states that the fr equency of performance tests requ ired for organics compliance should be reduced.

Commenter 18025 asks that the EPA gi ve consideration to units alrea dy subject to stat e-level testing requirements where these requirements provide at leas t the same assurance as the Utility Toxics Rule. The commenter notes that their Br idgeport coal unit complies with a Hg emission standard half that proposed by the EPA for similar units. The commenter states that Connecticut DEP remains confident that quarterly stack testing provi des a sufficient guarantee of compliance. The commenter states that likewise, the commenter’s Hudson and Mercer coal uni ts consistently comply with New Jersey’s Hg requirement through stack testing, and recent test data ha ve shown very low levels of Hg relative to New Jersey’s Hg limit of 3.00 mg/MWh (net). The comment er requests that in si milar situations state requirements be accepted as alternate tes ting 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 thatmany coal and lignite fired units are scheduling 24-month outages; some have even longer scheduled outages. According to the commenter, in the next few years, it is expected that the schedule will be extended even more as maintenance practices improve and as consumer electricity demands, and demands for base load capacity, increase. Therefore, Commenter requests that the final rule provide the option for performance tests a nd tune-ups to be conducted on the existing schedule of each power plant. The commenter st ates that in the event that the EPA feels there must be a maximum time limit, it cannot be shorter th an 36 months without signifi cantly interfering with plant operations.

Response to Comment 6: In response to comments, EPA has redu ced the duplicative testing of fuels, HAP surrogates and HAP. Optional periodic testi ng frequency has also been reduced. The EPA disagrees with the adoption of vari ous state Hg rules within the fina l MACT rule. Sources may apply on a site specific basis for alternative monitoring pe r 63.8. Neither the proposed ru le nor the final rule required organic HAP compliance testing, so there is no frequency to be changed. The tune-up work practice and testing has been altered to allow for more flexibility for facilities with less frequent outage schedules.

Comment 7: Commenter 17775 states that the purpose of section 63.10005(d)(7) “(demonstrate initial compliance through CPMS)” is unclear. Commenter 17775 is not aware of any op tion in the rule to demonstrate compliance using CPMS that measure po llutant concentration. Commenter 17775 states the EPA should issue a proposal that explains the purpose of this provi sion so that they can provide meaningful comment on it.

Response to Comment 7: The commenter is correct that there was no option for initial compliance option for use of CPMS in the proposed rule and this was an erratum.

4. Frequent testing for liquid oil-fired units.

Comment 8: Commenter 17758 states that frequent performa nce stack testing (monthly or every other month) for oil-fired EGUs is impractical, unnecessary, restrictive, and expensiv e, 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 shoul d perform stack testing no more frequently than annually.

Commenter 17775 states that for section 63.10006(l) and (m) for liquid oil-fired EGUs without HCl and HF CEMS”, the EPA must make it clear that the HCl and HF testing requirements do not apply to EGUs using fuel analysis in lieu of performance te sting, and that fuel analys is is an alternative to performance testing.

Commenter 17928 requests that the hours for mandator y unit testing should not be included in the calculation of oil use. These tests required by the ISO or for complian ce with the proposed rule should be exempt from any “ limited use” calculation.

Commenter 17716 states that many liquid oil-fired sour ces operate infrequently and only during peak demand periods, and frequent performance testing (monthly or every other month depending on whether add-on controls are installed) is burden. Commenter 17716 further no tes that no correlation was found between the PM control at oil-fired units and non -Hg metallic HAP emissi ons, that the emissions453 of HCl, HF, and non-Hg metals are mo st closely tied to fuel characteristics, and that changes in fuel characteristics over time could be tracked to determine if a change in emissions is likely. Commenter 17716 states the fuel sampling, anal ysis, and calculation of expected emission rates are already incorporated in se ction 63.10021 and should be applied for liquid oil-fired sources.

Response to Comment 8: Under the final rule, liquid oil-fire d units have three basic options for monitoring compliance, with a third alternate a possibility in some s ituations. First, these units may conduct quarterly performance tests to demonstrate ongoing compliance. If they choose this option, they must also conduct site-specific monitoring to ensure compliance between tests (see the final preamble for further discussion). Second, sour ces may use CMS for various polluta nts. This includes the use of a PM CPMS to demonstrate compliance with an operat ing limit established duri ng an initial performance test that demonstrates compliance with a filterable PM, total HAP metals, or individual HAP metals emission limits. A source can also elect to use a PM CEMS as a direct compliance method with the filterable PM standard (see the preamble for further di scussion of this option). It also includes the use of an HCl/HF CEMS for acid gas compliance demonstrati ons. The third alternative is for fuel moisture monitoring. This compliance option a llows 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 mustinstitute one of the other options for monitoring compliance with the HCl and HF limits. With respect to the comment concerning the need for HCl/HF CEMS performance specifications, please see the responses to comments under Comment Code 5A09.

5. Operating limits.

Comment 9: Commenter 18023 suggests BLDS for fabric fi lters are not necessary, and if BLDS are required in the final rule they s hould only be used for purposes of triggering maintenance activities. Commenter 18023 explains the following for BLDS: (1 ) this operating limit is purely arbitrary, the EPA provides no information nor makes any claim that th e operating limit quantifiably connected to the HAP emission limit; (2) the preamble language provides a different requirement where the output of the BLDS is measured during performance testing and then becomes a BLDS operating limit, this is an improper use of the BLDS as it attempts to use th e system to quantify emission rates; (3) the EPA guidance document on Fabric Filter Bag Leak Detec tion Guidance states, “this guidance is not intended to evaluate changes in the long term performance of the baghouse system, nor does it apply to applications in which monitoring system attemp ts 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 oc currences and could be adequately identified in the bi-monthly performance test re quired by the MACT.

Comment 10: Commenter 18023 suggests settin g fixed secondary power input limits for ESPs is unnecessary, and if the EPA goes fo rward setting ESP operating limits, the only necessary requirement should be to ensure that ESP power supplies remain in servic e. Commenter 18023 explains the following: (1) ESPs are generally designed to m eet a specified performance level with one or more TR sets out of service, this provides opera tional margin for malfunction and/or maintenance of each TR set, a boiler operator w ould have to perform its compliance test with secondary power artificially reduced in order to maintain this margi n, and this seems to contra dict the EPA’s desire to acquire meaningful emission data; (2) process conditions beyond the c ontrol of the boiler operator such as flue gas temperature, fly ash resistivity, and grain lo ading can affect the pow er levels of the ESP without necessarily detrimentally impacting emissions, some margin should be added to the operating limit to account for this variability ( i.e. , within 20 percent of the lo west 1-hour average secondary454 power); (3) because performance doe s not correlate perfectly with ESP secondary power, a reduction in power is more appropriately used to trigger maintenance activity ( i.e. , returning a TR set to operation) rather than being used to determ ine compliance; and (4) it is uncle ar why the proposed operating limits only apply for EGUs that operate additional wet control systems, the EPA should clarify what requirements they are proposing for EGUs that operate only an ESP.

Response to Comments 9 - 10: The EPA has responded to similar comments under Comment Codes 5A05 and 5A05a. Please see those responses. Under th e final rule, there are no operating limits for control device parameters or any BLDS requirements.

6. Support flexible compliance options.

Comment 11: Commenter 16850 states that electric utilities s hould be given the flexibility to choose the most efficient, least-cost compliance options to meet public health and environmental goals.

Commenter 17648 notes the EPA has pr ovided a variety of compliance op tions, particularly notes that the EPA provided a flexible array of compliance op tions for both initial and continuing compliance demonstrations, and encouraged th e installation and use of CEMS but has not mandated CEMS, thus giving sources reasonable opportunityto design different compliance pr ograms that best align with the source’s short- and long-term plans.

Commenters 17730 and 17820 appreciate that there ar e 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 sour ces 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 tec hnologies for coal-based units drive the selection of emissi ons controls, such as wet versus dry flue gas desulfurization.

Comment 13: Commenter 17772 states that the proposed ru les 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 complian ce 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 achie ve for an existing EGU that is reconstructed or merely modified, by eliminating the existing SSM exclusions. Commenter r ecommends that the EPA reconsider incorporating these SSM exclusions.

Comment 14: Commenter 17791 requests that the EPA recogni ze the needs of states and regions to deploy a diverse portfolio of cost -effective supply-side and demand-si de resources based on the unique circumstances of each State and region.

Commenter 18539 states that the EPA takes steps to pr ovide critical flexibility by providing for the use of surrogates to demonstrate compliance, proposi ng work practice standards where appropriate and allowing for emissions averaging. The commenter states that the EPA diminishes the utility of these flexibility mechanisms-consequently driving up costs and complexity-by placing burdensome and unnecessary restrictions a nd requirements on them, without demonstr ation of substantial environmental or health benefits and that the EPA’s proposed compliance testing and monitoring programs are455 complicated, confusing and costly, w ithout any demonstration as to why the requirements are necessary or how they would ensure compliance over the lo ng term even among the existing top 12% MACT pace
setters.

Commenter 19114 asks for greater flexibility so sour ces can reliably demonstrate compliance, such as through reexamination of the source s of uncertainty and r ecalculation of the lim its, longer averaging times, additional options for averag ing 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 ac ross the whole range of operations a unit would experience. The commenter states that the EPA shoul d consider the full range of operating conditions that might be expected over the life of a unit in es tablishing the final rule. Th e commenter is concerned that there is a risk of non-compliance due to unkn own and uncontrollable variables, especially for elements present in trace quantities for which no de tailed operational history exists, is significantly increased. According to the commenter, state agenci es have designed permits with limits or work practice standards that are applicab le to specific coal types and/or operating scenarios. The commenter states that in many cases, permits have been designed that exempt specific ope rating conditions, such as startup, shutdown, and malfunction operations, from th e emission limits designed for normal operations. According to the commenter, particul arly in the case of EGUs where control equipment is subject to known operational limits (like safe operating temper atures in the flue ga s before electrostatic precipitators can be energized or ammonia injection for a selective catalytic converter can commence) the case for the development of work practice standards is strong. The commenter asserts that the EPA’s proposed limits do not provide sufficient flexibility to allow compliance demonstrations to be made during reasonably foreseeable operating scenarios and must be reevaluated.

Comment 15: Commenter 16849 supports the need for at least a 180-day period to perform all compliance testing including needed ad justments 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 year s, could lead to unnecessary operation solely to demonstrate compliance, which is undesirable from both an environmental and a financial perspective.

Response to Comments 11 - 15: We address comments related to the compliance time and startup/shutdown/malfunction in the preamble to the fina l rule and elsewhere in this RTC. With regard to the flexibility comments, we believe that we have provided the flexibility reasonably allowed under the statute and court precedent. As noted elsewhere in this document, we have made adjustments to the monitoring provisions of the final rule that we believe will reduce the burden and complexity while complying with the statute.

The rule increases the emissions monitoring, reporti ng, recordkeeping, and testi ng options available to EGU owners or operators by adding a dditional choices, each of which ha s an averaging time that assures compliance with emissions limits. The rule no longer contains emissions limits but work practice standards, including operation of emissions control de vices as appropriate, duri ng periods of startup or shutdown and does not impede development and depl oyment of diverse energy portfolios. Compliance options have been simplified, but still assure compliance with emissions limits. While the Agency finds no impediment concerning averaging periods base d 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 practice standard, rather thanconduct emissions testing, thus preventing the commenter’s concern about unnecessary operation solely to demonstrate compliance.456 7. Clarifications needed for compliance demonstration.

Comment 16: Commenter 17752 states that the compliance de monstrations require clarification and revision. Commenter 17752 notes that although the EPA provides a number of compliance demonstration options, the applicability of many requirements is unclear . Commenters (17752, 17775) state the EPA must revise the proposal to clarify what requirements apply to each compliance option and include supporting rationale for each require ment. Commenter 17752 notes the preamble has inconsistent statements and lacks rational as to when operating limits and fuel input limits apply and when they do not apply (citing IV. Summary of this proposed NESHAP Section I. What are the testing requirements? Section J. What ar e the continuous compliance requirements? Section K. How did we select the compliance requirements? and V. Rati onale for this proposed NESHAP). Commenter 17752 cannot think of any rationale as to why a source with a continuous mon itor would also need to comply with an operating limit, and the commenter believes that the EPA intends for the operating limits and fuel input limits (including the operating load limit and continuous parameter monitoring systems) to only apply to EGUs who do not us e continuous monitors to demons trate compliance. Commenter 17752 states that if this is not the cas e, the EPA needs to include rational e for requiring the operating limits and provide an opportunity for publ ic 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 th at this supposed distinc tion between EGUs that demonstrate compliance using “performance testing,” a nd those that do not, does not exist elsewhere in the rule (or in the Part 63 ge neral 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 id entifies emissions testing, CEMS, sorbent trap monitoring, and LEE testing as “performance stack testing.” Commenter 17775 states proposed section 63.10005(a) defines “performance tes ting” to include the first 30- operating days of CEMS data. Commenter 17775 points out that although proposed sect ion 63.10005(c) allows liquid oil-fired EGUs to “demonstrate initial compliance . . . by conducting fuel analysis,” it is not clear whether the EPA intends that to constitute another form of “performance testing,” or an exception to it, and if it is an exception to it, the other provisions do not re flect that. Accordingly, Commente r 17775 indicates the proposed rule on its face appears to require all EGUs to establish site-specific operating limits for all controls used to meet emissions limits under the rule, and maximum fuel pollutant limits for chlorine, Hg, and non-Hg metals “according to” the cited provisions and paragra phs regardless of the compliance “option” they choose.

Commenter 17775 states that the EPA must specify th at the operating limits (including the operating load limit) and fuel input limits apply only to EGUs using stack tests to comp ly, or explain why those requirements are necessary for other units.

Commenter 17881 states that the EPA mu st revise the fuel types section in the proposed rule to clarify what requirements apply to each compliance option. A ccording to the commenter, the EPA must provide a clear rationale for each proposed requirement.

Commenter 17775 assumes that the purpose of the control device operating limits is to help assure compliance between performance tests at EGUs that are not otherwise monitoring compliance with the relevant standard continuously (e .g., at EGUs not using CEMS or sorb ent trap monitoring systems), and457 that the purpose of the fuel input limits are to en sure that EGUs that are not otherwise monitoring compliance with the relevant standard continuou sly (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 th at establish compliance with CEMS or sorbent trap systems to establish and demonstrate compliance with these other requirements. Commenter 17775 notes that this assumption appear s to be supported, somewhat, by the EPA’s few preamble statements. Commenter 17775 states the EPA must revise the rule and Tables signi ficantly in order to make clear that only those EGUs that demonstrate compliance with a specific HAP or surrogate “through performance testing other than CE MS or sorbent trap monitoring systems,” must comply with these requirements, or if the EPA does not so revise the rule, the EPA must issue a new proposal and provide a purpose for what appear to be re dundant and unnecessary requirements.

Commenters 17775 and 17790 state that the propos ed monitoring and compliance provisions are difficult to interpret and inadequately explained. According to the commenters, many of the EPA’s proposed provisions simply require compliance “as a pplicable,” but the EPA nowhere clearly states when the requirements apply. In other cases, the propos ed applicability seems cl ear, but the reason is not. Commenter 17775 cites an example, that the EPA cl early states in the preamble and in the proposed rule that EGUs that choose to comply with a su rrogate 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 w hy such testing is relevant, what the EGU is to do with the results, or how the proposed requirement can be reconciled with ot her provisions clearly allowing EGUs a choice between a HAP or a surrogate limit.

Commenter 17871 states that the compliance requirements are duplic ative and burdensome and would not provide any additional protection to public health or the environment.

Commenter 17928 states that the EPA’s proposed te sting and compliance demonstration requirements are unnecessarily complex, confusing and burdensome.

Commenter 17795 requests that the EPA provide complian ce demonstration flow ch arts for each of the categories of affected units. A ccording to the commenter, when regulators conduct required permit inspections without meaningful fl ow charts and a clear understanding of multiple paths for compliance, there will be a tremendous amount of uncertainty for both the regulated community and the regulators. The commenter states that providi ng flow charts would make it easierto incorporate this type of information into existing Title V permits.

Response to Comment 16: The EPA has made changes in the fi nal rule based on these comments to clarify and simplify the various monitoring and tes ting requirements. Please se e the discussion in the final preamble. The EPA believes these clarificat ions eliminate unnecessary duplication and provide sources with clear options fo r demonstrating compliance.

Comment 17: Commenter 17820 recommends that the EPA pr ovide clarification that units operating DSI technology will qualify fo r the option to use SO 2 as a surrogate for HCl. Commenter further states that the compliance demonstrati on, recordkeeping and re porting requirements need clarification and further explanation. The commenter states that the applicability of many requi rements, like fuel input limits and control device operating parameters are unc lear, and in other cases, the applicability seems clear, but the purpose is not or is questionable. According to the co mmenter, this can be addressed by providing additional clarity and explanation in the pr eamble to the rule or more specificity in the458 regulatory text concerning requirements for performance testi ng, continuous parameter monitoring systems, fuel sampling and analysis, control de vice operating parameters, monitoring and reporting.

Several commenters (17868, 18424, 18963) question the EPA’s assumption that a large number of EGUs will use DSI to control acid gases. The commenter states that while DSI is a lower-cost option to reduce acid gas emissions, there is nothing in the history of its usag e 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 commercially demonstrated applications of DSI for th e control of HCl from coal refuse-fired CFB units. Commenter 17868 questions the EPA’s assumption that the 3-year compliance schedule is achievable based on the use of DSI systems rather than FGD. Commenter 18424 also questions the EPA’s projection that a large number of EGUs will use DSI to control acid gases, and the use of these controls will increase the use of high-sulfur coals. According to the commenter, the EPA’s own consultant, Sargent and Lundy, has recommended not employing DS I 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 comme nter states that few utilitie s 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 s ource uses DSI and FGD, then that unit would qualify. The Agency estimates an additional 329 EGUs will choose some form of acid gas control by 2015; should an owner or operator find DSI unsuitable, he or she could choose from other approaches, including FGD or FBC with reagent injection. With respect to the rema ining general concerns about the clarity of the monitoring and tes ting provisions, please see response to Comment 16, directly above. Comments related to our assumptions with regard to DSI are responded to in the preamble to the final rule.

Comment 18: Commenter 17821 states that the EPA needs to revise the descripti on and definitions of the IGCC APCD to account for upstream fuel cl eanup 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 me tal HAP, sulfur, chloride) directly from the fuel stream of IGCC units. According to the commenter, in this respect, IGCC is more akin to a natural gas-fired combined cycle unit, since it burns a syngas, which is cleaner than the coal combusted in a pulverized coal unit. According to the commenter, the EPA should reflect th at IGCCs use upstream gasification/fuel clean-up (for example, AGR, SRU, PM scrubber) in the same way that coal-fired EGUs are credited for postcombustion or other air pollution control equipment such as SCR, ESP, and FGD. The commenter states that it makes no sense for IGCC to have additional testing burdens if redu ced testing programs are allowed for coal-fired units with APCD. According to the commenter, the EPA recognizes that an IGCC unit is a distinct type of electr ic generating unit by proposing a separate subcategory for IGCC units, and the EPA needs to further acknowledge the process differences between IGCC units and PC units by providing clarification that for purposes of this MACT the affected facility is the combustion turbines and any emission limitations apply to the heat recovery steam generato r HRSG stack. Commenter recommends that the EPA needs to provide further cl arification that all upstream fuel clean-up in the IGCC process qualifies as control eq uipment, thereby not putting a ny 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 EP A should clarify the use of heat input and generation output terminology to a ccount for (1) differences between coal-based (gasifier feedstock - based) and syngas-based heat inpu t; and (2) differences between syngas-based and natural gas-based output during co-firing operations.

Response to Comment 18: The final rule does not establish diffe rent testing frequencies based on the presence of add-on controls, so the concerns rais ed by Commenter 17821 are no longer relevant. As the final rule contains definitions for coal-fired electric utility steam ge nerating unit, integrated gasification combined cycle electric utility st eam generating unit, and natural gas -fired electric utility steam generating unit in §63.10042, there is no need for additional cl arification. According to the definitions. an IGCC that co-fires syngas derived from either coal or solid oil fuel with natural gas and get more than 10 percent of the average annual heat input during a ny of 3 consecutive calendar years or more than 15.0 percent of the annual heat input during any calendar year from syngas, it is an IGCC electric utility steam generating unit.

The commenters concerns about EPA not accounting fo r pre-combustions practices that remove HAP from the syngas are unfounded. Both the input and output based standards applicable to EGUs are production based limits. The EPA does not determine how a source will meet the standard only that the HAP emissions (or surrogate emissions) coming out of the stack must not ex ceed the standard. If a syngas production process removes sufficient HAP before combustion, the HAP concentration coming out of the stack should be compliant with the standards, perhaps even without the installati on of add-on controls.

Comment 19: Commenter 17867 states that the EPA should revise and/or cl arify some aspects of the rule.

a. Adjustments to the provisions concerning test ing, initial and continuou s compliance with the standards including:

i. The frequency of non-Hg metals and HCl test ing should be extended if consecutive testing shows emissions meet the standard.

ii. If a source elects to use PM as a surrogate , the emission limit should be established during the performance test to ensure it correlates with either total or individual non-Hg metal HAP emissions.

iii. Filterable PM, as used by the EPA in the final Industrial Boiler MACT, is the appropriate standard to use as the non-Hg metals surrogate.

iv. The EPA should adopt work practice standard s during periods of startup and shutdown for sources subject to the rule as used by the EPA in the final Industrial Boiler MACT.

v. The EPA should not require parametric monito ring for sources electing to show compliance by utilizing continuous emi ssions monitoring systems.

b. The EPA should allow states to request equivalency determinations based on state rules that cover the same pollutants, but with diffe rent control 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 limit applie s 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 emission s limit during startup and shutdown periods. See preamble for discussion. For th e issue in item (a)(v), the final rule does not require parametric monitoring where a CEMS is us ed to demonstrate compliance. For item b, these standards apply as federally enfo rceable standards. A Part 70 opera ting permit may provide for certain streamlining of applicable requirements, consistent with the applicable guid ance and requirements that govern the Part 70 program.

Comment 20: Commenter 17881 states that the requirement s of section 63.10031 should not apply to start-up/shutdown and flame stabilization fuels.

Comment 21: Commenter 17928 requests the EPA to pr ovide clarification on the compliance requirements for units that may change from being “nat ural gas-fired” to “oil-f ired”. According to the commenter, the proposed rule is unclear with rega rd to how much time the EPA would allow a newlydesignated oil unit to schedule and conduct initial performan ce tests to demonstrate compliance with the applicable standards.

Response to Comments 20 - 21: While the rule no longer requires compliance with emissions limits during periods of startup or shutdown, the rule main tains reporting requirements associated with the work practice requirement s during those periods.

8. Cannot meet compliance deadline.

Comment 22: Commenter 18023 indicates that the require ment in section 63.10005(g) to demonstrate initial compliance for existing sour ces no later than 180 days after th e compliance date is problematic for sources that may be in an outage or tempor arily not operating on the compliance date. Commenter 18023 states the EPA should clarify th at compliance demonstrations must be complete within 180 days after the compliance date or , if the unit is not oper ating on the compliance date , then 180 days after the unit begins operation. Commenter 18023 fu rther states that given the co ncerns that the proposed rule provides inadequate time to install c ontrols, it is likely a number of util ity units will be shut down on the compliance date.

Commenter 17714 states that the 3-year compliance d eadline could be problematic because utilities must also consider the potential impact of the G HG NSR permitting requirements that could be triggered for large emission control projects, especially wet flue gas desulfurization projects. The commenter states that the “Tailoring Rule” provisions can be triggered by some projects because of the required timing of emission control projects necessary to meet the emission lim its of the proposed rule, thus initiating the GHG BACT analyses requirements during the permitting pr ocess. The commenter states that GHG BACT is a largely unchartered area for both the regulated community and the state regulatory agencies and will likely create a dditional permitting delays. Accordi ng to the commenter, these delays will be exacerbated by challenges to the permits by those seeking to minimize GHG emissions. Commenter recommends the EPA include an exclusi on from the requirements to obtain construction permits, including greenhouse gases under the Tailoring Rule, for emissions controls needed for an existing unit to meet the emission limits of the Utility HAP MACT Rule.461 Commenter 17736 states that a 3-year compliance require ment is not feasible. Co mmenter disagrees that the data proposed in the regula tion is complete and it relied on faulty assumptions and unproven technologies. According to the commenter, comp liance and implementatio n 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 fo r 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 inst allation, if needed, as well as E GU operation so that the requisite emissions demonstration can be completed on time. Shoul d an owner or operator fi nd that despite his or her best effort to meet the compliance date additional time is required to instal l controls, he or she can request up to a 1-year extens ion from the Administrator.

Some commenters thought th at EPA permitting could cause delays in implementing this rule. The EPA recognizes that, following the vacatur of the ne w 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 pr ojects constructed to comply with this rule, have the potential to trigger NSR permitting. Based on an analysis done in 2005 th at looked at SCR and FGD for CAIR compliance, but that remains current and relevant for all pollutants except for GHG, EPA believes that NSR requirements would not significantly impact the constr uction of pollution controls that are installed to comply with this rule. In addi tion, it is very unlikely that pollu tion control projects would cause GHG increases that would exceed the 75,000 tons per year threshold either as a result of either chemically manufacturing GHGs or as a result of parasitic load. The EPA concludes therefor e that there will be no significant impacts on timing from NS R for any pollution control projec ts resulting from this rule. Should NSR be triggered it would at mo st be for just a few of the proj ected control installations. In the limited circumstances where pollution control installa tions 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. Fo r this reason, we strongly encourage permitting authorities to expedite permitting for any such project s, which are likely to be very limited in number.

Some companies may construct replacement generati on as a compliance strategy. State pre-construction permitting requirements depend upon each individual state. Some states do not re quire pre-construction permits while some others require public utility commission (PUC) approval. For states obtaining PUC pre-approval for cost recovery, auth orization typically averages seven months and is obtained usually within one year. 19 Furthermore, while PUC approval is necessary to recover investment costs through rate payers, it is not a prerequisite for obtai ning credit or performi ng 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 easte rn bituminous coals to meet the proposed MACT HCl limits. According to the commenters, the alte rnative control option of FGD cannot be timely installed to meet the proposed comp liance deadline as the EPA admits.

Commenters 17689 and 17886 state that the EPA’s de termination 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 intime 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 assumpti on that DSI with fabric filters will provide compliance-level reductions to meet the very stringent acid gas limits at all units. Without data that demonstrates otherwise, Commenter 17790 expects co mpliance with this proposed rule will require FGD on over 60 percent of coal-fired EGUs.

Commenter 17765 states that the DSI t echnology has not been widely used or tested to date and there is little or no satisfactory evidence which demonstrates that an actual unit can co mply with all of the proposed NESHAP using DSI without a scrubber.

Commenters 17765 and 17820 believe that without furthe r testing to confirm that DSI technology will work without a scrubber, it is highly unlikely an y utility’s compliance strategy will rely only on DSI technology. The lack of experience with th e DSI technology also highlights the problem with setting emissions standards pollutant- by-pollutant, as there is also insu fficient data to confirm whether a unit using DSI with or without a scrubber can meetall three standards on a continuous basis without creating antagonistic impacts to the overall effectiveness of other control technologies.

Commenter 17820 states that to satisfy the HCl em ission limit of 0.002 lb/MMBtu as proposed in the rule, DSI may be a viable option at a reasonable co st for coal with chlorine < 300 ppm. The commenter states that for coal with chlorine between 300 to 1000 ppm, DSI could sti ll be used but variable operating costs will increase substa ntially, while for coal with chlori ne greater than 1500 ppm, removal requirements will be difficult and variable oper ating costs could approach $8-$10/MWh or higher. According to the commenter, some companies that burn certain eastern bituminous coals may not be able to achieve compliance with the acid gas standards using DSI, because the higher chlorine content found in these coals necessitates a more aggressive control technology to remove higher levels of HCl. According to the commenter, to comply, these compan ies may have to install wet FGD, which presents major challenges to the 3-year compliance deadline that the EPA optimistically asserts companies will be able to meet.

Commenter 17820 states that the EPA assumes that an adequate supply of dry sorbents is readily available in the RIA, yet sorbent production would need to increase by 10 to 20 times in order to meet the EPA’s projected DSI demand. The commenter states that it is uncertain wh ether 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 a nd potential problems from DSI use will make companies’ decisions about employing DSI complex and lengthy, and some may be reluctant to take on large take-or-pay obligations. The comment er states that even assuming suppliers are willing to commit hundreds of millions for plant expansions th at may be needed to increase supply, it will still take more than 18 months to ramp up dry sorbent production. The commenter stat es that there are also substantial questions about the Trona supply chai n. According to the commenter, the sole regional supply of Trona from the Green River, Wyoming area takes two to four weeks to deliver, Trona is shipped by rail in sealed pressure di scharge (“PD”) railcars th at typically hold a litt le less than 100 tons of product, and Trona properties and f eed issues limit the size of a plan t’s storage silo to 200 to 300 tons. The commenter asserts that given the space constraint s 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 comm enter states that if rail service is unavailable to a given power plant, then trucking the material to the site may cause add itional logistic problems because of the large number of truck trips needed at substantially increased cost. The commenter also states that material suppliers r ecommend that Trona not be stored for more than one month because longer storage times may diminish the material’s eff ectiveness 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 cost of complying with the proposed MACT limits (because more units will need to install either a more expensive wet or dry scrubb er). 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 adop tion 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 load ing 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 deteri orated performance. The commenter also states that sodium-based sorbents shave acceptable ash resi stivity for applications in ESPs, but under certain conditions sodium bisulfat e is formed. According to the commenter, sodium bisulfate has a sticky phase at temperatures above 330 oF-350 oF, and this sticky phase has caused significant operational problems in a number of units , causing plug gage of systems and components in the gas stream. According to the commenter, under ce rtain conditions, sodium-based sorbents can serve as a catalyst to convert NO to NO 2 . This can cause an orange br own color in the stack plume

b. The commenter states that regard ing fabric filters and DSI, ther e is not a sufficient number of medium-to-high sulfur coal burning units that are equi pped with fabric filters to determine whether they can operate reliably withoutexperiencing degraded bag life from acid attack or H 2 SO 4 dew point corrosion, plug gage and/or blinding. DSI for fabric filter protection is not an industry standard. According to the commenter, there are operational and reliability risks in installing fabric filters on large EGUs burning medium to high sulfur coals. The commenter states that the negative effect of SO 3 from high sulfur coals on ACI fo r 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 filte r, the addition of DSI cause d the unit to need three times the normal amount of ACI to achieve the same leve l 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, sp ecifications completed, and a contra ctor secured before it can actually commence construction. According to the commenter, these steps could easily add several additional months; total project length incl uding these other factors could eas ily be 42 months. The commenter states that in its proposed rule, the EPA has underestim ated or not considered these additional burdens of installing fabric filters, activat ed carbon, and sorbent injection.

c. According to the commenter, companies may need to install other technologi es such as wet FGD, which has an expected implementation time of 52 m onths after necessary permits and other approvals are secured. The commenter states that this point is critical given that the EP A 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, wh ich 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 injecti on rates of Trona at approximately 600 lb/hr, engineering studies have shown HC l removals at less than 20% withvirtually 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 engineer ing data that both dem onstrate compliance level removal rates and document accompanying balance of plant effects; for example, larger alkali injection rates can cause pH upsets in downstream systems and environmental contro ls. 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 i nvestigation on the widespread a pplication of this technology is warranted. According to the commenter, the use of DSI will likely require a fabric filter to avoid NSR and PSD permits. The commenter states that while DSI may be installed in less than three years, engineering, permitting and constructing a fabric filter will, in fact, take longer, and that this concept is further complicated by any need to replace existing ash handling systems in order to accommodate the higher volume of wastes (i.e., fly ash and spent/unspent reagent) associated with DSI.

Several commenters (17756, 17758, 17790) are concerned that the EPA overestimated the number of DSI devices that will be used. Commenters 17758 and 17790 note that units burning eastern bituminous coals may not meet the acid gas standard using DSI; therefore they may use FGD instead.

Commenter 18037 states that the presumption that so rbent injection or dry scrubbing will be installed over wet scrubbing systems implies that the EPA is looki ng solely at this proposed rule and not the suite of rules the electric generating industry will be f acing. According to the commenter, when considering all the rules, wet scrubbers may be the control of choice over dry syst ems and the installation time for wet scrubbers is significantly longer.

Response to Comment 23: As mentioned in the response to comment 17, the agency finds that a number of additional EGUs will choose some form of acid gas control by 2015; should an owner or operator find a particular approach such as DS I unsuitable, he or she could choose from other approaches, including flue gas de sulfurization or fluidized bed co mbustion with reagent injection. Source owners or operators have th e ability to schedule equipment installation, if needed, as well as EGU operation so that the requisi te emissions demonstration can be completed on time. Should an owner or operator find that despite his or her best effort to meet the compliance date additional time is necessary for the installation of c ontrols, he or she can request up to a 1-year extension from the Administrator.

9. Request to modify compliance requirements.

Comment 24: Commenter 17800 requests the EPA to exempt EGUs from the annual tuning requirement in section 63.10021(a)(16 )(iii) and (iv) if such units us e a continuous tu ning algorithm to optimize the air-to-fuel ratio, and minimize NO X and CO production. The commenter states that in section 63.10021(a)(16)(iii) and (iv) the EPA is re quiring the annual inspecti on of systems 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, typically boiler operators use excess O 2 to determine proper combustion; the gene ral indicator of incomplete combustion is high CO levels or unburned carbon in the fly ash, and operators use O 2 set points to insure combustion has been optimized. Currently Commenter uses a neur al network computer system to optimize the boiler combustion and minimize NO X and CO production; this system c ontinually tunes the boiler combustion465 process based on boiler operating parameters. Accord ing 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 al ternate work practice standards, such as a CO requirement, but has adjusted the language in the final rule to recogni ze the value of automated boiler optimization tools such as neural-net syst ems. The EPA has reviewed the comments on the proposed frequency of tune-ups, and made adjustment s 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 a nd that to make this happen, the EGUs need to install observation ports. Commenters request the EPA to exempt them fr om this requirement as inspecting the flame would not provide useful information relative to optimizi ng CO and would be extremely expensive, as tubing in the boiler would have to be re configured to accommodate the port. According to the commenters, in some wall-fired coal boilers, there are observation ports which can be us ed to determine if flames are impinging on the furnace walls. The commenters state that while a qualitative evaluation can be made regarding the general ap pearance of the flames (bright, dark, etc.), observation of the flames is rarely, if ever, used to access the impact on NOx or CO; for in stance, flame observation on cyclone and coal-fired tangential boilers would not generally 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 e ssentially the burner as well, and in the case of a coal-fired tangential boiler, the furnace is filled with a spiraling flame that covers most of the furnace. The commenters state that the EPA has apparently recognized this by requiring that the flame pattern must be inspected “ as applicable .” Nevertheless, Commenters request exemption for those boilers that do not currently have observation ports or it can be shown that observation of the flames in these boilers provides no useful inform ation relative to minimizing CO.

Response to Comment 25: The EPA has modified the rule to st ate that if specific aspects of the inspection process are not applicable to a given boile r type, then those elements of the basic procedure would be adjusted according to best combusti on engineering practice for that burner type.

Comment 26: Commenter 17818 states that for compliance, itappears that the alternate limit in this case (of alternate Hg limits) woul d require both a simultaneous signi ficant emissions reduction to the levels of the primary limits and a significant reducti on in unit heat rate [when an Hg emission rate limit of 1.0 lb/TBtu or 0.008 lb/GWh and the apparent corre ction factor (unit heat rate) of 8000 BTU/KWh is applied]. According to the commenter, this scenar io seems unlikely for most owners and operators.

Response to Comment 26: Conversion errors made in the proposed limits were brought to our attention and corrected. We believe that the final limits do not contain the issues noted by commenter.

Comment 27: Commenter 17821 states that existing IG CC units should be able to use SO 2 as a surrogate for acid gases (e.g., HCl) as analternative 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 coalfired 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 ex ists and states that as an example, General Electric’s gasification technology, currently bei ng installed at the Edwards port IGCC, uses water scrubbing of466 syngas at high temperatures which removes water so luble acid gas compounds such as HCl, HCN, HF, and Cl 2 . The commenter states that the emission contro ls for the Wabash River and Polk Station IGCC units have their own variations, wh ich are distinctively different fr om conventional coal-fired units. Commenter proposes that new a nd existing IGCC units should ha ve 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 ha s based such limits on the two operating IGCCs.

Comment 28: Commenter 17881 states that to measure the ma ss flow of air and fuel to maintain a desired ‘ratio’ does not work. The commenter states that facilities will periodically calibrate flow transmitters on the air measurement system and coal feeders on some plants, and boiler firing controls are based on maintaining boiler drum pressure and trim air in order to maintain a desired excess O 2 leaving the boiler; enough coal is put in to combus t and maintain pressure, and enough air is put in until a desired excess oxygen is achieved l eaving the boiler. The commenter st ates that coal properties vary greatly (heating content and moisture), so coal f eed rates at a desired lo ad can vary greatly, and consequently, the mass of air entering the boiler varies greatly.

Response to Comment 28: The EPA recognizes the inherent diffi culties 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 perf orm necessary MRR compliance demons tration tasks that are required on a daily, weekly, monthly, quarterly and semi-annual basis. According to the commenter, this does not include the external resources and costs associated with stack testing or fuel analyses. The commenter states that these MRR requirements are duplicat ive 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 significan tly reduce the issues raised by the commenter.

Comment 30: Commenter 17914 states that while many of the proposed provisions of the rule are technically achievable, there are some limits which are not sustainable in da y-in/day-out operation at EGUs which face a complex mix of fuel variabilit y, combustion management, turbine integration and Air Quality Control Systems(AQCS) performance op timization challenges and constraints. Commenter requests that the EPA reconsider se veral aspects of the rule, which as proposed would severely hinder reliable, long-term operation of th ese key assets in our nation’s en ergy infrastructure and seriously jeopardize the addition of new, mo re 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 re sponse to other comments in the final rule record.

Comment 31: Commenter 17930 states that the EPA has pr ovided 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 de liver results that even approach the degree of control or consistency that the EPA claims. Using th e same ACI control technology to the fullest extent, and operated in the same manner, over multiple units, Commenter has experienced mercury emissions reductions ranging from 30 percent to 80 percent - far below the EPA’s predicted reductions of over 90467 percent and nowhere close to the co nsistency that would justify setting a limit such as that proposed by the EPA.

Commenter 18498 disagrees with the EP A proposal not to use technologie s other than ACI as the basis for a beyond-the-floor analysis rela ted 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. A ccording 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 ad ditional options that w ould allow for compliance while protecting grid reliability a nd reducing retrofit costs passed to c onsumers; for example, a viable option would allow a facility to oper ate at a reduced capacity factor rath er than being required to retire or achieve the standards in the proposed rule. The co mmenter states that allowi ng a facility to adopt a capacity factor of 10 percent or le ss would achieve the desired resultof reducing emissions but would not place the EPA in the position of dictating energy generation profiles and that such an option would help ensure reserve capacity for the grid and at the same time reduce emi ssions. According to the commenter, the EPA has set a standard that will be difficult for sources to comply with using technology the EPA has recommended in the proposed rule. For example, states the commenter, using DSI technology to meet the acid gas HAP emission limits actually makes it more diffi cult to comply with the PM emission limits because the dry sorbent inject ed into the flue gas stream reacts with SO 2 , creating sodium sulfate, a particulate that must be captured by the PM contro l device in addition to the other particulates in the flue gas stream. Commenter s uggests that the EPA revise its proposal and set a new MACT floor based on the best performing 12 pe rcent of units overall, rather than the best performing 12 percent of units fo r 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 predicti on 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 ma ny instances in ponds. The commenter st ates that where a base is added to the pond, the water will necessarily have to be treated with an acid to decrease the pH in the pond; at this time, there is insufficient information to know e ither 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 appr opriate 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 we re also using ACI, in combination with the publically available information from the DOE/NETL mercury control de monstration program, supports that consistent mercury removal levels > 90% are achievable when th e correct sorbent is prope rly used (i.e., injected corrected and at the correct rate ). The EPA understands and acknowle dges that contro l 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 technolo gy (such as ACI). The comments on the pollutant-bypollutant approach have been addressed else where in the response to comments document.

Comment 32: Commenter 17702 states that the EPA’s propos ed compliance requirements are overly burdensome and should be modified. According to the commenter, some of the compliance requirements may result in periods of noncompliance by EGUs that may be capable of complying with the emission limits under normal operations.468 Response to Comment 32: The final rule makes a number of changes to streamline the compliance requirements. Please see the final preamble for further discussion.

10. Need clarification on output-based limitations.

Comment 33: Commenter 17385 states that Tables 1 and 2 of the NESHAP list output-based limitations in units of mass of pollutant per electrical output (lb pe r 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 NE SHAP 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 sp ecify gross generation.

11. Improve sustainable efficiency.

Comment 34: Commenter 17620 states that the EPA should develop a record in the upcoming EGU GHG regulations that would enable accurate measurem ent 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 outsi de the scope of this rulemaking.

12. Support work practice standards.

Comment 35: Commenter 17790 supports the use of work practices standards included in the proposed EGU MACT to ensure compliance with th e proposed organic HAP. Co mmenter 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 expensiv e and because of the low levels, results can be unreliable. According to the commenter, prope r combustion will ensure low emissions of organic HAP and requiring proper combusti on is the best means of control.

Response to Comment 35: The EPA acknowledges the support and has retained in the final rule a work practice standard for organic HAP emissions.

13. Request to modify or remove work practice standards.

Comment 36: Commenters 17638 and 17818 request that the EPA establish a wo rk 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 th e 18-month work practice inte rval 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 in stall scaffolding in the furnace, to gain access to the burners, and then rem oval of the scaffolding. According to the commenter, this is a process that is both expensive and time c onsuming, as well as generall y not required except to perform burner inspections or perform repairs, and such activities are genera lly not done on an annual basis, but rather are less frequently perf ormed during periods of extended maintenance shutdown/inspection. Commenters proposed that the 18-month maximum outage interval should be extended to 24-30 months and the inspection of flame patterns for EGUs for the purpose of tuning burners is improper. EGUs can have 50 or more t ypes of burners, and not all flames are visible.469 Inspecting flame patterns is more useful for indus trial boiler practices in which an observer peers through a glass at the burner and then makes changes to nearby controls to optimize the flame. Commenter 17638 supports a CAM-type approach regard ing the establishment of work practices, which provide for reasonable assurance of the unit operation in lieu of a “one size fits all” approach.

Several commenters (17689, 17756, 17928, 17813) state that the 18-month interval between inspections is not consistent with establishe d utility practice regarding periodic outages for mainte nance and repair. Commenters recommend a 36 month compliance period. According to the commenters, utilities should be able to implement their own best management prac tices if they are demonstrated to be best for the unit. For small systems, such as many rural electr ic cooperatives, state the commenters, many parts may not be inventoried and may take several months to acquire, and to complicate matters, units may be in periods of high need, such as during summer or winter peaking when replacement parts become unavailable, thus making shutdown for repair not feasible due to reliab ility or other paramount concerns. In such cases, commenter 17689 believes utilities should be given reasonable time to optimize considering the electric demands on the system.

Commenter 17756 states that the work practice sta ndards for EGUs to address any emissions of organic HAP and dioxins do not reflect some of the practical realities of operating an EGU.

Several commenters (17761, 17767, 17795) state that the proposed work practice standards regarding organic HAP will have a detrimental impact on the outage schedules of applicable units since every unit would have to perform an onerous inspection and tune-up every 18 months. According to the commenters, this scheduled tune -up would require additional outag es in between planned major maintenance overhauls further affec ting unit availability, overall system reliability, and generating costs. The commenters state that the EPA’s ICR test data de monstrated that the majority of applicable units emitted non-detectable levels of or ganic HAP, even under the utility industry’s existing work practice standards and maintenan ce outage cycles. Commenters 17761 and 17795 suggest that there is no need for increased scheduled outages and inspections (every 18 months) for units already emitting nondetectable levels of these HAP and, as such, thes e standards should be rem oved from the final rule. Commenter 17767 recommends an extension beyond 18 months.

Commenter 17851 states that the EPA should not set a dioxin/furan standard or a non-dioxin organic HAP standard. Doing so will not reduce the emissions of organic HAP.

Commenter 17851 states that the EPA should not set a dioxin/furan standard or a non-dioxin organic HAP standard and that doing so will not reduce the emissions of organic HAP.

Commenter 17930 states that the EPA should allow u tilities to document their own operating practices, including testing, data collection, and inspection schedules. According to the commenter, each utility has developed documentation practices that best, and most efficiently, serve th at particular plant and company and to require other documentation practices would be an unnecessary burden on already taxed utility operators. The commenter states that there are many instances where emissions are below detection levels and should not be used as a basis to establish a work-practice standard.

Several commenters (19536, 19537, 19538) stat es that the work practice sta ndard should require that all EGUs install real-time software to continuously optimize boiler combustion and perform soot cleaning. According to the commenter, these systems continuous ly monitor the combusti on process to determine the optimal balance of fuel and air flows in the furnace to position dampers, burner tilts, overfire air and other controllable parameters at their optimal setting. The commenter states that these systems are470 already in widespread use thr oughout the utility industry and have the added benefit of improving efficiency, thus reducing operating costs. According to the commenter, a boiler tune-up is not adequate to assure continuous minimization of organic HAP . The commenter asserts that the work practice standard assumes that all organic HAP are created by incomplete combus tion and that this assumption is incorrect, especially for dioxins which are formed after the combustion process and whose emission rate depends in part of coal chlorine content.

Response to Comment 36: The EPA has reviewed the comments on the proposed frequency of tuneups, and made adjustments in the final rule. Under th e final rule, the tune-up must be conducted at each planned major outage and in no event less frequently than every 36 months , with an exception that if the unit employs a neural-network system for co mbustion optimization dur ing hours of normal unit operation, the required frequency is a minimum of on ce every 4 years (48 months). The EPA believes the minimal recordkeeping associated with this wo rk practice standard is not unduly burdensome. The EPA does believe that a work practic e standard is the best approach for controlling organic HAP, and thus has retained the work pract ice standard in the final rule.

14. Delegation to states (compliance dates).

a. General support.

Comment 37: Commenters 17758 and 17909 indicat e that allowing states to seek delegation of the section 112 program will provide important compliance flexibility (particularly related to timing of retirements, repowerings, and instal lations of control equipment) for those units and utilities that have already made investments consistent with state en vironmental programs, and failure to allow state delegations could undermine these i nvestments. Commenter 17758 further indicates that if states can demonstrate that overall emissions reductions are equivale nt or greater than those that would be achieved by the proposed rule, the EPA should delegate the section 112 program to these states, even if the state emissions reductions would not necessarily occur on the same schedule.

Commenter 17798 states that the EPA needs to be awar e that states with existing Hg rules may request approval of their rules in meeting the EGU NESH AP. According to the commenter, to this point, Wisconsin, under state statute, is re quired to establish state rules fo r implementing any federal NESHAP requirement. Commenter requests the EPA to include a process in the NESHAP rule which will facilitate states in establishing rules as equivalent to the EGU NE SHAP. For Hg emissions and other accumulative impact pollutants, the commenter sugge sts equivalency can be measured by comparing total emissions on a statewide or corporate utility basis.

Commenter 17719 is concerned about ex isting sources subject to state-onl y rules for the reduction of Hg and other air toxic emissions. Co mmenter does not want the promul gation 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 econo mic viability of the st ate and the health of the public. Commenter seeks to make use of temporal flexibility, au thorized under CAA sec tion 112(i)(3) in obtaining delegation of the MATS to preserve a hard ne gotiated comprehensive Colorado-specific program designed to yield greater emission re ductions than the MATS alone. The commenter states that the state has taken three separate actions to reduce the emissi ons of criteria pollutants and HAP from coal-fired utility boilers.471 a. The Colorado Air Quality Control Commission (AQ CC) adopted state-only Standards of Performance for Coal-Fired Electric Steam Generating Units into Regulation No. 6, Part B, Section VIII on October 18, 2007;

b. The Colorado Legislature passed House Bill 10-1365, the “Clean Air-Clean Jobs Act” (“CACJA”), on April 19, 2010; and

c. The AQCC adopted revisions to the Regional Haze State Implementation Plan (“RH SIP”) in Regulation No. 3, Part F on January 7, 2011.

According to the commenter, under these rules, th e state has successfully negotiated both emissions standards and shut down provisions with Colorado utilities to reduc e 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 cleane r energy sources, taking into consideration cost impact to customers, necessary transmission sy stem changes, unit outage schedules and outage contingencies, and construction timeframes, and th at ultimately, the CACJA will promote job growth and reduce air emissions within the State.

Commenter 18034 states that the stat e agencies that receive delegate d authority for the final NESHAP rule will be tasked with enforcing the rule. According to the commenter, some of the issues will directly impact its ability to appropriately enforce the rule, and the EPA must consider how state agencies will be expected to enforce the rule.

Comment 38 : Several Commenters (17758, 17873, 17756) state that the EPA should allow states to seek delegation of the CAA section 112 program, as authorized by the Act. S ection 112(l) of the CAA allows a state to seek delegation of the section 11 2 program. The commenters note that in the proposed rule the EPA acknowledges that a number of st ate and local program have plans to address environmental issues and that these plans may lead to reductions in HAP emissions equivalent to or greater than the proposed rule.

b. Support for specific state/local or EGU.

Comment 39: Commenter 18019 states that they encourage the EPA in the final MACT rule to make clear that Oregon has regulatory flexibility to ad dress the unique Boardman case. In particular, the commenter asks the EPA to expressly recognize th at Oregon could obtain de legated authority under section 112(1) to implement the MACT consistent with the Boardman 2020 plan, where the plant will achieve mercury reductions both ahead of and in exce ss of any federal standar d, meet the acid gas and organics standards in advance of the MACT re quirements, and cease coal burning entirely by 2020. Commenter urges the EPA to expand on this concept in th e final rule and make clear that plans, such as the Boardman 2020 plan, coupled with the early merc ury reductions, would meet the “no less stringent” test for state delegated programs.

Comment 40: Commenter 17867 states that early termination of coal operations and interim controls will result in lower aggregate emissions of haze ca using 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 st andards. According to the commenter, the EPA’s proposed Utility NESHAP Rule is one of several the EPA rule s that will affect the nation’s coal fleet, including the Boardman facility. The comment er states that the Boardman plan requires Commenter to install472 pollution 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 DSI system. According to the comment er, under the Boardman 2020 plan, all emissions associated with coal-firing at the Bo ardman Plant will end by 2020, resulting in dramatic reductions in all conv entional pollutants (SO 2 , NO X , PM), Hg, other HAP, and GHGs. In addition, the Boardman 2020 Plan establishes a pathtoward 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 regulat ions would require polluti on upgrades in order to meet air quality, water quality or waste manageme nt requirements, and on ce these regulations are finalized, a key question facing electric utility companies is whether to re trofit 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 reso lve this dilemma by establishing a clear regulatory pathway that allows the state to pr eserve 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 containi ng the following elements, that if offered by the ODEQ in connection with other elements needed for compliance assurance, would be considered by the EPA as potentially meeting the equivalency requirements of section 112 and subpart E:

a. A Hg standard more stringent and imposed earlier than the federal rule. The commenter states that the Oregon Utility Mercury rule was pr omulgated in 2006 and requires Boar dman to meet an aggressive standard of removal of at least 90 percent of the Hg emitted from the unit or a limit of Hg emissions to 0.60 pounds per trillion BTU of heat i nput by no later than July of 2012; thus, Boardman would achieve Hg controls that are well below th e EGU MACT proposed limits and have them installed at least 3 years early.

b. An acid gas standard the same as, or more stri ngent than, the proposed fe deral 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 us e of low sulfur coal; while inst allation has not been completed, and full scale testing to determine control effec tiveness 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 standa rd 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. Th e commenter states that th is might be either the existing PM emission limit of 0.04 lb /MMBtu (filterable) as a surrogate for non-Hg metals or slightly relaxed individual or total metals limits. According to the commenter, while Oregon potentially could allow marginally higher emissions than the federal standard, the Oregon plan would require complete phase out of fossil fuels by 2020, which would result in significantly lower aggregate non-Hg metal emissions compared to continued operation in compliance with the MACT standard under the EGU NESHAP proposal.

e. A requirement that coal firing at Boardman be stopped by 2020, which would result in of the dramatic reduction in all HAP and other pollutants. Commenter believes such a set of requirements, which would contain some elements that are more stringent than the federal rule and others that are slightly less stringent, would – taken as a whole – be at least as stringent as the proposed federal rule. According to the commenter, given that delegations to date have been based on state regulati ons that are essentially473 identical to the federal rules or co ntain more stringent requirements for particular pollutants (e.g., Hg), the EPA has not had an opportunity to provide the public with an analysis of whether an alternative state program may allow emissions for individual pollu tants 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 fo r the EPA to address this aspect of its delegation authority and provide guidance to the states regardi ng their demonstrati on of equivalency.

Commenter 18019 states that under “Boardman 2020” pl an, PGE will install pollution controls to reduce interim emissions of nitrogen oxides by about 50 per cent 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 commente r states that IRP in Or egon is a rigorous process for examining how to meet customer needs at the lowe st 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 environm ental costs that may be incurred.

Comment 41 : Commenter 17867 states that the EPA shoul d clarify that States may demonstrate equivalency with the EGU MACT through alternative regulation that achieves in aggregate emissions outcomes that are equivalent to the NESHAPs. Specifically, the comm enter requests the EPA to confirm that Oregon has flexibility to us e its Mercury Rule and the Boardm an 2020 Plan to address federal Regional Haze requirements as th e foundation for a delegated program. The commenter states that section 112(l) of the CAA, and the correspondin g implementation regulations at 40 CFR Part 60, Subpart E, provide that each state may devel op and submit to the Admi nistrator 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 alte rnatives must be holistically equiva lent to the Federal requirements. Commenter urges the EPA to make clear that a stat e-implemented rule for coal units that includes steeper and/or earlier emission reduc tions of some pollutants (e.g., Hg ), identical emission limits for other pollutants (e.g., acid gases) , and marginally less aggressive emission reductions for some pollutants (e.g., non-Hg metals or PM), plus a commitment to early ce ssation of coal firing, along with the necessary work practice standards and elements necessary for compliance assurance, may be considered by EPA as no less stringent, i.e., “e quivalent,” to the proposed utility NESHAP rule.

c. Concerns over delegation.

Comment 42 : Commenter 17648 states that in response to request for comments on whether EPA would be authorized to delegate the section 112 pr ogram to states enforcing laws related to EGU emissions and HAP reductions where the program resu lts in greater emission reductions than the EGU MACT but allows a compliance time extending be yond the statutory three year maximum such delegation would “not [be] appropria te 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 prog ram with more lenient deadlines.”

d. Implementation.

Comment 43: Commenter 16859 requests that the EPA conc urrently publish implementation guidance for this rule to states at the time of new rule issu ance. According to the commenter, timely issuance of implementation guidance would facilit ate state adoption of the new rule as well as increase state and EPA staff resource efficiency in completi ng activities related to new rule adoption.474 Response to Comments 37 - 43: Responses to these comments are provided in the preamble to the final rule.

15. Need option for percent reduction or increase compliance averaging time.

Comment 44: Commenter 17737 requests that pe rcent reduction should be available as an alternate to a numerical emission rate a nd could be established to be based on percent reduction from the boiler inlet Hg concentration in a manner sim ilar to the procedure under 40 CFR 60 subpart Da. According to the commenter, the percent reduction could be set at 91 percent, which is th e 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-m outh configuration, or boiler design. If the Hg coal concentration increases over time, Commenter may not be able to meet the standard with available technology and could be faced with curtailment as the sole compliance option but that this concern could be somewhat alleviated if the compliance averaging time were to be on a 12-month rolling basis.

Commenter 17737 states that ICR data shows some E GUs would achieve a lower emission rate with 75- 85 percent removal than others with removal rate inexcess of 91 percent. According to the commenter, by not including a percent removal, the EPA is penali zing those EGUs that are not able to obtain coals with relatively low Hg content.

Commenter 17737 states that the EPA’ s primary rationale for not allowing the percent reduction option is that it may discourage or complicate the use of coal washing as a comp liance technology. According to the commenter, this would only be the case if the EPA elected to adopt a perc ent removal standard in lieu of a numerical limit.

Response to Comment 44: We have addressed comments rela ted to a percent reduction format elsewhere in the final rule record.

16. Cannot meet mercury emission rate on continuous basis.

Comment 45: Commenter 17761 states that after a case-by-ca se 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 fac ility has demonstrated significant variability in Hg emissions. The commenter states that operating and monitoring experience with Hg emissions at their EGU suggests that ACI performance is also highly variable and subject to decline based on a number of factors which may necessitate the use of additional solutions to achieve the expected performance criteria. According to the co mmenter, the inherently low chlorine content of their coal will make it extremely difficult for well-controlled units that utilize their co al to meet the proposed rule’s 1.2 lb/TBtu Hg emission rate on a c ontinuous basis. The comm enter 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 temperatur e, pressure drop, ammonia slip, S CR catalyst degradation, etc.) or outside the utility’s contro l (e.g., variability of Hg and chlorine c ontent 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 fo r variability. As demonstrated by contemporaneous data collected by EGU owners or operators and submitted to the Ad ministrator, approximately 180 EGUs are currently475 meeting the Hg standard contained inthe final rule. To the extent a pa rticular owner or operator believes his EGU’s Hg emissions are too high, he can and shoul d take advantage of the three year period before compliance is required to find one or a combination of mercury-reducing approaches that will enable the EGU to meet the Hg emissions limit.

17. Allow portable monitoring equipment.

Comment 46: Commenter 17740 requests the EPA to permit s ources to measure concentrations of CO and NO X in the effluent stream before and after ad justments with portable monitoring equipment. According to the commenter, industry practice is to use portable analyzers located at the boiler outlet duct to measure CO and NO X during combustion tuning operations.

Response to Comment 46: The EPA agrees with the comment and has modified the rule to allow portable emissions monitoring equipment as acceptable for meeting this requirement.

18. General clarifications needed.

Comment 47: Commenter 17740 states that the EPA should clarify the time ranges listed in 40 CFR section 63.10006(n). The commenter st ates that the proposed ranges ar e specified in terms of days, months and years, and that it is unclear whether the EPA is referri ng to calendar or operating days. Commenter recommends that the EP A adopt operating days or operating quarters. The commenter states that these terms are used routinely by utilit ies to manage emissions program schedules.

Commenter 19033 states that Table 3 of the the propos ed regulation conflicts w ith 63.1 0006(o) and (p). 63.10006 provides that less frequent te sting than annual may be perfor med, if the crite ria in 63.10006(o) and (p) are met, whereas Table 3 re quires that annual testin g be performed for existing EGUs. To correct this conflict, Commenter 19033 recommends thatTable 3 be amended for existing EGUs.

Response to Comment 47: The agency reviewed the commenters’ concerns, clarif ied in section 63.10006(g) that calendar days are the appropriate m easurement between stack tests, and corrected Table 3 in the final rule. The agen cy finds periodic stack testing based on a time period other than calendar days would be confusing for not only the owne r or operator but also the agency and the public. Note that the cited table was inte nded to refer to the annual performa nce tune-up in the proposed rule. Under the final rule, this has been clarified and the periodic frequency for conducting the tune-up has been modified. See discussion in the preamble.

19. Opposition to the EPA regulation.

Comment 48: Commenter 17768 states that citing the justific ation for an emissions averaging decision that was provided in a 16-year old rulemaking is insufficient.

Comment 49: Commenter 18477 states that Hawaii’s R PS has two significant ramifications for commenter’s ability to comply with the proposed ru le: first, modification of a large percentage of commenter’s generation fleet to us e 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 cu rrent resource plans indicate the re tirement of at least four EGUs with relatively low capacity factors within eight to ten years. According to the commenter, installation476 of costly control technol ogy on these units to comply with the E GU MACT for the relatively short time frame before retirement would also represent significant economic inefficiency. Commenter estimates that installation of emission control equipment for Hg, HCl, HF, and PM would cost at least $696 million, based on preliminary quotes provided by e ngineering consultants and equipment vendors. According to the commenter, to date, no control e quipment vendor will provide performance guarantees, so this cost estimate does not address the risk associ ated with failure to comp ly with the proposed HAP emission limits. The commenter states that it is extremely difficult for companies to develop a costeffective compliance plan wit hout control equipment vendor gua rantees. Vendor guarantees allow companies to plan for prudent capital investment s 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 inve stments. Accordingly, Commenter urges the EPA to exercise its discreti on and establish work practice standards for noncontinental liquid oil-fired units.

Comment 50: Commenter 17805 states that it is inappropriate for the EPA to require utilit ies to expand energy efficiency and demand response programs as analternative to replacing retired generation when retrofits are uneconomical. The commenter stat es that based on their resource modeling, the effectiveness and long-term viability of these programs are ultimately dependent on customer participation. According to the commenter, de mand response and energy efficiency programs are typically more suited to be replacements for peaking type generation resources th an traditional base load generation.

Response to Comment 48 - 50: The EPA disagrees that establishe d precedent, can and should not be used as justification for actions within this rulema king. As noted elsewhere in this document, we have established a subcategory for non-c ontinental liquid oil-fired EGUs inthe 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: Emission Impacts

Commenters : 17174, 17385, 17620, 17689, 17768, 18932

Comment 1: Commenter 17174 asks that the EPA take into c onsideration the effect of the proposed rule on non-HAP pollutants and the overall air quality and pub lic health improvement to avoid exacerbating air quality issues.

Response to Comment 1 : The EPA has determined that the propos ed rule will lead to reductions of criteria and HAP responsible for significant adverse health effects and that su ch reductions will produce substantial public health benefits. Accounting for ancillary impacts is standard practice in benefit-cost assessment since these benefits are a consequence of the rule, regardless of th e 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-ben efits have been included in th e regulatory impact assessment.

Comment 2 : Commenter 17385 asks that the EPA perform additional energy efficiency sensitivity analyses incorporating additional policies. The co mmenter is pleased with the Integrated Planning Model (IPM) analysis of demand-side energy effici ency impacts on moderating electricity demand and reducing compliance costs. The IPM performed for the proposed rule included only federal appliance standards and utility demand side management program s. The commenter points out that there are other efficiency programs that could be factored in, such as building code s, tax incentives, state and local
programs.

Response to Comment 2 : The EPA recognizes that the energy effi ciency sensitivity conducted does not represent the full array of ongoing policies in this ar ea. The scenario does, howev er, illustrate in detail the impacts of two of the more significant policy type s that are leading to incr eased investment in enduse efficiency: ratepayer-funded programs and fede ral appliance standards. These policies are not otherwise represented, for the most part, in the ba seline electricity demand forecast from EIA that is used in the EPA’s modeling. Building codes and tax in centives may be accounted for to a greater degree in the EIA forecast.

Comment 3: Commenter 17620 argues that although the prop osed rule would reduce Hg emissions so that on average the remaining emi ssions could be approximately 45 lb /unit, emissions of 22 lb/yr/unit cannot be considered trivial or “de mimimis.”

Response to Comment 3 : The EPA disagrees with the comment er’s notion that the goal of the technology-based phase of regulation under CAA section 112 is to reduce em issions to levels that can be considered trivial or “ de minimis .” In fact, there is no such goal de scribed in all of CAA section 112 and today’s rule complies with the requi rements of section 112(d) to establ ish technological standards based on what has been achieved in practice by the best performing sources in the category. If the commenter is actually commenting on whether the proposed regula tion will adequately protect public health or not, under the requirements of CAA section 112(f), within 8 years after promulgation of this rule, the EPA will determine whether additional regulations are nece ssary to further limit HAP emissions from EGUs to protect public health withan ample margin of safety.

Comment 4 : Commenter 17689 reports that generating and transmission cooperativ es provide 41% of all distribution cooperative electric generation needs, of which 80% is coal-fired. The commenter also478 states that 50% of this coal-fired equipment wa s 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 a ll of the equipment has low NO X burner technology, making the aggregate cooperative co al-fired generation newer and bett er controlled than the overall electric utility sector.

Response to Comment 4: Existing pollution control technologies are available for EGUs to comply with MATS, including controls th at reduce Hg, non-Hg metal and and particulates, and acid gas HAP, including HCl.

Comment 5 : Commenter 17768 states that the rule is justif ied based on the co-benef its that stem largely from PM reductions which represent the majority of total quantified and monetized benefits. The commenter argues that is important to account for such co-benefits or ancillary benefits because they are just as significant as countervailing risks and theyhelp to justify the cost-benefit analysis 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 be nefits 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 regu latory action, to the ex tent feasible, for the purpose of determining the likely impacts, not to jus tify 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 cobenefits are thus an important category to quantify.

Comment 6: Commenter 18932 cites that in 2005 EGUs we re responsible for 47% of anthropogenic cobalt emissions in the US. The commenter then cite s 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 ye ars after promulgation of this rule, the EPA will determine whether additional regulati ons are necessary to further limit emissions of cobalt (or any other HAP) to protect public health withan ample margin of safety.

Comment 7: Commenter 17627 states that the 2005 base ye ar did not include emission reductions that have already occurred as a result of many enforc eable federal and state pr ograms. 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 fr om 2005. Therefore, to achieve reasonably accurate estimates of benefits, the most important feature of the EPA’s approach is having an accurate projection from 2005 to 2016, so that the emissions reductions and economic downturn referenced by the commenter are included in the future base and therefore not included as part of the benefits of the rule. Th ese impacts are included in both th e 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 a nd 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 pr oposal were updated to reflect the co mment process on the Cross-State Air479 Pollution Rule (CSAPR), for which number eastern states provided detailed updates to the EPA’s emissions projection assumptions for EGU, non-E GU point, stationary area, and non-road mobile sources. All of these comments were included in the pr ojections 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 es timates. 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 th e time the datasets were created. This included the use of Annual Energy Outlook (AEO) of 2010 data inthe EGU projections. Ot her updates to point sources included the incorporation of all known controls in the 2016 ba seline, and the inclusion of nonEGU plant closures, federally enforceable emissions re ductions, and consent decrees that have happened since 2005. Finally, while the EPA has attempted to provi de 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 dict ates that these units be retired. The commenter states that the EPA’s claim that compliance options to reduce criteria pollutant s would not have HAP reductions lacks evidentiary foundation. Further, HAP emissions by EGUs have yet to be linked to a cognizable hazard.

Response to Comment 1 : The EPA disagrees with the commenter ’s assertions regarding the motives underlying MATS and the lack of a linkage between HAP emissions by EGUs and public health hazards. The EPA’s full statement found in the preamble to the proposed rule does not imply that the EPA encourages or requires EGUs to retire ra ther than install control equipment but, rather, simply observes that if companies choose to retire the units, it is unlikely to have notable impacts on electricity grid reliability (as shown by EPA analysis). EPA di d not state that compliance options for criteria pollutants will not reduce HAP emissions as comme nter suggest, only that there may be compliance options (e.g. purchasing allowances in a tradi ng program) which may not lead to HAP emission 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 fo r reductions in emissions that have occurred since 2000, and for other expected cont inuing reductions driven by state and other CAA requirements. The commenter discu sses 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 nearly 50% of the coal-fired capacity in Texas has FGD systems. The commenter also poi nts 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 by ot her requirements of the CAA, and the EPA has done so in the technical analyses accompanying this final rule. As documented in multiple technical support documents supporti ng the final rule, the EPA acknowle dges that emissions from U.S. EGUs and other sources would be less than previous years due to controls app lied to comply with other EPA regulations. It is standard practice for the EPA to include these emi ssion reductions achieved through promulgated regulations, settlements, consent de crees, and closures in the baseline for future year analyses. Because the CSAPR has significant impacts on emissions from U.S. EGUs, the EPA specifically accounted for CSAPR in the baseline. As such, the EPA has accounted for emissions reductions since 2000 in the anal yses supporting the “Appropriate and Necessary” finding, as the commenter suggests. Future year emissions modeling conducted for the final RIA was updated to reflect the most recently available information, and incor porates comments submitted to the docket in response to the proposed rule.

Comment 3: The U.S. relies on coal-fired generation for abou t half of its electric ity. It should be taken into account that the U.S. power sector has reduced air emissions s ubstantially under existing programs. The industry has cut SO 2 and NO X emissions by 57% since 1980. Mercury has been cut by 40%. This has occurred while electricity use has increased by 85% and electricity from co al generating facilities has tripled. The industry has made significant strides to reduce emi ssions. Derailing such efforts by piling on additional regulations that many coal- and oi l-fired facilities are not able to comply with undermines all this hard work. No t only does the proposed Utility MA CT rule in its current form481 threaten existing generating facilities, it threatens futu re development of an integral part of our energy portfolio. Please withdr aw this proposal.

Response to Comment 3: This regulation does not conflict or interfere with efforts cited by the commenter, but rather builds on them by requiring that coal-fired power plants control highly toxic HAP emissions to a level that is cu rrently being achieved by the best performing EGUs. These levels of control can be achieved with the application of widelyavailable cost effective pollution control equipment and practices. Doing so will save thousa nds of lives and avoid hundreds of thousands of cases of illnesses including asthma attacks and other respiratory symptoms in children.

Comment 4 : Commenter 18037 believes the use of base y ear 2005 overstates emission reductions from the proposed rule because it ignores the additional reductions reali zed between 2005 and the present. The commenter also suggests the future emission s are erroneous because they are based on 2010 NODA that have since been updated. Fina lly, the commenter states that th e economic downturn that began in 2008 further reduces actual emissions, making the bene fits 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 fr om 2005. Therefore, to achieve reasonably accurate estimates of benefits, the most important feature of the EPA’s approach is having an accurate projection from 2005 to 2016, so that the emissions reductions and economic downturn referenced by the commenter are included in the future base and therefore not included as part of the benefits of the rule. Th ese impacts are included in both th e 2016 baseline and the 2016 policy case and therefore are not captured as benefits of the rule.

As discussed in the preamble to today’s rule and supporting materials, the EPA diligently included the emissions reductions that have o ccurred from 2005 to present and the final modeling done for the RIA for this rule is the best available national informa tion to reflect reductions in emissions that have occurred from 2005 to present. The data used at proposal were updated to re flect 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, stati onary area, and non-road mobile sources. All of these comments were included in the proj ections 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 projecti ons. Other updates to poi nt sources included the incorporation of all known contro ls in the 2016 baseline, and the in clusion of non-EGU plant closures, federally enforceable emissions reductions, and cons ent decrees that have happened since 2005. Benefits of the rule are based on emissions reductions projected by IPM modeling to occur in 2016. These projections are based on demand assumptions in 2016 consistent with AEO 2010. The EPA thus disagrees with commenter, and maintains that bene fits are not overstated as a result of the economic downturn. See IPM documentation Chapter 3 fo r further details on electricity demand.

Comment 5 : Commenter 18428 discusses well-controlled facilities which have installed control technology that reduces their emissions to area so urce levels. The commenter believes that applying generally achievable control techno logy (GACT) to these f acilities recognizes th e investment already made.

Response to Comment 5: The EPA has addressed comments relati ng to area sources 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 only electrical output , which fails to account for thermal energy produced and used by cogeneration units. The commenter points out that combined heat and power (CHP) and waste heat recovery (WHR) units provide em ission-free electricity and effici ent heat, making a CHP twice as efficient as traditional power ge neration and WHR able to produce em ission-free power from heat that would have been vented. The commenter provides a fi gure showing that as much as 63% of total energy inputs are lost as wasted heat w ith conventional generation so the ru le should incentivize CHP and WHR projects by modifying the output-based emissions limits to account for both thermal and electric generation.

Response to Comment 6 : The final rule provides 75% credit for thermal output in the definition of “gross output” (this is the value th at was proposed). This value has b een 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 proj ection that Polk Power Station Unit 1 CA and Unit 1 CT, which use the IGCC process, would requir e installation of fabric filters as a result of the proposed rule. The commenter claims that the IGCC pr ocess is extremely effective for the removal of PM and that the fabric filter woul d not be warranted. The commenter re quests that the EPA perform an additional review of the modeling pro cess and consider that fabric filte rs 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 ar e not a feasible technology for the IGCC process. Final IPM modeling does not reflect th e addition of a fabric filter to IGCC units.

Comment 8 : Commenter 17916 supports the proposed rule b ecause 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 transbounda ry air pollution.

Response to Comment 8 : The EPA thanks the commenter for their support.

Comment 9 : Commenter 18425 supports the compliance schedule of the proposed rule because reductions in Hg emissions from Wisconsin’s largest utility WE Energies will reduce health impacts to the state’s residences.

Response to Comment 9 : The EPA thanks the commenter for their support.

Comment 10 : Commenter 17884 agrees with the National Mi ning 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 comment er also believes that the EPA exaggerates the PM 2.5 emissions, which are already a ddressed 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 by MATS. Acc ounting for ancillary benefits is standard practice in benefit-cost assessment since thes e benefits are a consequen ce 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 jus tify 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 cobenefits are thus an important category to quantify.

Consideration of ancillary benefits in benefit-cost analysis is directed by OMB Circular A-4 (p. 26, available at: http://www.whitehous e.gov/omb/circulars_a004_a-4/ ):

“Your analysis should look beyond the direct be nefits and direct costs of your rulemaking and consider any important ancillary benef its and countervailing risks. An ancillary benefit is a favorable impact of the rule thatis typically unrelated or secondary to the statutory purpose of the rulemaking (e.g., re duced refinery emissions due to more stringent fuel economy standards for light tr ucks) 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-econom y standards for light trucks).”

It is also directed by the EPA’s Gu idelines for Preparation of Economic Analyses (p. 11-2, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ):

“An economic analysis of regulatory or pol icy options should present all identifiable costs and benefits that are incremental to the regulation or policy under consideration. These should include directly intended effects and associated costs, as well as ancillary (or co-) benefits and costs.”

In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a regulatory action, to the extent f easible. We further note that we were unable to monetize other important benefits, including health bene fits of ozone reductions, additional PM 2.5 health benefits, and direct health benefits of reducing SO 2 . If we were able to fully mone tize these benefits, the benefits would exceed the costs by an even greater amount than we currently estimate.

The EPA disagrees that the quantified PM 2.5 health benefits are double-count ed with the health benefits achieved by other regulations. The EPA’s standard practice for its rules is to estimate, to the extent data and time allow, all benefits of the emissions reductions achieved by a rule beyond control requirements for other rules . If this rule was duplicative with other rule s, 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 exp ected as a result of MATS are additional emission reductions beyond those regulations (e .g., CSAPR) that were considered to be part of the baseline. Therefore, the benefits from particle reductions are not double counting – they are real additional health benefits from emissions reducti ons achieved by MATS alone.

Further, the PM 2.5 health benefits expected from this rule are not double-counted withbenefits 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 stra tegies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, th e control strategies that states may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directlyresult 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 cost s 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 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 th e Administrator to be pr otective of public health within an adequate margin of safety, taking into consideration effects on susceptible populations based on the scientific literature availabl e at the time the standard is set. Although benefits o ccurring below the standard may be less certain than those occurring above the standard, the EPA considers them to be legitimate components of th e 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 be nefits are the main reason for supporting the proposed rule, they also recognize secondary impact s 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, ecol ogical, and visibility bene fits are a likely outc ome of any action that results in reduced emissions of Hg, PM 2.5 , or other pollutants.

Comment 2: Commenter 17868 notes the possibility of unint ended 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 we stern coal to more power plants. Some customers are captive rail customers who must re ly on a single railroad to deliver their products. These customers tend to need bulk commodities such as coal, grain or lumber moved, which cannot be moved effectively on-road. The commenter references a study by the Surface Transportation Board (STB) that showed 44% of all tonnage shipped by freigh t rail is captive, which allows the railroad industry to charge rates 500 to 700% above cost and refusing to provide ade quate 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 im pact that has not been considered.

Response to Comment 2: The EPA modeling fully accounts for th e cost of rail tran sportation, including a consideration of rail competition. This is reflected in the results presented in the RIA. In recent years, railroads have increased coal transportation rates in real terms wherever they have the opportunity. However, rail rates at plants captive to a single rail carrier are now close to the maximum levels prescribed by the STB, which limits the potential for further real increases in these rates. Moreover, between 2004 and 2008, the differential between rates at captive plants and rates at competitively-served plants narrowed. For further information, pleas e 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-f loor options, but could notfind 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 qual ity health and environmental impacts also argue against determining that fuel switching is a reas onable beyond-the-floor op tion.” The commenters note that strong regulatory programs exist at the federal and state levels to protect against non-air quality health and environmental impacts from the produc tion, transport and use of natural gas. Commenter 17852 states that natura l gas does not involve issues as complex as those associated with nuclear waste disposal or the risks associated with nuclear accidents, the envi ronmental damage from mountaintop coal, the technical complexity of offshore deep water oil drilling or the need for new high-voltage, longdistance transmission or large land footprints needed for utility-scale renewable energy. This commenter goes on to say that the EPA’s record shows that n on-air issues apparently do not provide a reasonable basis to discourage fuel switchi ng 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 cost effective, not b ecause of the non-air quality health and environmental impacts. We do note, however, that natural gas ex traction through hydraulic frack ing is a relatively new process and, while it can be safelyundertaken, there remains some leve l of uncertainty a bout the level of expertise available to do so in all instances.

Comment 4 : Commenter 17833 expresses concern that the pr oposed rule may impair the reuse of coal combustion residuals (CCR) such as flue gas de sulfurization gypsum (FGD gypsum). The commenter urges the EPA to achieve emissions reductions without affecting the FGD gypsum market and points out that ignoring the implications of the proposed rule on CCR, the cost/ben efit analysis is incomplete and cannot be properly evaluated. The commenter explains that the us e of FGD gypsum to manufacture wallboard rose dramatically since 1995 in part because of the >$1.5 bi llion expansions and retrofittings done in 1999 to wallboard plants. That investmentturned over 85 million short tons of FGD gypsum into building material, and kept it out of landfills. In order to be used by most wallboard plants, FGD gypsum must be formed in a multistage process to precise specifications by the electric utilities. Converting operations to handle a different gypsum material requires plant cl osure and expensive recommissioning of the plant, as well as additiona l costs for transporting natural gypsum, which can approach the cost of the final product. The commenter discusses th e 30 years the FGD gypsum industry has spent reviewing literature and performing their own studies to be sure the it does not present human health or environmental concerns and provide d the following referenc es: Jessica Sanderson et al. , “Fate of Mercury in Synthetic Gypsum Used for Wa llboard Production,” USG Corp. Report for U.S. Department of Energy (Aug. 2005); Lisa Yost et al. , “Lack of Complete Expansive Pathways for Metals in Natural and FGD Gypsum,” 16 Human & Ecological Risk Assessment 317-39 (2010); Scott Shock et al. , “Evaluation of Potential for Mercury Volatilization from Natu ral and FGD Gypsum Using Flux Chamber Tests,” 43 Envtl. Science & Technology 2282-87 (Feb. 2009). Gypsum Association’s November 19, 2010 comments on EPA’s proposed coal ash waste rule: “Hazardous and Solid Management System: Identification and Listing of Special Wastes; Dispos al of Coal Combustion Residuals from Electric Utilities, Comments Submitte d by the Gypsum Association.” The commenter states that the loss of FGD gypsum in the manufactur e 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 prove n environmental benefit of FGD gypsum wallboard.

Response to Comment 4: The EPA does not expect a significant impact on the availability of FGD gypsum due to MATS. IPM analysis shows a potential 6 GW reduction in wet FGD operations, not all of which produce gypsum. This is a small fraction of the total 180 GW of wet F GD projected to operate in the base case, and should have an insignifi cant impact on the availability of FGD gypsum.

Comment 5 : Commenter 17833 sees a lack of information on the potential environm ental and economic impacts of these emission limits on the materials and waste streams that would be generated by EGUs to achieve regulatory compliance to be problematic. Without such information the commenter believes the EPA has not performed an appropriate cost-benefit anal ysis. In particular, the commenter points out that the proposed rule may affect metal levels in E GU wastewater and waste streams. Such downstream impacts must be addressed to adequately assess the costs and benefits of the proposed rule. The commenter believes the narrow scope of each separate media review prevents the EPA from properly assessing the costs-benefit ratio and the proposed rule’s potential to complicate or compromise the effectiveness of other proposed rules, and asks that the rules be cons idered in aggregate.488 Response to Comment 5: Waste streams associated with co nventional emission controls for NO X , SO 2 , and PM are already well regulated, and the costs of compliance with th ose regulations were considered as part of the promulgation of those rules. MATS may increase the number of waste streams that will have to be properly managed from two MATS-specifi c controls: ACI for Hg control, and trona DSI for HCl control. The EPA’s IPM modeling for MATS incl udes additional solid waste landfill disposal cost allowances as part of the variable O&M expenses associated with th ese 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 rule as well. The EPA is not aware of, and commenter has not provided any information about, any waste streams a ssociated with potential fu ture regulations that cannot be properly evaluated as phys ically distinct syst ems, not complicated or compromised by the waste streams already considered fo r MATS and other existing rules.

Comment 6 : Commenter 18447 states that the proposed rule ha s the potential to forc e their city to find an expensive landfill solution fo r its municipal solid waste as an alternative to burning it.

Response to Comment 6: There are multiple options for controll ing HAP to the levels required by the final rule and the final regulati on does not preclude the use of re fuse-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 polluti on controls that can be ut ilized to reduce emissions without requiring a new fuel source.

Comment 7 : Commenter 17928 argues that the higher th e 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 w ill result in increased hourly emissions of CO 2 . The EPA is currently designing emission guidelines for fossil- fired electric generating units and is taking this into consideration.

Comment 8 : Commenter 18477 discusses the Hawaiian RPS laws that may be undermined by the numeric limits in the proposed ru le. The commenter explains that Ha waii is moving toward having 70% of its energy use come from clean energy source s 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 In itiative designed to impl ement a fundamental and sustained transformation in the way renewable ener gy and energy efficiency re sources 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 st ate’s strategy to achieve these goals, the commenter explains, is the use of liquid biofuel from renewable s ources, 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 biofue ls and biofuel blends into its power plant operations.

The commenter explains that Hawaiian Electric is a re gulated entity that serves an isolated grid, so it does not have economic resources like those available to a merchant ge nerator which can sell power to the highest bidder. The commenter believes the capital investment into control t echnologies that may not be enough to achieve compliance will impact the ability to continue to implemen t the biofuels plan and will undermine the environmental be nefits 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 subcateg ory for liquid oil-fired EGUs. We believe that this will help address the concerns noted by commenter. The EPA is finalizing emission limitations for this subcategory because it do es not believe that work practice standards are applicable in this case as emissi on 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, 18428, 18433, 18434, 18437, 18486, 18497, 18500, 18575, 19114, 19121, 19199, 19212, 19213, 19653, 18023

1. Impacts analyses 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 economic and reliability analysis in the proposed ru le because it does not take into account the other major expenditures that will need to be undertaken by the utilities sect or in the next 5 to 8 years to comply with up to 8 other regulations. Commenters ask that the rules be considered together, or at least that the Transport rule (CSAPR) be considered in conjunction with the proposed rule. Commenter 17701 encourages multi-pollutant solutions through a robust analysis of all the rules and guidance on costeffective multi-pollutant responses. Commenter 17815 asks that the EPA especi ally consider impacts on regions such as Texas which relymore heavily on coal as a major fuel source, and commenter 17919 made a similar request in honor of the nation’s “industrial heartland.” Commenter 18428 believes the EPA should evaluate the effects of regulations together, as industry doe s, to plan for compliance in the most cost-effective manner possible. Commenter 18433 also explains that m ilitary buildup in Guam will strain resources there, allowing insufficient cap ital to meet all these requirements. Commenter 18497 states that the industry decisions pertaining to adding needed generati on capacity are being exacerbated by the number of new or pending rules and requests a thorough analysis of the combined impacts.

Response to Comment 1: The final CSAPR was included in the ba seline analysis for MATS and other finalized air rules and regulations. As explained in the preamble to today’s rule, the EPA considered impacts on regional bases as part of its overall analyses, and these ar e discussed in the RIA and other technical supporting materials.

The Agency did not prepare a cumulative impact an alysis to accompany the rule for the following reasons: 1) the various EO requirements that the Ag ency 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 th e merits of the regulation; 3) estima tes specific to a pa rticular rule are more transparent than those from a cumulative imp act analysis. A cumulative impact analysis lumps several regulations together and can potentially mask a high-cost/low benefit regulation among other rules that may have large net benefits. By anal yzing 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 th at 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 th at 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 a ssumptions have been made in the RIA, including negative economic impacts.

Response to Comment 2: The EPA recognizes its obligations unde r EO 13563 to use the best available techniques to accurately quantify both present and future costs and benefits as well as to ensure the objectivity of scientific and technol ogical information and processes us ed in its analysis. As such, the EPA relies upon guidance from its independent scientif ic and economic review panels and employs peer reviewed processes and techni cal literature in completing its analyses. The methodology and assumptions made for the analysis of the rule were included in the RIA that accompanied the proposal.

EPA modeling and projections are in tended to be a reflection of po ssible compliance using specific tools, assumptions, and methodologies that the agencybelieves to reflect th e best and most current information related to the power se ctor. It is not intende d to reflect actual co mpliance decisions, since those will be made individually be the affected industry based on whatmakes most sense using existing technologies or other, more cost-effective strategies.

The EPA has conducted detailed impact analysis of the rule, which s hows reasonable impacts to retail electricity prices. The analysis provides a rich ch aracterization of regional issues, and reflects the differences in the power sector composition across thos e regions. The impact of the rule will vary across regions, and the EPA has presented some of those imp acts 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 employmentanalysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the a ffected sector and the overall economy.

Comment 3: C ommenter 17629 requests that the cal culation and assumptions used to justify the proposed rule be reviewed in detail.

Response to Comment 3: The EPA recognizes its obligations under EO 13563 to use the best available techniques to accurately quantify both present and future costs and benefits as well as to ensure the objectivity of scientific and technol ogical information and processes us ed in its analysis. As such, the EPA relies upon guidance from its independent scientif ic and economic review panels and employs peer reviewed processes and techni cal literature in completing its analyses. The methodology and assumptions made for the analysis of the rule were included in the RIA that accompanied the proposal.

EPA modeling and projections are in tended to be a reflection of po ssible compliance using specific tools, assumptions, and methodologies that the agencybelieves to reflect th e best and most current information related to the power se ctor. It is not intende d to reflect actual co mpliance decisions, since those will be made individually be the affected industry based on whatmakes most sense using existing technologies or other, more cost-effective strategies.

The EPA has conducted detailed impact analysis of the rule, which s hows reasonable impacts to retail electricity prices. The analysis provides a rich ch aracterization of regional issues, and reflects the differences in the power sector composition across thos e regions. The impact of the rule will vary across regions, and the EPA has presented some of those imp acts 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 employmentanalysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the a ffected sector and the overall economy.492 2. General support for the proposed rule.

Comment 4: Commenter 16850 commends the EPA for allowing u tilities to deploy various control technologies in order to meet the pr oposed 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 specifically in asking that the EPA allow more flexibility and consider all rules associ ated with utilities together. Commenters 17701 and 18428 ask that there be a continued dialogue with federal and state utility and e nvironmental regulators to ensure compliance does not hinder system reliability and minimizes cost impacts on consumers. Commenter 17701 includes the National Association of Regulat ory 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 permitte d 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 current ly achieved by the best performing EGUs in the category. Individual facilities are free to use whatever technologies, processes, or other means they wish in order to achieve this standa rd. 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 flexibi lity for compliance by including, among other things, variability in setting emission standards; provi sions allowing emissions averaging among existing sources in the same subcategory to demonstrate compliance; use of su rrogates to determine compliance; choice for existing sources to comply with input -based or output-based limits; and guidance on appropriate use of the 1-year extension to comply w ith the proposed rule if additional time is needed for installation of controls.

Comment 6: Commenter 17648 states that the EPA has appropriate ly incorporated provisions in the proposed rule to provide regulated EGUs with flexib ility to reduce emissions to achieve compliance in the most cost-effective and efficient manne r 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 aver aging to demonstrate compliance 4. Use of surrogates to determine compliance, 5. Choice for existing sources to comply w ith input-based or output-based limits 6. Statutory eligibility for a one-year extension to comply w ith 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 unnecessari ly harm the industry

.
Response to Comment 6: The EPA thanks the commenter for these observations.

4. Proposed rule does not properl y account for all compliance costs.

Comment 7: Commenter 17758 discusses units that operate a nd 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 highe r than most other forms of electricity generation and would increase with retrofitting with an ESP while o ffering 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 cycl e units. Also, the EPA estimated that many oil/gas units will convert, or have alrea dy converted, to natural gas. The ru le contains “limited use” provisions that will mitigate the impacts on many oil-fired faciliti es 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 cap able of converting to another fu el (e.g., subject to natural gas curtailment) are expected to install cost -effective air pollutioncontrol technologies.

Comment 8: Commenter 17055 mentions that their initial assessment did not consider impacts the RICE regulations may have on the potent ial loss of small units relied upon by many municipalities. Elimination of these units could, th e commenter believes, leadto local congestion and require transmission expansi on and local programs to meet demand. The commenter believes that working with the industry to institute these changes will help preserve reliab le system operations and also allow for a more gradual integration of the co sts of compliance that could significantly mitigate reliability issues and sudden increases in consum er electricity prices. The commenter discusses an evaluation of costs due to potential environmental c ontrol installations required for a specific group of units if the owners determine that the units require retr ofitted controls instead of closure. The estimate of $8.5 billion would be required as ini tial investments for installation of the necessary controls, a number that may make funding difficult and which will impact the consumer bills.

Response to Comment 8: The agency has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serv e load after retirements are factor ed in, and industry has also shown that it can build new capacity quic kly in response to demand. The EPA believes it has appropriately assessed the potential impacts of this rule, but also recognizes that indi vidual plant retirement decisions for compliance with the rule are made based on indi vidual 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 flexib ility to deal with timing when additional time is needed to address transmissi on 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 co mply, if conditions warrant (see preamble).

Comment 9: Several commenters (17403, 18016, 18033, 18497) quot e the National Economic Research Associates analysis results showing the combined impacts of the proposed rule and the Clean Air Transport Rule. The analysis shows the proposed ru le is responsible for the majority of economic494 impacts that utilities will need to consider whenplanning for compliance. The commenters present an estimation of compliance costs from this analysis of $17.8 billion in annualized compliance costs and a total cost of $184 billion for 2011- 2030, with estimated price increase s from 12 to 23% in certain regions.

Response to Comment 9: The EPA modeling of the final rule proj ects lower price impacts than noted by commenter, and the analyses and results are fu lly 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 ensuri ng public health is protected in accordance with requirements outlined in the CAA. The EPA has conducted detailed economic impacts analysis on the regulated sector, and finds the impact of the rule on th e regulated sector is small compared to the overall benefits, and the industry has an excellent track reco rd of installing pollution controls without greatly impacting electricity prices. The repo rt cited by the commenter is not tr ansparent with regards to several key criteria, making it impossible for the EPA to fu lly assess its value as a critique of the RIA.

Comment 10: Commenter 17638 states that the evidence shows that the EPA underestimated the impact of compliance costs of the proposed rule including the following impacts:

1. Electric grid reliability, including transmission 2. The number of coal fired units reti red in response to the proposed rule 3. Increases in natural gas prices 4. Increases in electricity rates 5. The impact on national, re gional and local economies.

The commenter requests that the EPA respond to the EIA , EEI , NERC , NERA, Credit Suisse, ICF, and Burns & McDonnell and explain how its approach as directed by EO 13563 utiliz ed the best available techniques to quantify anticipated presen t and future benefits and costs...” The commenter further states that the EPA does not consider the cumulative impact s of all its rules, as shown by wording on page 25058 of the proposed rule that it has yet to consider these cumulative impacts.

Response to Comment 10: The agency did not prepare a cumulativ e impact analysis to accompany the rule for the following reasons: 1) the various EO requi rements that the agency must comply with require us to estimate impacts specific to this rule; 2) de cision makers and the public need to know the impacts specific to a particular rule in or der to judge the merits of the regul ation; 3) estimates specific to a particular rule are more transparent than those from a cumulative impact analysis. A cumulative impact analysis lumps several regulations together and can potentially mask a high-cost/low benefit regulation among other rules that may have large net benefits. By analyzing each regulation separately, the EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this particular regulation.

This does not, however, mean the EPA has failed to consider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.

Additionally, the agency does reflec t on the broader cumulative impact s of our regulations. In March 2011, the EPA issued the Second Clean Air Act Prosp ective Report which assesse d at the benefits and495 costs of regulations pursuant to the 1990 CleanAir Act Amendments. The study examines the cumulative impact of these regulations (found at http://www.epa.gov/air/sect812/feb11/summaryreport.pdf). As shown in th e report, the di rect benefits from the 1990 Clean Air Act Amendments reach almo st $2 trillion for the year 2020, a figure that dwarfs the direct costs of implementa tion ($65 billion). The full report is at http://www.epa.gov/air/sect812/prospective2.html.

The direct benefits of the 1990 CAA Amendments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reve rsed using any reasonable alternative assumptions or methods. This conclusion is like ly to also be attributable to this rule as shown in the RIA.

Comment 11: Commenter 17702 questions the solitary estimate for cost of compliance as opposed to the range of monetized benefits for the proposed rule. The commenter believes that the EPA should provide a range of costs based on best and worst case scenarios from the EPA’s estimate of 11.1 GW of coal-fired generation being shut-down, to other industry estimat es of up to 48 GWs shutdown. The
commenter especially questions the EPA’s assumption thatnew natural gas from shale formations will provide sufficient gas to allow fuel switching from coal to gas, despite a recent New York Times article indicating that the amount of gas may be overestimated. (New York Times article June 26, 20 II “Insiders Sound an Alarm Amid a Natural Gas Rush”)

Response to Comment 11: The EPA agrees that providing a range of estimates can be one way to present the results of analyses, but it is certainly not the only way, and the EPA is not required by E.O. 13563 to present a range of impact estimates. The EPA has conducted sensitivity analyses that explore key parameters in order to ensure its analyses are as accurate and reliable as reasonably possible, and the corresponding impacts (including cost) can be found in Chapter 3 of the RIA for the rule. To the extent that the background information on which news media reli ed for their reports is not in the record, we are not able to comment on their veracity. The EPA recognizes its obligations under EO 13563 to use the best available techniques to accurately quantify both pr esent and future costs and benefits as well as to ensure the objectivity of scientific and technol ogical information and processe s used in its analysis. As such, the EPA relies upon guidance from its independe nt scientific and econo mic review panels and employs peer reviewed processes and technical l iterature in completing it s analyses. The methodology and assumptions made for the analys is of the rule were included in the RIA that accompanied the proposal.

Comment 12: Commenter 17718 states that the EPA’s cost-benef it 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 subsid iary to comply with the proposed rule, which is exp ected 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 co sts 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-f ired capacity shows that the overa ll compliance costs of less than $11 billion are greatly underestimated. The commenter includes the following reference in a footnote:

In the Matter of: Application of Kentucky Ut ilities 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: Applic ation of Louisville Gas and Electric Company for Certificates of Public Convenience and Necessity and Approval of Its 2011 Compliance Plan

Response to Comment 12: The commenter has not provided the necessary information to enable the EPA to evaluate commenter’s assertions. The EPA has conducted a detailed national impact analysis of the rule, which includes estimates of impacts to reta il electricity prices that the EPA believes, in the absence of contradictory evidence, is reasonable. Moreover, industry ha s shown in the past that it can install significant pollution controls more cost-eff ectively than the EPA can sometimes anticipate.

Comment 13: Commenter 17743 states that the proposed rule’s standards will apply to all power plants in Oklahoma and is expected to involve widespread installation of new emission control technologies at great compliance cost.

Response to Comment 13: The standards do not cover all power plants in Oklahoma. Rather, the standards apply to coal- and oil-fi red EGUs of greater than 25 MW . The EPA has conducted a detailed national impact analysis of the rule, which includes es timates of impacts to retail electricity prices that the EPA believes, in the absence of contradictory evidence, is reasona ble. Moreover, industry has shown in the past that it can install significant polluti on controls more cost-effectively than the EPA can sometimes anticipate.

Comment 14: Multiple commenters (17281, 17299, 17305, 17306, 17849, 19041, 19123, 19209) express concern that proposed rule may affect the affo rdability 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 in cremental compliance costs in 2015 are underestimated by half. The commenter asks the EPA to carefully analyze the cost estimates and impact on grid reliability and energy costs and revise the fina l rule appropriately, or withdraw the rule entirely since it can’t be justified technically or economically.

Response to Comment 14: The agency prepared a resource adequacy analysis for the proposed rule and has revised that analysis for the final rule. The agency is also working with FERC regarding the reliability impacts of this rule. The EPA has outlined th e various flexibilities associ ated 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 demonstrati ng 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 prep ared for this rule, and the results are summarized in the preamble for this rule. Results of these analyses are available in various le vel of detail in the RIA and the TSDs, and the detailed results can be f ound in the docket for this rulemaking and through the official web site for this rule.

Comment 15: Commenter 17761 believes the EPA compliance co st estimation is too low. The
commenter cites the $17,000 incremental cost for burner inspection and states that their experience with such inspections gives a very different number.

Response to Comment 15: The EPA is sensitive to the concerns raised by the commenter about the costs of a complete burner inspection requiring a un it outage and internal boile r scaffolding and so we are adjusting the time period between burner inspecti ons not to exceed 36 months. Additionally, a unit that employs neural net combustion optimization so ftware during all periods of normal operation may497 not exceed 48 months between burner inspections. Th is allows the burner inspection to be combined with other critical work projects th at require internal access to the unit, and reduces the overall cost burden of the work.

Comment 16: Commenter 17765 reports the cost of complying withjust the acid gas standard of the proposed rule could easily be over three times high er than the EPA’s projec tion 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 re tirement are much higher than the EPA’s estimate, ranging from 50 to as high as 100 GW in retirements, as opposed to the EPA’s estimate of 10 GW

.
Response to Comment 16: The EPA disagrees with commenter’ s assertion that the EPA’s cost projection is understate d, and maintains that the EPA’s incremen tal cost and retirement projections are reasonable. The EPA also notes that the estimates commenter refers to do not necessarily project impacts based on an identical policy. The EPA has c onducted detailed impact analysis of the rule, which shows reasonable cost impacts. Industry has shown th at it can install large am ounts of pollution controls and often finds more cost-effective compliance options than the EPA can anticipate.

Comment 17: Commenter 17775 reports that a comparison of a Hg-only MACT rule to an all-HAP MACT rule leads to an additional $30 billion in overnight capital expenditures for additional pollution control equipment and an additional $13 billion in overnight capital expenditures for new capacity additions. The commenter mentions that an all-HAP ru le results in 5 GW of a dditional plant retirements when compared to a Hg-only rule.

Response to Comment 17: The EPA disagrees with commenter’s characterization of the additional costs associated with today’s rule as “overnight cap ital expenditures,” as existing affected sources have up to 3 years to comply with the ru le (including the potential for an a dditional year for the installation of controls), and capital costs are typically amortized over an extended period of time. Comparing the estimated costs of complying with today’s rule with those of a Hg-only rule is inappropriate, as the EPA is establishing standards for all HAP emitted from EGUs consistent with CAA section 112. The preamble provides further discussion of the legal requ irements that the EPA has sought to comply with in adopting today’s rule. The EPA be lieves, in the absence of contra dictory evidence, that the costs imposed by the rule are r easonable. Moreover, industry has shown in the past that it can install significant pollution controls more cost-effectiv ely than the EPA can sometimes anticipate.

Comment 18: Commenter 17813 points out that fabric filters were not included in costs for beyond-thefloor limits, but should be included since it is still unknown if ESPs can meet the PM standard.

Response to Comment 18: The EPA has conducted detailed impact analysis of the rule and includes cost of fabric filters, ESPs, and ESP upgrades. The costresults 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 co al ash may be designated as hazardous waste under RCRA (Subtitle C), causing state and municipal governments to feel compelled to remove and remediate the coal ash fill from under buildings, atlandfills, and under highways. These costs are not498 considered in the estimated cost for the proposed ru le. 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 sc ope of this rulemaking and, thus, the EPA is not providing a response. The EPA is addressing issues related to coal combustion residuals in a separate rulemaking.

Comment 20: Commenter 17824 discusses the proposed ozone limits being lowered from 0.075 ppm to 0.060-0.070 ppm . The commenter states that a limit of 0.060 ppm will change 13 of Alabama’s 14 monitored counties to non- attainment status and move 85% ofmonitored counties nationwide to nonattainment status, leading to a cost of $20-$90 billion annually and potentially costs up to 7 million jobs by 2020 and close many of these counties to new business.

Response to Comment 20: This comment is not within the scope of this rulemaking and, thus, the EPA is not providing a response. The EPA is addressing issues related to the NAAQS for Ozone in a separate rulemaking.

Comment 21: Commenter 17824 discusses the regulation of three utilities operating 12 EGUs affected by the proposed rule. Between them the utilities estimate compliance costs of $116.2 million in capital costs, and an expectation that the proposed rule would contribute to the retirement of 2 of the units for a loss of 253 MW. More of these units may be retire d, depending on the final rules promulgated for the interrelated regulations currently targeting utilities.

Response to Comment 21: The EPA has designed the rule to mitig ate the impacts to the extent possible and finds that a very small amount of the coal fleet c ould 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 alternat ives in the course of their analysis.

Comment 22: Commenter 17686 asks that the EPA acknowledge the price increase per MW for compliance as the size of the unit decreases. Commenter 18021 agrees with this additional strain on smaller units, due to the economy of scale. The comm enter believes that the EPA did not consider the disproportionately large co st 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 control technologies to cost approximately 3 times more per MW for small units. (The commenter includes the following references : U.S

. Utilities: Coal-Fired Generation Is Squeezed in the Vice of EPA Regul ation; Who Wins and Who Loses?, Bernstein Research, 2010., “The Hidden State Financial Crisis ,” Wall Street Journal online publication, May 18, 2011.)

Response to Comment 22: The EPA’s analysis includes sca ling factors for pollution controls, depending upon the size of a par ticular unit. See documentation for the IPM for more detail.

Comment 23: Commenter 17883 owns and operates severa l coal-fired facilities s ubject to the proposed rule and sees the proposed Hg limits as difficult to achieve without costly modifications while other facilities will require modifications to meet HCl limits. The costs are estimated to be $60 million for one facility.499 Response to Comment 23: The EPA recognizes that the final rule will obligate source owners to install additional controls and has attempted both to mini mize unnecessary additional co sts and to accurately estimate the costs to the industry. The EPA cannot veri fy commenter’s assertions with regard to any particular unit or facility.

Comment 24: Commenter 18425 expresses concern about the compliance costs of the acid gas controls, which the commenter believes will have a large impact on Indiana coal industry. The commenter considers the conclusion that regulating acid gases is necessary to be incorrect and creates costs greater than what is necessary to protect public health.

Response to Comment 24: The EPA disagrees with the commenter for the reasons set forth in the proposed rule and this final action. The commenter provides no information that causes the EPA to reconsider our conclusions. The EPA has conducted detailed impact analysis of the rule, which shows reasonable cost impacts. Industry ha s 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 25: Commenter 19121 considers the EPA’s estimated comp liance costs to be underestimated since forced retirements and fuel switching are not properly attributed.

Response to Comment 25: The EPA disagrees with commenter’s assertion that compliance costs are underestimated or that there is anyt hing in the rule that requires a unit to retire, since retirements are the products of economic business deci sions left to the owner. Comm enter does not provide detailed information on the “forced retirements and fuel sw itching” that commenter alleges are not properly attributed.

Comment 26: Commenter 18433 explains the costs for units in Guamand references cost estimates in the Edison Electric Institut e report on average retrofit capital cost for ESPs and DSI technology. The
commenter references a table created for the 4 units whic h will be subject to the proposed rule. [See Table 2 in EPA-HQ-OAR-2009-0234-18433-A3 ]

Response to Comment 26: The EPA has included a separate category for non-continental liquid oilfired EGUs (see preamble).

5. Proposed rule does not properl y account for all other impacts.

Comment 27: Commenter 17408 considers the proposed rule and other new or proposed rules focused on the coal industry. The commenter points out that hundreds of thousands of people make a living from coal and cites a Penn State study that showed there to be up to 11 jobs created for every one coal job. The commenter also states that millions of people rely on the electricity that coal provides.

Response to Comment 27: The EPA has conducted detailed impact analysis of the rule, which shows impacts that the EPA judges to be reasonable. The EP A 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 employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.500 Comment 28: Commenter 17707 discusses the Alabama Power installation of $2.6 billion worth of emission control tec hnologies, including SCRs and scrubbers with reduced emissions from their coalfired units approximately 65% since 1996. The commenter considers the EPA’s new standards to be unreasonable because any benefits would be increm ental and outweighed by the costs of compliance. The commenter states that small coal-fired units will not be able to afford upgrades and the proposed rule will result in lost jobs and re venue due to high compliance costs.

Response to Comment 28: The benefits of this rule encompass the benefits of Hg reductions and cobenefits to health achieved via PM 2.5 reductions. The EPA has conducted detailed economic impacts analysis on the regulated sector, a nd finds the impacts of the rule on the regulated sector are small compared to the overall benefits, and the industry ha s an excellent track reco rd of installing pollution controls without greatly impacti ng electricity prices. In additi on, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into comp liance. 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 sm ooth transition with this rule and ad dress 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 implementi ng the proposed rule. Commenters 17716 and 17731 point out that the proposed ru le has no effect on whether efficiency savings are realized and these savings do not serve as offsets to the hi gher compliance costs imposed by the proposed rule. Commenters believe energy efficiency had onl y a modest, indirect effect inlater years and references Table 23, lines 3 and 4 on page 25074 of the proposed rule, which shows incr emental annual compliance costs with and without energy effi ciencies. The compliance cost is the same for both options in 2015, and changes only from $9 billion (with) to $10 billion (without) in years 2020 and 2030. The
commenters also disagree with claims that energy effici encies will offset rate hikes. The commenters believe changes in the amount of energy used are mo re 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 owne r or operator. However, the EPA believes energy efficiency m easures can be a complement to th is rule, and can be an important tool in helping address emissions. The EPA has not included all the likely a dditional energy efficiency measures that may occur by 2015, but will conti nue to pursue energy efficiency improvements throughout the economy, along with othe r Federal agencies, states and other groups. This will contribute to additional environmental and pub lic health improvements while lowe ring the costs of realizing those improvements.

Comment 30: Several commenters (17791, 18421, 18434) acknowledge that the proposed rule recognizes the role of energy efficiency in redu cing compliance costs and not es that the EPA cannot mandate energy efficiency policies. The commenters quote the EPA estimate that energy efficiency could reduce costs of the proposed rule by $2 bil lion in 2015, $6 billion in 2020 and $11 billion in 2030. Commenter 18434 believes that since energy-efficiency i nvestments are concentrated in densely501 populated areas with highest demand, ev en limited policies in the existing sensitivity analysis are likely to have greater benefits than estimated. This commenter also states that both state and federal policymakers are making progress in the area of energy efficiency, making the potential for fuel savings through efficiency greater than that estimated. The commenter urges the EPA to modify the analysis to reflect the State Energy Efficiency Acti on Network recommendations. The commenter understands that the EPA cannot mandate efficiency programs, but it can urge state regulators to view compliance extension requests more favorably from facilities making efforts to advance efficiency.

Response to Comment 30: The EPA agrees that energy efficiencymeasures can be a complement to this rule and can be an important tool in helpin g address emissions. The EP A 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 wi th other federal agencies, states and other groups. This will contribute to additional environm ental 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 environmen tal benefit of CHP and has been carried over to the NESHAP.

Comment 31: Some commenters (17689, 17824, 17887, 17912, 18021, 18037, 18500, 19212, 18023 ) express concern about the combin ation of multiple regulations cu rrently proposed and the limited timeframe for compliance with th ese proposed rules. Commenter 17689 mentions the NSR and permitting requirements for the installation of control technology, and the f act that this process can take over a year. This would be likely to create a backlog at state agenci es, making it nearly impossible to meet the compliance timeline. Commenter s 17824 and 18023 in particular cite the EEI s tudy that found 50% of the U.S

. coal fleet may be unavailable by 2015 as a result. Commenter 17887 points out that many generators will need the same equipment and specialized labor, leading to price pressure and equipment shortages due to th e tight timeline. Commenters 17912 and 17689 question the need for outages to install equipment for multiple rules duri ng the same timeframe, which will require more time than is allowed under these rules. The commenter sees this as particularly probl ematic for IPPs, because they typically do not have enough EGUs to avoid reliability issues withsuch outages and will have to pay to replace the capacity. Commenter 18037 explai ns the difficulties for planning without time to consider economies of scale, or co-benefits that c ould be realized by the inst allation of one type of equipment as opposed to several. Also, this commenter discusses the physical space constraints for some plants looking to retro-fit control equipment. To remain competitive, fac ilities must add control equipment as it is needed, and adding equipment before it is necessary is financiall y imprudent.

Response to Comment 31: One of the purposes of developing the NSPS and MATS rules in tandem was to facilitate more cost-effec tive 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 pollu tion controls, and additiona l detail on timing can be found in the preamble.

Comment 32: Commenter 18015 believes as an owner/operator of three large coal-fired power plants that the proposed rule will have signi ficant impacts on the company’s operations.

Response to Comment 32: The EPA has conducted detailed impact analysis of the rule, which shows impacts the EPA has judged to be reasonable. The EP A has designed the rule to mitigate the impacts to502 the extent possible. In addition, th ere are certain provisions for granti ng 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 Cons ent Decree in the matter of American Nurses Ass’n v. EPA , 08-2198 (D.D.C.). That decr ee requires the EPA to sign the final MATS rule by December 16, 2011.

Comment 34: Commenter 18023 reports that the roughly 400 GW of capacity affected by the proposed rule and other pending or new regulations are vital to adequate electricity suppl y and provide substantial generator-supplied frequency control capability to th e bulk power system. The commenter states that the aggregate impact of these rules will require unpr ecedented levels of generation and transmission construction in a short time period and could force i ndustry to operate in uncertain conditions. System changes in the electricity industry must be evaluated in advance so the system can be planned and operated such that the causes and effects ca n be understood, and costs and problems minimized.

Response to Comment 34: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired capac ity) and that coal-fired generation will not change significantly. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence that will help serve load. In addition, ther e are certain provisions for granting utilities some additional time to compl y, if conditions warrant (see preamble). The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule and address specific issues.

6. Coordination of rules regulating similar pollutants.

Comment 35: Commenter 17627 states that NSPS requirements in the proposed rule have the potential to retire coal generati on without an economical replacement, increasing costs to the public. The
commenter asks that the proposed rules that deal with the same pollutants be coordi nated so that one is implemented and given time to realize benefits befo re another program controlling the same pollutants are implemented. The commenter believes this approach would pr oduce the desired environmental and human health benefits while maintaining system reliability and minimizing costs.

Response to Comment 35: To the extent possible, the EPA has coordinated the rulemakings. However, CAA section 112 provides statutory compliance times which preclude doing muchof what commenter seeks. Other comments on the compliance time issue ar e responded to elsewhere in the final rule record.

Comment 36: Commenters 17681 and 17901 state that the EPA’s initiatives will each have an impact on electricity cost and transmissi on and together the compliance cost s could disproportionately impact the elderly, minorities and low-in come 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 Title V permitting; (j) GHG NSPS; (k) 2010 revisions to 40 CF R Part 63, subpart ZZZZ; (l) 316(b) cooling water intake structures; (m) Steam Electric Effluent Guidelines; (n) Numeric nutrient criteria; (o) Total Maximum Daily Load rules; and (p) Coal Combustion Residuals.

The commenters also ask that the EPA honor EO 13563 by considering these rules together. Commenter 17901 estimates that the combined rules will dire ctly impact approximately 400,000 MW or oil- and coal-fired generation, or 40 to 50% of national electricity generation.

Response to Comment 36: The EPA acknowledges that elderly, minority and low-income populations are overrepresented among those persons who live in close proximity to co al-fired power plants. For that reason, the EPA expects that el derly, minority, and low-income population groups would benefit disproportionately from the reduced emissions that will result from the rulemaking. The agency did not prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO requirements that the agency must comply with require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the impacts specific to a pa rticular rule in order to judge the merits of the regulation; 3) estimates specific to a particular rule are more transparent than those from a cumulative impact analysis. A cumulative imp act analysis lumps several regulations together and can potentially mask a high-cost/lowbenefit regulation among other rules that may have large net benefits. By analyzing each regula tion separately, the EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this particular regulation.

This does not, however, mean EPA has failed to c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.

Additionally, the Agency does reflec t 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/su mmaryreport.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 di rect 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 Am endments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wi de margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed504 using any reasonable alternative assump tions 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 a bout overlapping, redundant or inconsistent requirements as well as doing everything in the Govern ment’s power to stop wasteful practices. The commenter questions the EPA’s choice to impose se veral regulations instead of one. The
commenter quotes the EPA study that states implementation of the 1997 NAAQS for ozone and PM may lead to Hg reductions, but went on to say that the reductions could not be sufficiently quantified. The commenter questions the validity of the statement and asks the EPA to develop and implement a procedure to provide reasonable upper and lower bound estimates of PM reductions likely to be achieved through state SIP programs. The commenter acknowledges that the estimates may not be completely accurate, but believes providing an estimate would be more helpful than not including one. The commenter believes that by not making a prediction, the EP A is essentially assuming the benefits of the state SIP programs on Hg will be zero, which is not cr edible 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 atta ining these NAAQS. Although both RIAs calculate PM and ozone costs and benefits, it is important to note that there are key differences in th e design and analytical objectives of a NAAQS RIA and one for a rule such as MATS. The NAAQS RIAs illustrate the potential costs and benefits of attaining a new air quality standard nationwide based on an array of emission control strategies for different sources. In short, NAAQS RIAs hypothesize, bu t do not predict, the control strategies that states may choos e to enact when implementing a NAAQS. The setting of a NAAQS does not directly result in costs or be nefits, and as such, the NAAQS RIAs are merely illustrative and are not intended to be added to the costs an d benefits of other regulations that result in specific costs of control and emission reductions. Some costs and benefits estimat ed 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 coor dinated control strategies for EGUs. The commenter considers this approach to be too late, si nce 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 th e regulated community plan for all interrelated regulations and cumulatively assess th e societal impacts of these regulations, which has not been done in this instance. The commenter sees the combined regulations impacting American competitiveness as increased prices undermine busines ses ability to compete and sendi ng businesses and jobs overseas.

Response to Comment 38: The EPA believes that by proceeding with the rules being adopted today, which were developed with explicit consideration of the impacts of CS APR, 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 indu stry. 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 tribal nation and sma ll government landlord of affected EGUs, states that the EPA is obligated to consult with the commenter and analyze the economic impacts to the commenter in promulgating the proposed rule. The commenter further states that EPA is required to tailor the proposed rule so thatthe costs of compliance for plan ts on the commenter are achievable within a reasonable timeframe, while taking into account the unique cha llenges of the plants for this and future rulemakings. The commenter explains that compliance costs to meet BART have the potential to impact the commenter’s economy significantly. The comm enter is concerned that the proposed rule will create a recurring threat of severe reductions in the revenue recei ved from the power plants and their supplying mines. The commenter explains that FCPP and NGS ar e subject to proposed BART determinations and that EPA, Region IX, proposed an Alternative Emission C ontrol 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 significantly reduce emissions from FCPP. Curren tly, the EPA, Region IX, has delayed proposing BART for NGS until at least December, 2011, pending consultations with stak eholder tribes. After publication of the ANPRM for BART, the commente r recommended a phased approach to emissions controls for FCPP and NGS, and suggested that th e EPA consider the multiple interests at stake, including the significant economic interests of th e commenter. The commenter asks that the EPA analyze the impacts from these rulemakings and provi de flexibility for compliance scheduling so that FCPP and NGS, upon which the commenter relies, can continue operations.

Response to Comment 39: Landlords of affected facilities are not included in the definition of an affected small entity and, thus, were not included in the EPA’s analysis of small entity impacts. The EPA conducted multiple consultations with the tribes, including the Navajo Nation and has sought to be responsive to concerns raised in those consultations. As to comment s about an obligation to tailor the rule to the Navajo Nation’s economy, the CAA impos es certain specific requirements and the EPA does not believe that it permits tailoring to the extentthat appears to be requested by the commenters.

With respect to compliance, the EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into compliance. Sources may also seek a 1-year extension of the compliance period from their title V permitting authority if the source needs that time to install controls. CAA section 112(i)(3)(B).

8. Methodology and assumptions in calculations.

Comment 40: Commenter 17810 recognizes that the EPA can consid er costs as part of the beyond-thefloor analysis, but asks that the EPA clarify the methodology and assumptions used and expand the analysis to include potential cost effectiveness of repowering coal-fir ed units as natural gas combined cycle units. The commenter provides recommendations on the technologi es used in combusting natural gas, fuel costs and pipeline cost s. (Insert included in original letter 17810-A1_Table2Page17.doc.) The commenter questions the pipeline construction costs for converting ex isting 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 whic h the EPA’s methods result in cost estimates 20 times greater than a more site-specific estimate. The commenter offers a ta ble showing two example coal-to-gas repowered units for which the EPA es timate is approximately $375 million while the total costs using Navigant estimates ar e $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 a ssumption is not shown.506 Commenter 17810 also requests clarificati on on the “Incremental Fixe d Costs” equation and any assumptions made about plant life. The commenter questions whether the manner in which the EPA evaluated these costs is scientif ically sound, since the report only includes costs associated with retrofitting a 303 MW unit at static te chnology, pipeline and fuel costs. The commenter notes that no information on why the EPA chose to estimate cost s for only one unit or chose a 303 MW unit. Since these costs can vary greatly depe nding on the unit size, the commenter suggests that the EPA conduct a sensitivity analysis showing the cost s of retrofit options for different size units and fuel price points.

Commenter 17810 suggests the EPA analyze the costs of re tiring 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 ev aluation of the cost of control options since there are efficiency advantages over boiler-based technologies.

Response 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 adequately evaluated. The EPA’s IPM modeling inherently considers new NGCC capacity as analternative to continue d operation of existing coal units, with and without retr ofit air emission controls. The EP A’s IPM modeling for MATS also offers a CTG option for existing coal units, wherein the CTG capital cost is properly scaled to the existing unit size. The EPA’s TSD discussion of CT G used an average unit size of about 300 MW only to illustrate the approximate average economics of a lternative (and collective) control options, including CTG. The EPA has fully documented its peer-reviewed methodology and assumptions for assessing the impacts of this rule, which can be found in the documentation for IPM ( http://www.epa.gov/airmarkets /progsregs/epa-ipm/index.html ). The documentation includes generation technology assumptions, pollution control cost assu mptions, fuel supply assumptions, and financial assumptions governing the power sector.

9. Energy efficiency reduces compliance costs and emissions.

Comment 41: Commenter 17843 appreciates the Energy Efficiency Scenario that illustrates how the costs of the proposed rule can be lowered through energy efficiency in vestments instead of retrofitting pollution controls or building new generation units. The commenter points out that energy efficiency also enhances reliability as it enc ourages retirement of the least effi cient units as demand decreases. The
commenter points out that some states are pursuing aggr essive 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/doc s/Investment_of_RGGI_Allowance_Proceeds.pdf (accessed July 8, 2011).

Response to Comment 41: The benefits of energy efficiency policies are discussed in the preamble. These impacts include reduced need for construction of new generating capacity as well as reduced need for construction of emissions controls such as FGDs . The EPA has designed a rule with 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 the like ly additional energy efficiency meas ures that are likely to occur by 2015, but will continue to pursue energy efficiencyimprovements throughout the economy, along with other Federal agencies, states and other groups. Th is will contribute to add itional environmental and public health improvements while lowering th e costs of realizing those improvements.507 Comment 42: Commenter 17929 states that new boilers can reduc e emissions by incorporating energyefficient designs that allow them to use less co al to produce the same amount of electricity. The
commenter points out that a boiler operating at 40% effi ciency will use 10% less coal to produce the same amount of power than if it is operated at 36% efficiency.

Response to Comment 42: The EPA generally agrees and thanks the commenter for their observation.

Comment 43: Commenter 18421 discusses the role of energy e fficiency in reducing costs and preserving reliability. The commenter cites studi es by McKinsey and Company, MIT’s Innovations, U.S

. DOE and others that see benefits to more e fficient processes and improved demand-side energy efficiency programs. The commenter compares the T oxics Rule Case without energy efficiency to the Toxics Rule Case with energy efficiency and found th at the efficiency policie s 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 electr icity demand growth. The commenter cites a 2009 study by the American Council for an Energy-Efficien t Economy which found by looking at programs in 14 states that efficiency programs by the utility sector cost one-third less than investing in new generation of any type. A report by Synapse Energy Economics re inforced the finding and showed that the highest cost per kWh saved through energy efficiency was 3 cen ts, compared to the national average of 9 cents per kWh of delivered electricity. (The commenter provided the following references as footnotes: RIA8.13 Illustrative End-use Energy Efficiency Polic y Sensitivity RIA8 Appendix D. For example, McKinsey& Company, “Unlocking En ergy Efficiency in the U.S

. Economy,” (July 2009), Hannah ChoiGranade, Jon Creyts, Anton Derkach, Phi lip Farese, Scott Nyqui st, and Ken Ostrowski ( http://www.mckinsey.com/clientserv ice/electricpowernaturalgas/downloads/us_energy_efficiency_full_ report.pdf ) and Electric Power Research Institute, “Assessment of Achievable Potential of Energy Efficiency and Demand Response Programs in the U.S . (2010-2030),” (January 2009), ( http://www.edisonfoundation.net/ie e/reports/EPRI_SummaryAssessm entAchievableEEPotential0109.p df

).American Council for an Energy-Efficient Economy, Saving Energy Cost-Effectively: A National Review of the Cost of Energy Saved Thr ough Utility-Sector Energy Efficiency Programs , September 2009. 105 States evaluated are: California, Connectic ut, Iowa, Massachusetts, Minnesota, Nevada, New Mexico, New Jersey, New York, Oregon, Rhode Is land, Texas, Vermont, and Wisconsin Synapse Energy Economics, Inc, No Need to Wait: Using Energy Effici ency and Offsets to Meet Early Electric Sector Greenhouse Gas Targets , May 2009.)

Response to Comment 43: The studies cited provide informati on on the cost-effectiveness of energy efficiency policies that are gene rally consistent with the sour ces cited for the EPA analysis.

10. Fuel switching.

Comment 44: Commenter 18423 questions the EPA’s statements a nd calculations pertaining to fuel switching as a regulatory option. The commenter questions the lack of consid eration for new gas units to replace coal units and the rejection of fuel switching as an option due to the lack of supply/availability of natural gas and the cost. The commenter reviews the capital costs calcul ated by the EPA and concludes that the ratio of cost of fuel switching from coal to gas is 18-53% higher than th e 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 switc hing to natural gas removes the expe nse 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 c ontrol technology refit scenario comparisons.508 Response to Comment 44: The EPA disagrees with commenter’ s assertion that EPA calculations comparing the coal-to-gas (CTG) boiler conversion opti on to other retrofit cont rol options incorrectly included the base cost of coal fuel (as well as ga s fuel) in the CTG incremental fuel cost. The EPA incremental cost calculations are correct. Furthermore, EPA’s IPM an alysis has fully considered and included the multitude of compliance options available to sources. The IPM analysis indicates that there will be a small amount of coal retire ments (less than 2% of all coal-fir ed capacity) and that coal-fired generation will not change significantly. The agencyhas also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence that will help serve load. The EPA modeling fully reflects the costs of competing fuels, and the results can be found in Chapter 3 of the RIA. The EPA responds to comments associated with requiring units to switch to natural gas in response to comments on the beyond the floor analys is elsewhere in the final rule record.

11. Miscellaneous.

Comment 45: Commenter 17752 expresses concern about the risk of noncomp liance for early action. The commenter explains that if controls are installed ba sed on the proposed rule do not achieve the reductions required by the final rule, the unit owner faces enforcement penalties because there is not market in which to buy allowances to cover the compliance shortfall. The commenter also notes that utilities contemplating retrofits to units in rate-regula ted states run a risk of non-recovery if they make capital commitments before the final rule is issued.

Response to Comment 45: The EPA is allowing a 3-year compliance timeframe for existing sources affected by the rule, and there ar e also conditions under which exte nsions could be granted (see preamble for additional discussion on timing.

Comment 46: Commenter 19114 questions the lack of documentati on to support conclusions about the amount to capacity that would or would not need to add fabric filters to meet the proposed PM limits. The commenter requests full emission data and projections along with details on which technologies, controls and units are likely to meet the HAP standards with or without the use of a fabric filter.

Response to Comment 46: See Documentation Supplement for EPA Base Case v.4.10_MATS – Updates for Final Mercury and Air Toxics Standards (MATS) Rule for a detailed description of the assumptions used by EPA regarding fabric filter retr ofits in the modeling done in support of the final rule.

Comment 47: Commenter 17701 points out that their organiza tion members have a history of supporting cost-effective ener gy efficiency measures and are lead ers 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 co st of compliance s how much of the cost is associated with acid gas controls, which the commenter believes will have a strong impact on Indiana coal industry. The commenter considers the decision to regulate acid gas to be incorrect because the costs are more than what is necessary to protect public health.

Response to Comment 48: The EPA’s response to comments conc erning 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 faci lities will be able to sell or trade coal ash/coal combustion residuals despite possible ch anges that could occur in the sodium content of the ash due to new emission contro l technologies being required. Incr eased sodium could render the ash unable to be sold and lead to coal ash manageme nt costs in addition to lost revenue. Commenter 18500 points out the EPA identified 93 GW of capacity that it expects to utilize ACI to meet the proposed requirements. This commenter states that the benefici al reuse market for fly as h tops $2 billion annually, so the use of ACI would risk eliminating the mark et and forcing landfilling of these residuals at a dramatic increase of operating cost. The commenters be lieve these considerations should be included in the costs.

Comment 2 : Commenter 17754 states the limitations placed by the proposed rule on the sale of coal ash potentially interferes with broade r environmental considerations becau se they may impede the continued beneficial use of coal ash for the reclamation of abandoned mining lands.

Comment 3 : Multiple commenters (17621, 17758, 17754, 17775, 17821, 17868, 17881) discuss the use of sodium-based DSI and the impact it could have on marketability and beneficial use of fly ash in concrete, wallboard, asphalt products, bridge constr uction and mine reclamation. The commenters state that around 134 million tons of coal combustion residuals are currently generated every year and 56 million of these are recycled in these applications. The loss of these uses, the commenters say, will cause the coal ash/coal combustion residuals to be disposed of instead of used beneficially, causing economic, operational and environmental burdens. Coal-based faci lities 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 incertain applications to assure high-quality products, such as an appropriate alkali limit for use in concrete to avoid expansion and cracki ng. The commenters explain that the sodium-based sorbent inje ction technologies cause fly ash to exceed the appropriate alkali criteria, exceed necessary carbon co ntent, and are soluble, making itunsuitable for use in ready-mix concrete. The commenters go on to explain that sol ubility is also increase d, 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 savi ng virgin resources and reducing energy consumption, reduci ng GHG emissions and the need for land disposal and ask that the forfeiture of environmental benefits of coal ash/coal combustion residuals be assessed and considered in overall policy evaluation. Comment 5: Commenter 17821 reports that 3 million tons of coal ash/coal combustion residuals is beneficially reused by their organization annually, but this will end if they must install sodium-based DSI or ACI. This will lead to loss of jobs and an economic impact on the utility plant and end users of the coal ash/coal combustion residuals.510 Response to Comments 1 - 5: Multiple commenters declare that DSI and ACI controls contaminate coal ash/coal combustion residuals , thereby rendering the co-mingled material unmarketable. The EPA notes (from the comments submitted) markets purchased56 million tons of the 134 million tons of coal ash/coal combustion residuals – a fraction of the total coal ash/co al combustion residuals generated. Removal of this entire quantity due to contamination from the marketplace can be adequately satisfied by the remaining coal ash/coal combustion residual s produced. By the comments submitted, not all coal ash/coal combustion residuals gene rated 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 fl ow rates, this may or may not render ash unmarketable. The EPA concludes ne gligible impacts to downstream co al ash/coal combustion residuals end-users market.

As for coal ash/coal combustion residuals producer s, only 42 percent of ash sells to the market (56 million tons of 136 million tons) thereby making it a mi nor revenue stream for an EGU. As mentioned before, depending upon ACI and DSI flow rates in conj unction with coal ash/co al combustion residuals buyer’s specification, the ash may re tain marketability. As for contam inated ash, a station’s owner may install a secondary particulate captu re device dedicated to removal of DSI absorbents or activated carbon downstream of existing PM equipment. This sec ond PM device preserves coal ash/coal combustion residuals ash sales while reducing waste volume gene rated. Finally, for those E GU’s electing to dispose of the contaminated ash, the EPA m odels 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 in jected by DSI and ACI controls will contaminate CCR, particularly fly ash, to such an extent that the co-mingled mate rial 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 collecti on of injected sorbent down stream of the existing PM collection device. This modeling assumption incurs th e 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 AC I remain economic for many units even with this conservative cost assumption, the EPA concludes th at there will likely be minimal impacts to the downstream CCR end-user market. Furthermore, a lthough the EPA based the costs and performance estimates of DSI on use of Trona, the use of other reagents can mitigate or even avoid this problem altogether. Sodium bicarbonate has been shown to be more effective than Trona, which would reduce the sodium content of ash considerably. Activated lime hydrate is another alte rnative to Trona that would avoid the concern about sodi um solubility altogether. The CCR marketplace sets specifications for allowable contaminate levels and these specificat ions vary based upon the ultimate purpose of the fly ash. Depending upon ACI and DSI flow rates, the fly as h may or may not be rendered unmarketable. In some cases the fly ash will remain acceptable for the original purpose; in some cases it may no longer be acceptable for the original purpose, but it will be suitable for other purposes. Regarding any lost revenue due to contaminated ash issues, the EPA observes that almost all of an EGU’s revenues are derived from electricity sales, with ash sales re presenting a very minor income stream at risk to demand forces within the downstream market. Avoided disposal costs are of ten more significant than any CCR revenues, and if the fly ash can be repurposed for a less valuable pur pose, 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 ru le for additional discussion of DSI.511 As for activated carbon contamination issues, pr oper location of the inje ction point will prevent contaminating salable by-products; note an additional PM capture device may be required for collecting Hg-laden activated carbon downs tream. An SCR with WFGD c onfiguration burning fuels with sufficient halogen content will oxidize Hg in th e SCR followed by capture in the downstream WFGD thereby eliminating the need for ACI. The dissolved water-soluble Hg species is easily separated in the gypsum dewatering/washing process

Comment 6 : Commenters 17868 and 17911 express concern that coal ash may be designated as hazardous waste under RCRA (Subtitle C), causing state and municipal governments to feel compelled to remove and remediate the coal ash fill from under buildings, at landfill, and under highways. These costs are not considered in the estimated cost fo r the proposed rule. The commenters estimate coal ash disposal costs as hazardous wast e to range from 5% to 24% of a municipal government’s revenues. Commenter 17408 expresses concern about increasingly toxic fly as h as a result of using carbon injection to comply with the rule.

Response to Comment 6: Federal statute limits MATS to stati onary source emissions (see the preamble for the final rule for applicability). As for contam inated ash, a station’s owner may install a secondary particulate capture device dedicated to removal of DSI absorbents or acti vated carbon downstream of existing PM equipment. Issues regarding CCR remedia tion 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 bur ning source to meet the HCl limit which may not be realistic. Wet scrubbers are likely to be necessary and will increase complia nce costs and the number of plants to retire since th ey cannot afford compliance. So me commenters (17765, 18033, 19114) state that the EPA needs to examine what portion of the estimated 56 GW of the ex isting fleet expected to install DSI instead of scrubbers may realistically do so to more accurately estimate costs because the commenter believes that cost of complying with ju st 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 w ith DSI alone and no measurable health benefits. Commenter 19114 states that few coal-fired units use DSI for any pur pose and none have been identified that employ DSI for HCl control. Given the lack of practical experience in the indus try, the commenter believes the EPA should revisit the application and pe rformance attributes of the tec hnology or risk understating the potential costs and number of induced unit retirements.

Response to Comment 7: DSI is commercially proven for acid gas control as vouched by 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 tec hnology. DSI systems have been in service for more than 20 years as an effective t ool to reduce acid gas levels. SO2 and HCl emissions are typically controlled t ogether. In some industrial applicatio ns, HCl may need to be controlled512 separately. Current and impending legislation are th e drivers in determining the required emissions levels. DSI is a cost-effective soluti on to control these emissions.”

As discussed in the preamble, the EPA has used very conservative assumptions in modeling the projected use of DSI technology. See the preamble for the final rule fo r a more detailed discussion of DSI.

Comment 8: Commenter 17758 agrees that DSI can be used for compliance at many units cost effectively, but strongly disa grees with the assumption underl ying 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 th at define the HCl floor, only 15 units currently use DSI, and only fi ve of those units use DSI without FGD.

Response to Comment 8: The EPA does not believe that DSI and dry scrubbers will be the only compliance options for control of acid gases, and utilities will choose comp liance pathways based on a variety of considerations and avai lable technologies. DSI is a comme rcially available technology and the EPA believes it will play an important role fo r achieving compliance. See preamble for further discussion on DSI and other compliance options.

Comment 9 : Commenter 16469 explains that DSI is applic able to smaller units burning low-sulfur subbituminous coal. The commenter states that operational performance systems using sodium bicarbonate indicate SO 2 removal rates in the range of 20-60%, which is below the >90% SO 2 removal typically associated with wet scrubbers. The commen ter includes a table show ing removal rates for HCl and SO 2 at increasing bicarbonate flow rates in th e range of 75-95% for HCl and 20-60% for SO 2 . The commenter reports that anal ysts believe that DSI is likely to be used by smaller units, with larger unit installing scrubbers. The commenter also believes that additional controls may be needed to address future regulations which could entail re trofit 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 logistically cumbersome to maintain for smaller units.

Response to Comment 9: See the preamble for the final rule for a discussion of DSI.

Comment 10 : Commenters 17620 and 17648 report that th e ACI and DSI technology required to comply with the proposed rule have existed fo r many years. Commenter 17620 states that these technologies require little capital for construction and normally invol ve installation sc hedules of less than 12 and 24 months, respectively while FGD a nd 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 follow ing past regulations bei ng passed. The 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 es timates add 98 GW of ACI and 26 GW of new SCR for NO X control. Commenter 17648 confirms thatACI is a feasible control technology for Hg emissions, regardless of the control tech nologies presently used to control for PM, SO 2 or NO X and gives examples of how this can be done. The comm enter also points out that regulation often drives development of cheaper, more efficient controls. Th e commenter confirms that technologies exist to achieve the reductions called for by the proposed ru le. The commenter believes that sources can513 reasonably expect to be able to a lter 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 th at the EPA’s analysis underestimates the number of units that will need to install wet or dry FGD controls to meet the proposed acid gas limits. The commenter says that DSI is a mature technology that is well suit ed for units that burn fuels with lower or mid-level sulfur contents and is among the viable options for a number of sources to achieve the proposed HCl limits. The commenter points out that 73% of the sources with HCl emission data in the ICR database already achieve the proposed HCl limit and several of them do so using DSI. The commenter goes on to list coal-fired units that control SO 2 using DSI.

Response to Comment 11: The EPA thanks the commenter for the information provided in support of the proposed rule.

Comment 12 : Commenter 17702 acknowledges that they have compliance options to meet the proposed requirements, such as adding carbon injection or switching to a wet sc rubber. However, the commenter feels this will add additional costs and defeat the environmental objectiv es that led to the selection of their air pollution control system, such as conservi ng water with a dry scrubbe r as opposed to a wet scrubber and finding a way to use the calcium byproducts. However, the proposed emission limits will require ACI, which will interfere withthe ability to sell the byproduct.

Response to Comment 12: Although wet scrubbers (WFGD) use considerable amounts of water, approximately 90 weight percent of the water can be recovered in a gypsum slurry dewatering process and returned to the system. Wate r used for quenching incoming flue gas to the wet scrubber, can be minimized by lowering flue gas temperatur es 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-p roducts; note an additional PM cap ture device may be required for collecting Hg-laden activated carbon downstream. An SCR with WFGD c onfiguration burning fuels with sufficient halogen content will oxidize Hg in the SCR followed by ca pture in the downstream WFGD thereby eliminating the need for ACI. The dissolved water-soluble Hg species is easily separated in the gypsum dewatering/washing process.

Current scrubbing technology captures MATS acid gase s with superior effectiveness relative to SO 2 ; 20 as a result, the EPA does not anti cipate 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 contro ls may be required in some cases. 22 Where additional controls are needed, the EPA believes that units with dry scr ubbers with fabric filters may choose ACI, but they may also find other approaches effective. In manycases, especially bituminous coal units, high co-

20 NESCAUM report; “Control Technologies to Redu ce 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 Redu ce 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 co als, capture can be enhanced with bromide addition. Experience has shown that addition of oxidizing agents (i.e., br omide) and/or the use of sorbents designed to mitigate or avoid the adverse effects of ac tivated carbon on fly ash, including mineral-based sorbents, are available and effective. 23 As a result, the EPA believes that facilities with dry scrubbers are especially well suited to comp ly with the rule at re latively low expense.

Comment 13 : Commenters 17736 and 19114 question the effec tiveness of DSI to control acid gas emissions from coal-based EGUs and point out that no such units have been identified as employing DSI for HCl control. The commenters have experience inst alling Trona injection systems on coal-fired units and understand the shortcomings of DSI in jection. As such, the commenters find SO 2 removal by DSI to be too costly and cumbersome to be practically applied. Specifically, the commenters find the nozzle pluggage and antagonistic effects on ESPs would make achieving HC l and PM limits difficult over a 30- day period. Commenter 19114 questions the EPA’s “D ocumentation 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 by the EPA is a simple slide presentation about a single test, and lacks technical specifics that allow the data to be extr apolated 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 wo rries that there could be potential cost premiums for affected units if they are a ll forced to rely on a single vendor for the required technology and points out that the testing reports used by the EPA do not evaluate potential operations concerns. The commenter also states that the co sts associated with maintaining a DSI system due to pluggage and antagonistic effects on ESPs would make achieving bot h the HCl and PM limits very difficult to achieve over a 30-day operating period. The co mmenter calls on the EPA to expa nd the quantity and quality of their review.

Response to Comment 13: The EPA has determined that DSI is an effective acid gas control technology since MATS acid gas removal exceeds 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 substantially less capit al investment than a unit em ploying a wet or dry scrubber. 25 However, a DSI system’s operating costs tend to exceed a wet or dr y scrubber for high sulfur fuels. As a result, the EPA’s IPM modeling limited the DSI retrofit opti on to units combusting fuel less than 2.0 lb SO 2 /MMBtu. Pluggage issues result fr om poorly designed systems for powdered solids conveyance. A variety of causes can lead to blockage; for exam ple, poorly designed piping systems, inappropriate storage practices, incorrect system operation, plus others. Similar problems arose and were solved in analogous industries of food processi ng (wheat flour, powdered sugar), c oncrete (dry Portland cement), and pharmaceuticals etc. regarding dry powder materi al transfer. The EPA has noted that there are commercially available solutions to address these issues. 26 Pluggage problems at a particular facility do

23 Hizny, W., Magno, G., Yang, X., “BASF Mercury So rbent ZXTM for Control of Coal-fired Power Plant Hg Emissions,” Paper # 176, Power Plant Air Pollutant Control “MEGA” Symposium, August 30 – September 2, 2010, Baltimore, MD
24 NESCAUM report; “Control Technologies to Redu ce Conventional and Hazardous Air Pollutants from Coal-Fired Power plants” March 31, 2011, p. 22
25 ibid, p. 13
26 UCC web site; DSI FAQ #3 Plugging Issues. We b site: http://unitedconveyor.com/dsi.aspx515 not disqualify DSI as a commercially available co ntrol technology. With re gard 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 fina l rule for a further discussion of DSI.

Comment 14 : Commenters 17758 and 18033 discusses the EPA’s acknowledgement that if DSI does not achieve the required HCl reductions , utilities will need dry or wet scrubbers to achieve compliance, which the commenters believe will prompt more unit retirements. Commenter 17758 also mentions that the cost for DSI varies from $4/MWh to $15/MWh and there are few supplie rs of DSI technology, especially the Trona. Commenters 17758 and 17775 cite difficulties with the Trona supply with estimates of costs to deliver Trona to the eastern U.S. as high as $200/to n 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 in creased Trona supply difficult to achieve. Finally, the commenters note that units using DSI or ACI often need PM c ontrol downstream, such as a baghouse or ESP and a baghouse typically takes 36 months to install and costs $200/KW. Overall, th e commenters question the cost-effectiveness of DSI, quoting BP C as saying that, “...capital costs for an alternative, dry sorbent injection are significantly lower. On a levelized co st basis, however, the difference is far less significant...” Commenter 17781 agrees with this conclusion and says that while DSI can be economic with low sulfur fuels and/or operated over short time periods, many EGUs will need to install spray dryer adsorbers (SDAs) in lieu of using DSI, wh ich means longer lead times for procurement and installation of at least a year.

Response to Comment 14: The EPA disagrees with the commenters and does not expect that scrubbers are necessary solely for acid gas control under th e MATS rule. The EPA has analyzed the supply of Trona and sodium bicarbonate and determined that it is ample, as soda ash (a product of mined Trona) is already used extensively for other industries (such as glass manufactur ing, detergents, etc.) that need a reliable supply. Trona is a very reactive substance, and relatively small amounts are required to control HCl. Trona DSI has also been shown to improve ESP performance, so that a fabric filter is generally not necessary unless otherwise needed for PM control. As discussed in the preamb le, recent testing shows that trona DSI control of HCl with an ESP is very n early as effective as with a FF. Facility owners may choose to install scrubbers for control of acid gas; however, th is does not change the EPA’s determination that other technologies are available and can be used to co mply with the rule at reasonable cost and in the time frame of the rule. Also see the preamble for the final rule for a further discussion of DSI.

Comment 15 : Commenters 17765 and 18033 report that privat e sector estimates of retirements are higher than the EPA’s estimates because of the unproven effectiveness of DSI, the lack of reliability of the reagent supply chain, the lack of industry experience w ith the technology and the potential impact of dispatch. These concerns lead to retirement es timates of 50 to 100 GW. Commenter 17765 believes that without further testing to show that DSI technol ogy can be relied on for compliance, few utilities will choose it. The commenter finds the EPA’s compliance timeline makes it difficult for utilities to obtain information necessary to make deci sions about control tec hnologies or unit retirement. The commenter also points out that many of the 56 GW capacity units the EPA estimated would choose DSI will not have that option due to overlapping CAA rules.

Response to Comment 15: The EPA disagrees with the commenter s’ assumptions. There have been numerous private sector studies that examine reti rements due to several EPA rules that have been proposed or finalized over the past2 years. Many of these studies were based upon assumptions of what a rule might require prior to its proposal or fina lization, and the assumed requirements were generally516 more stringent than the actual requirements proved to be. Alth ough the EPA’s modeling for MATS predicts that some units will choos e DSI, the EPA recognizes that some of these units may not actually do so, for a variety of reasons that may involve owne r preferences and site sp ecific circumstances. Also see the preamble for the final rule for a further discussion of DSI.

Comment 16 : Commenters 17775 and 18037 discuss various adverse consequences of DSI use, pointing out that it can hinder comp liance with Hg and PM limits as the injected reagent adversely affects baghouses, and requires that three times the normal amount of ACI be used to achieve the same level of Hg control, as well as leading to the mission of a visible brown plume from the high sodium
content.

Response to Comment 16: The EPA is aware that there is so me data suggesting DSI can adversely impact ACI performance. In particular, the Presqu e Isle tests where this was observed were for SO 2 control, and the Trona treatment ra te for those tests was therefore hi gher than would be necessary for control of HCl for PRB fuel. PRB fuel typically has low HCl emissions and likely will not need additional controls for HCl in most cases. On th e 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 adversely affects PM and Hg control. Insufficient bag house capacity or exce ssive sorbent injection rate can adversely affect PM control performance. 27 An improper operating temperature redu ces activated carbon’s ability to capture Hg 28 while high concentrations of SO 3 compete with mercury for capture. 29 DSI systems failing to remove sufficient SO 3 negatively impact ACI system performance. 30 Hg speciation exiting the furnace significantly impacts controls selection and performance, with multiple factors affecting speciation (e.g., fuel constituents, halogen presence, installed emissions controls, and temperature). 31,32 ESP performance typically improves with sodium based sorbents; on the other hand, a calcium based species tends to negatively impact operation. 33 The brown plume phenomenon apparently 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 treatme nt rate needed for HCl removal. Formation of a brown plume appears to be an even t too infrequent to disqualify DS I as a control scheme within the MATS. Represented by the Presque Isle tests, one system 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 Ibid., p.A-8
29 Ibid.
30 Ibid.
31 Solvay Chemicals publication “Mercury (Hg)”
32 Tutorial: Mercury Chemistry in Boilers and Me rcury Control Technology (Part 1) by C Senior, Reaction Engineering Intl., 30 thInternational Technical Conference on Coal Utilization & Fuel Systems; April 17-21, 2005
33 UCC web site; DSI FAQ #1 ESP Performance. Web site: http://unitedconveyor.com/dsi.aspx
34 Sjostrom, S.,Senior, C., Durham, M., Bu stard, J., “INTEGRATED MACT COMPLIANCE PLANNING,” http://www.adaes.c om/PDFs/presentations/AQVIIIIntegrated%20MACT%20planning.pdf517 over 30 other DSI systems did not generate a brown plume. 35 Also see the preamble for the final rule for a further discussion of DSI.

Comment 17 : Commenter 17775 explains that the assumption that an adequate supply of dry sorbents will be available is not a good one. The commenter explains that sorbent production will need to increase by 10 to 20 times in order to meet the EPA’s projected DSI demand. This is a problem, the commenter explains, because the industry is not going to spend hundreds of millions of dollars on plant expansions without a secure market, but until the util ities decide to install DSI, they will not know what the demand will be. Once a commitment is made, it wi ll take more than 18 months to increase sorbent production to necessary levels to supp ly all the projected new DSI units.

Response to Comment 17: Multiple comments submitted claim insufficient absorbent (or sorbent) production capability exists to serve the DSI market. The agency researched th is issue and determined that DSI utilizes the following absorbent materials for pollution control: Trona, sodium bicarbonate, sodium carbonate (common name: soda ash), calc ium carbonate, and calcium bicarbonate - sodium based chemicals are favored over calcium based ma terials due to economics. Trona is mined in Wyoming as a naturally occurring ore by four co mpanies with mining operations extracting 16.5 million tons in 2010. 36 Production peaked at 18.1 million tons in 2006. 37 In 2010, 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 abso rbent for DSI pollution control. Exports claimed onehalf of the 10 million tons of soda ash produced in 2010. 39 Currently, the industry (ANSAC) alleges unfair foreign practices negativ ely impacting domestic exports. 40 Considering the excess Trona mining capacity, the fact that nearly 50 pe rcent of Trona-based derived soda ash is exported, and the fact that alleged foreign competition practices negatively imp act exports - the agency concludes that Trona supply is not an issue.

The EPA disagrees with commenter’s estimate and has concluded that current U.S. Trona production may already have adequate surplus capacity to meet projected DSI demand. See the preamble for the final rule for a further discussion of DSI.

Comment 18 : Commenter 17790 explains thatthe EPA’s analysis of em ission reduction technologies required by their facilities to comply with the propos ed rule is erroneous because it assumes they will install fabric filters on all coal-fired units. However, the commenter’s analysis showed that DSI is only economical on units which are able to achieve comp liance-level reductions of HCl using ESPs, and spending additional money on fabric filters is not economical for them.

Response to Comment 18: The EPA’s IPM modeling for the MA TS final rule now takes into consideration that there are less co stly options than FF for PM complia nce, particularly the upgrading of

35 “Comparison of Sodium Bicarbonate and Trona for SO2 Mitigati on at a Coal-Fired Plant” by Kong & Vysoky (Solvay Chemicals) Electric Po wer 2009 presentation, May 12-14, 2009. ref: http://www.solvair.us/s tatic/wma/pdf/1/5/8 /4/0/SO2_Mitigation-Electric_Power_2009.pdf
36 http://www.wma-minelife.com/trona /TronaPage2/tron a_production.htm
37 ibid
38 http://www.onrr.gov/ONRRWebStats/StateAndOffs horeRegions.aspx?state=WY&yeartype=FY&year= 2010&dateType=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 analysis has conservatively has not incorporated. For these reasons, many units that we re previously modeled as installing a FF may find that only the installation of DSI upstream of the existing ESP may be needed for MATS compliance. Also see the preamble for the final rule for a further discussion of DSI.

Comment 19 : Commenter 18033 requests that the EPA addr ess integrated planning after the proposed NSPS for GHS from EGUs are issued to create a cumulative cost anal ysis. 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 fe w years later. The commenter went on to explain that not every coal type within the projected 56 GW e xpected to install DSI w ill 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 NM A revised cost estimates for DSI.)

Response to Comment 19: Issues regarding a NSPS for GHG from EGUs are not within the scope of the MATS rule, although the EPA does intend to seek to coordinate requirements under today’s rules with those of the pending NSPS for GHG emissions. Also see the preamble fo r 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 charac teristics. The commenter quotes NESCAUM “Control Technologies to Reduce Conventional and Hazardous Ai r Pollutants from Coal-Fired Power Plants,” March 31, 2011, as estimating capital costs and storag e silo costs for DSI at around $20/kW. The report also cites approximately 90 coal uni ts currently using DSI, showing th at it is effective at reduction HCl by more than 99% and works efficiently with a downs tream fabric filter or ESP. The commenter also quotes SOLV Air, a Trona distributor, as refuting claims that Trona is likely to be unavailable by saying “hundreds of years of reserves of Trona are avai lable.” Commenter 17621 agrees with the idea of various options for sorbents used with DSI technol ogy and explains the various pros and cons of some options. The commenter reports on a Trona injection te st that resulted in a visible brown plume and degradation of Hg removal by ACI. The commenter e xplains that while hydrat ed lime injection would remove SO 3 without the adverse impacts of Trona, it is unkn own if the hydrated lime could meet the proposed limit at any injection rate or if it would increase pr essure drop across a baghouse to unacceptable levels. The commenter also mentions th e 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 preheate r pluggage in some cases. The commenter describes a field test program in which Tr ona or sodium bicarbonate was us ed to achieve high HCl and SO 2 removal rates without pluggage problems. The commenter explains that the site has an atypical system including both hot- and cold-side ESP, and so rbent was injected upstream of the hot-side ESP which may have minimized pluggage and plumes. This commenter believes that further investigations are needed of DSI over a range of power plant designs, coal types and air pollution controls to fully evaluate HCl and SO 2 removal performance and impacts on balance-of-plant operations.

Response to Comment 20: The EPA thanks the commenter for the information provided in support of the proposed rule.519 Comment 21 : Commenter 18424 considers the EPA estimates for control technologies to be suspect since they may not be appropriate for use by many power plants, depending on the coal burned and the impacts DSI will have on PM and Hg emissions. The commenter questions the method of developing emission rules for each pollutant independently without considering how one c ontrol device may impact the control of other pollutants.

Response to Comment 21: The EPA disagrees with commenter. The EPA evaluated the effects of DSI on different fuels and considered the effects on Hg and PM emissions. See the documentation for IPMv4.10_MATS, and the preamble for the final rule for a discussion of DSI. It is important to note that the EPA established emission standards based on th e best-performing sources in each subcategory for the different emitted HAP. The EPA is not specifying th e use of a particular control device, leaving it to the discretion of the source owner or operator to select controls that will meet the applicable standards considering the characteristics of the particular source.

Comment 22 : Commenter 18023 disagrees with the assumption th at 56 GW of coal plants will not need a FGD system because DSI will suffice at a lower cost and shorter timeline for installation. The commenter states that even if DSI can achieve the HCl removal levels require d to comply, it would not do so under all operating conditions. The commenter states that the EP A’s model predicted that several of the commenter’s power plants would not achieve continuous compliance with the proposed acid gas limit using DSI. (Commenter includes Figure 6 s howing necessary technology to achieve compliance with proposed HCl limit.) Therefor e, the commenter believes the costs and timeline on which the proposed rule is based are erroneously low. The comm enter 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 a ll units. The use of wet scrubbers will also drive up compliance costs so the commenter asks thatthe EPA update cost assumptions to account for these requirements.

Response to Comment 22: The EPA disagrees with the commenter . The EPA has determined that wet scrubbers, while beneficial for acid gas control, ar e not necessary for compliance with the MATS rule. Also see the preamble for the final rule for a further discussion of DSI.

Comment 23 : Commenter 17775 states that the proposed rule will require large-scale installation of new control technologies to meet the Hg, HCl and total PM limits. The commenter restates the EPA estimates that the proposed standards will require the installation of 93 GW of ACI, 56 GW of DSI, 26 GW of wet FGDs and dry FGDs, 166 GW of FF and 5 GW of SCR, and that this $46 billion (in 2007 dollars) of control equipment can be installed in 3 years. The commenter considers the EPA’s estimate to be unreasonable because it is based on inco rrect assumptions about the efficacy of DSI.

Response to Comment 23: See the preamble for the final rule for a discussion of the efficacy of DSI. Also see the RIA for projected controls retrofits a nd costs as updated in EPAs analysis for the MATS final rule.

Comment 24: Commenter 17775 questions the EPA’s conclusions about the effectiveness of DSI since they are based on limited information and incomplete analyses. The commenter points to ICR data from plants using DSI systems to see that only 11 of the 28 units using DSI do so to control SO 2 and only two of those 11 units report ICR emission s data that show compliance with the proposed existing source HCl limit. In fact, those two cases the units burn low chlori de fuel and do not need to install DSI to meet the HCl limit. Therefore, the commenter states that ther e 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 by the EPA to support its views on DSI are lacking information on how DSI may affect PM or Hg emissions. Also, the commenter sa ys 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 point s out that the flue gas make-up in the case study was not representative of low sulfur coals.

Response to Comment 24: The EPA disagrees with commenter’s conclusions. Also see the preamble for the final rule for a further discussion of DSI.

Comment 25 : Commenter 18963 notes that there have been no commercially demonstrated applications of DSI for the control of HCl from coal refuse-fired CFB units. Further, even to the extent that it is technologically feasible to use sorb ent injection to c ontrol 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 recl aiming lands and protecting and enhancing streams damaged by acid mine drainage.

Response to Comment 25: See the preamble for the final rule for a further discussion of DSI.

Comment 26: Commenter 16849 states that even under revi sed averaging periods, Trona and DSI are not a viable option for Empire, as is incorrectly st ated by the EPA (“IPM Parsed Results - Policy Case,” Unplanned DSI Installations by 2015 includes Asbury: 2076_B_1).

Response to Comment 26: The EPA believes that DSI has the pot ential to be a useful and costeffective control technol ogy option for many units. We also understa nd that it is not an appropriate option for all facilities. Ov erall the EPA believes that the technology is most applicable for units burning lower-sulfur content coal (including, pot entially, low-sulfur bituminous coal).

3. Electrostatic precipitators.

Comment 27 : Commenter 17622 explains that ESPs are th e primary particulate collection equipment for many utility units and are designed to have su fficient Specific Collecting Area (SCA) to meet the proposed total PM emission limits. The commenter consider s it to be in the best in terest of the industry to retain existing plant assets as much as possi ble while complying with the proposed rules. The commenter explains that ESPs can be upgraded by im proved maintenance/repair, parts replacement, etc., or rebuilding to increase SCA. However, the comm enter points out that the potential for upgrading existing ESP installations to meetthe proposed limits depends on the age and design of the existing equipment. Not all equipment was designed to achi eve 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 pot ential to include other reagents for Hg control. There is an impact on the ID fans and structure to convert to a fa bric filter, but much of the existing support structure and ducts/casings could be us ed. The final solution suggested by the commenter is the addition of a wet ESP to an existing wet FGD to capture filterable and condensable particulate. The commenter offers the Dallman and HL Spurlock plants in the ICR PM database as examples of this approach and explains that this alternative has the advant age of using existing air pollution control equipment with low increase in pressure drop.521 Response to Comment 27: The EPA thanks the submitter for the information provided in support of the proposed standard MATS and notes that this in formation corroborates th e EPA’s views about the availability of multiple compliance options for many affected sources.

4. Timeline.

Comment 28: Several commenters (17627, 17655, 17911, 19114) express concern over the compliance timeline of the proposed rule. In particular, the numb er 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 origin ally estimated to cost $33 million actually cost them $61 million entirely due to the fact that all the CAIR-affected un its were competing for the same design, material and labor pools during a compressed construction schedule to comply. The commenter expects the same thing to happen to a greater extent in response to the proposed rule.

Response to Comment 28: Commenters recalling price esca lation during CAIR’s implementation phase understandably convey concerns regarding th e EPA’s cost estimating; however, the present economic situation does not reflect current national or global condi tions. During CAIR implementation, high global demand for construction co mmodities (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 will compete for work to utilize idle resources. As an indicator, demand for power plant construction labor decl ined 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 by 2014. 42,43 Timeline compliance date attainment and available resources are addressed in the preamble for the fi nal rule and Response to Comments section 5C01 “Compliance Dates.”

Comment 29 : Commenter 17627 explains that facilities muststart 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 unrea sonable before the final requirements are known and compliance plans are designed, and permitting authorities generally do not allow any construction preparation until permits are granted.

Response to Comment 29: The agency believes that the MATS proposal offered sufficient regulatory detail to inform prudent retrofit planning activities, some of which at least c ould be commenced without further delay. To cite an example, a station ow ner 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-f ired-power-plant-to-re ceive-emissions-controlsystem.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-d eal-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, especially those burning eastern bituminous coals, may have to install a wet FGD which pr esents challenges in cost and installation time. The commenter es timates 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 es timates and ability to comply within 3 years incorrect, the commenter believes.

Response to Comment 30: The EPA disagrees with comments wa rning wet scrubbers are necessary for units burning eastern bituminous coal. The EPA exam ined this issue and determined DSI adequately suffices for units burning low sulfur eastern bitumi nous coal. The EPA’s IPM analysis for MATS limits DSI retrofit controls for compliance to fuels containing less than 2 lbm SO 2 /MMBtu. Timeline, feasibility, and emissions control cap ability issues are discussed in th e preamble for the final rule, and Response to Comments section 5C01 “Compliance Dates.”

Comment 31 : Commenters 17775 and 17904 discuss the many st eps involved in adding controls to coal-fired EGUs, such as initial design, develo pment of project specifications, procurement, identification of bidders, solicitation, review of bids and contract ne gotiations, permitting, landfill issues, obtaining financing, final design, mobilizati on of workforce, construction, process tie-ins and startup testing. Commenter 17775 includes a memo (J. Edward Cichanowicz, “Feasibility of Retrofitting Fabric Filter Particulate Matter Control Technology to the Elect ric Generating Unit Inventory as Projected by EPA” (July 2011) Attachement 12 of EPA-HQ-OAR-2009-0234-17775) showing estimates of 48 months to install a single scrubber for a large unit, 50 months for a single scrubber at a small unit, 51 months for installation of two sc rubbers and 54 months to install th ree or more scrubbers at a single facility. The memo also estimates that not all existing EGUs that need a new fabric filter will be able to meet a 3-year compliance schedule, and even if gi ven 4 years to comply, only 54% would be able to comply. The commenter also explains that time needed to obtain financing can vary greatly, with some regulated utilities needing to obtain approvals from their State PUCs to recover the costs, and some rural cooperatives needing to access the private market for funding. Commenter 17904 refers to Davis Cnty. Solid Waste Mgmt. v. EPA , 101 F.3d 1395, 1400 (D.C. Cir. 1996) wording that states the EPA’s MACT floor would “impose significant retrofitting costs th at [are] unreasonable given the limited additional pollution control that stricter st andards would achieve.” The comment er expresses concern over the high costs and short timeline for the necessary control retrofits.

Response to Comment 31: For discussion on the issues mentioned above, see the preamble for the final rule and Response to Comments section 5C01 “Compliance Dates.”

Comment 32 : Commenter 18039 questions the s uggestion that existing units be allowed to run for an additional year while a replacement is constructed, w ithout being subject to MACT standards for that year. The commenter agrees that this is a reasonable scenario for facilities that will use that year to construct a replacement unit with si gnificant long-term emission reducti ons. However, the commenter is

44 B&W press release June 29, 2011; “B&W to Design and Supply $54 Million Emissions Control System for Indiana Power Plant” ref: web site: http://www.babcock.com/news_and_events/2011/20110629a.html523 concerned that a facility in the process of building replacement pow er may decide to operate a highemitting unit for an additional year, specifically due to the extension. The commenter therefore objects to the extension for fear a large amount of pollutants will result. The commenter also asks that if construction replacement power lasts longer than the 1-year extension, th e final rule wording make clear that the older unit is not permitted to avoid MACT compliance beyond thatyear, even if the replacement is not yet on-line.

Response to Comment 32: Issues regarding compliance dates, extensions, state programs regarding agreements, replacement power construction, etc., ar e discussed in the preamble for the final rule.

Comment 33 : Commenter 18017 states that if the propos ed rule and other pending rules require installation of new control equipmen t costing hundreds of millions of dollars, the potential result could be early closure of their plant because the owners will be required to comply before they know whether the approvals necessary to operate after 2019 can be obtained. The commenters concern is that the EPA may establish final emission limits governing NGS PM emissions that are so st ringent that a new PM control device will be required with compliance date s before approvals can realistically be obtained. This would lead to high compliance costs and could jeopardize continued operation of the NGS facility with severe economic impacts on numerous Indian Tribes.

Response to Comment 33: The EPA will work closely with other regulatory authorities to support timely implementation of MATS.

5. One technology per pollutant.

Comment 34 : Commenter 17682 considers the EPA estimate of compliance technologies to be suspect because of the proposal of adopti ng an untested compliance technology to reduce sulfur emissions, and which may impact PM and Hg emissions. The comment er asks that the EPA refrain from developing emission rules for each pollutant independently w ithout considering how one compliance measure may impact the control of other units. The commenter belie ves this approach leads to cost estimates that do not adequately reflect the cost for other sources of energy that may be required to make up for lost coalfired generation. The commenter would like to see cost estimates that adequate ly reflect the ultimate cost increases that individual home owners will need to pay.

Response to Comment 34: The agency reviewed all technologies presented within the proposal for adequacy and commercial availability; moreover, independent publications and trade organizations confirms their capability towa rds 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 establishing 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 Redu ce 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.supportcl eanair.com/resources/studies/file/4-8-11- URSTechnologyReport.pdf
47 EPA-HQ-OAR-2009-0234-17622524 6. Dual liquid-powder sorbent technology.

Comment 35: Commenter 17721 discusses a multi-emission reduction technology called involving a dual liquid-powder sorbent (DLPS), which is particul arly effective in removi ng 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 co mmenter suggests that the effectiv eness of the DLPS system for highsulfur coals makes it a valuable revision to the pr oposed 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 a nd flexibility within the industry and asks that the proposed rule allow for a variety of Hg control systems.

Comment 36 : Commenter 17721 considers the proposed rule vague on the point of demonstrating compliance with the Hg emissions limit using a Hg CEMS or a sorbent trap monitor without installing ACI or DSI. The commenter suggests revising th e final rule to recognize DLPS technology as an available emission control technology for Hg and othe r HAP, or at least make it clear in the preamble that the use of a DLPS system in stead of, or in combination withother technology, is permitted. The commenter describes three power companies operating eight generating stat ions that have DLPS technology installed, with results of up to 98.7% Hg reductions. The co mmenter 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 comment er describes testing do ne between 2005 and 2008 and provides the results. (The commenter includes a table of “Full Scale Multi-Pollutant Test Results” in EPA-HQ-OAR-2009-0234-17721-A1.)

Comment 37 : Commenter 17721 questions the proposed ru le’s focus on ACI technology, which works differently from DLPS technology because ACI and DSI involve injecting a sorbent into the flue gas stream upstream of a PM control device to react w ith 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 suggested in the proposed rule. The commenter asks that the proposed rule be amended to allow DLPS technology as an available control technology for Hg, HCl and other HAP metals , and allow units equipped with DLPS or DSI to qualify for SO 2 emissions limits as an alternative to the HCl emissions limit.

Comment 38 : Commenter 17721 points out that the propos ed rule focuses on controlling acid gas emissions in the exhaust stack, while DLPS allows aci d 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 c ould be achieved by a scrubber.

Response to Comments 35 - 38: Multiple comments were receiv ed advocating control technologies that were not represented in the EPA’s compliance cost analysis of the MA TS proposal. The agency notes that control technol ogies mentioned within the proposal are ne ither an exhaustive nor an exclusive list; rather, these listings demonstrate proven availa ble technologies for industry sector compliance. The EPA is not selecting, nor precludi ng, any particular technologies in this rulemaking but is instead allowing each facility to determine its preferred m eans of compliance with the emission rate standards.

7. Retirements.525 Comment 39: Commenter 17731 questions the EPA’s view thatutilities can easily retire and replace units that are unable to comply with the new em ission limits. The commenter considers the option of replacing older units with more e fficient units to be risky because the utility may spend the time and money to build new coal-fired units only to find out that the units cannot comply with the stringent new unit emission limits.

Response to Comment 39: This issue is discussed in the preamble for the final rule.

8. Activated carbon injection and alternatives.

Comment 40: Commenter 17734 discusses the use of amende d silicates as an environmental and economical way to comply with existing and pe nding Hg regulations. The commenter describes amended silicates as a “drop-in” alte rnative that is often superior to partially activated carbon, at a cost competitive with ACI. The commente r explains that the amended si licates are added to the coal combustion gases upstream of PM control equipment to modify Hg into an inert and insoluble state. The commenter states that amended silicates have been designed to be compatible with concrete, allowing for preservation of fly ash value, and passes the EPA leachability tests. The materials have also been developed to avoid the sensitivity to SO 3 , so a high rate of Hg capture is maintained in ESPs. The commenter requests that the EPA revi se the proposed rule to clearly state that newly developed and commercially-available products besi des powder activated carbon can achie ve similar or better results under different or similar chemical mechanisms.

Response to Comment 40: Multiple comments were received advo cating control technol ogies that were not represented in the EPA’s compliance cost analys is of the MATS proposal. The agency notes that control technologies mentioned with in the proposal are neither an exhaustive nor an exclusive list, rather, these listings demonstrate proven available t echnologies for industry sector compliance. The EPA is not selecting, or precluding, any particular technologies in this ru lemaking but is instead allowing each facility to determine its pr eferred means of compliance withthe emission rate standards.

Comment 41 : Commenter 17761 reports a dramatic decrease in performance of an ACI system between the years of 2007 and 2009. Given this unexplained declin e, the commenter feels it is necessary for the EPA to review the longer term opera ting performance of control equipm ent when setting a Hg standard.

Response to Comment 41: Like any air pollution control technology, numerous parameters impact ACI performance with possible causes due to operational changes, equipment degradation, etc. The owner retains responsibility to maintaining their emissi ons control system and unde rstanding its operation to continuously achieve compliance. ACI is a proven t echnology for Hg removal with multiple successful installations. 48 This issue is addressed more fully elsewhere in the final rule record.

Comment 42 : Commenters 17796 and 17869 indicate that th e pollution control technology industry continues to develop new and more cost effec tive ways to reduce Hg emissions. Commenter 17796 discusses the DOE research on costs of applying activated carbon at vari ous 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 t echnology has shown that

48 NESCAUM report; “Control Technologies to Redu ce Conventional and Hazardous Air Pollutants from Coal-Fired Power plants” March 31, 2011526 implementation can be done by a majority of utilitie s, and the competitive mark etplace will continue to reduce the costs for these technologies.”

Response to Comment 42: The EPA thanks the commenters for the comments supporting the standard.

Comment 43: Commenters 17813 and 17816 state that the EPA fails to provide complete cost-benefit analysis of beyond-the-floor limit. Commenter 17813 considers this to be an underestimate, in part because more units will be impacted than predicted. The commenter sees the benefit for lignite beyondthe-floor limits to be smaller thanthe annual benefits pr edicted for Hg reductions, since there are fewer lignite units and they already comply with the floor limit.

Comment 44: Commenter 17930 states that the EPA failed to provide the proper cost-benefit analysis given the disproportionally high costof the beyond-the-floor limit comp ared to any potential gains. According to the commenter, the EPA’s estimate of annual cost of implementing the beyond-the-floor limit ($86.7 million) is far greater than the possible benefits of the beyond-the-floor limit. The EPA predicts that the annual benefit of Hg reductions for the en tire rule is merely $450,000 to $890,000 by 2016. (See Utility MACT Rule Proposal at 25078. Pri ce 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 sin ce lignite units would already be complying with a floor limit.

Comment 45 : Commenter 17904 questions the EPA assumpti on that a unit equipped with ACI and a fabric filter can achieve the beyond- the-floor standard with no additi onal cost. The commenter explains that such systems have performance limitations and will not achieve the proposed limit consistently, so alternative and additional controls will need to be considered. The co mmenter agrees with 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 establis hing actual costs of compliance, which would be prohibitive.

Response to Comments 43 - 45: A quantitative analysis of costs was included in two beyond-the-floor TSDs 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 filt ers consistently show hi gh Hg removal rates with a wide range of coals. The BTF limit may be achieva ble through other means, such as a wet scrubber with bromide addition. In other cases, halogen a ddition to promote Hg oxidation and capture may be beneficial. ACI is a proven, ma ture technology for capturing Hg. 49 Comments claiming BTF Hg emission rates for lignite fuels as financially im practical and technically unattainable are unfounded. Commercial 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 Redu ce Conventional and Hazardous Air Pollutants from Coal-Fired Power plants” p. 19, March 31, 2011

50 ICAC 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 ma y contain increased Hg levels a nd display greater Hg variability than PRB or bituminous fuels; however, these two asp ects do not make BTF emi ssion rates unattainable or financially prohibitive. ACI selec tively captures the oxidized form of Hg regardless of fuel source or rank. 53 Yet, the presence of SO 3 interferes with Hg capture and re quires 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 im pede ACI performance; under these circumstances, chemical addition to promote oxidi zation (such as a halogen, as cite d earlier) improves performance. Halogens can be inserted: pre-combustion (added to fuel), during combustion (furnace insertion), post combustion (gas stream injecti on) or through carbon impregnation. 55,56 Meanwhile, adjusting carbon injection rate will compensate for fuel Hg vari ability. Consequently, the EPA maintains current technology allows BTF Hg capture ra tes as proposed. See the preamble for the final rule for further discussion.

9. Coal rank/type.

Comment 46: Commenter 17757 explains thatcoal rank or type has an impact on the design and operation of boilers and associat ed control equipment. The commenter believes the EPA has not considered the costs of boiler modifications and c ontrol technology retrofits in the proposed rule with respect to the coal rank and related factors. The commenter be lieves these distinctions should be considered and points out that they were factored into the emission rates for the acid rain program and prior Hg proposals issued by the EPA.

Response to Comment 46: 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 47 : Commenter 17796 states that the cost and de gree of Hg reduction depends on coal type and additional costs to upgrade particulate polluti on control to accommodate additional particle loading from ACI. The commenter references a DOE study findi ng that western coal withlow chlorine levels emits higher amounts of elemental Hg, and is more readily controlled with ACI impregnated with bromine, with one example facil ity estimate of $26,200/lb of Hg controlled at 90% using halogenated activated carbon. The DOE estimated the beyond-the- floor option to be $22,496/lb of Hg removed. The most recent report cited states that “the ACI systems have the potential to remove more than 90% of the Hg in many applications based on results from NETL’s field testing program, at a cost estimated to dip below $10,000/lb of Hg removed. However while the re sults achieved during NETL’ s field tests met or exceeded program goals, only through experience gain ed during long term continuous operation of these advanced technologies in a range of full-scale co mmercial applications will their actual costs and performance be determined.”

Response to Comment 47: The EPA thanks the commenter for the comments submitted.

52 Assessment of Technology Options Available to Achieve Reductions of Hazardous Air Pollutants, URS Corporation, April 5, 2011, http://www.supportcl eanair.com/resources/studies/file/4-8-11- URSTechnologyReport.pdf

53 NESCAUM Report, op. cit., pp.19-20

54 Ibid. p.19

55 Solvay Chemicals publication “Mercury (Hg)”

56 ICAC Report, op. cit.528 Comment 48 : Commenter 17807 discusses the lower chloride coals ranging from 0.05 to 0.10% in the Illinois basin, but states that it would be difficult to obtain ne cessary 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 c onsider other coal sources to achieve compliance with the HCl limit, which will increase demand and impact long term availability of these coals and decrease fuel procurement flexibility and reliability.

Response to Comment 48: The EPA determined further fuel subcategorization is unwarranted. The EPA addresses subcategorization else where in the final rule record.

Comment 49 : Commenter 18033 quotes the EPA position stated in CAMR, “[a]t some point in the future, the performance of control technologies on Hg emissions could advance to the point that the rank of coal being fired is irrelevant to the level of Hg control that can be achieved....” The commenter states that while controls for Hg emissions have arguab ly reached this point based on the proposed MACT standard, this is not the case for acid gas control for higher sulfur coal s. If a well-cont rolled unit burning higher sulfur coals cannot meet the standard, the commenter believes the EPA needs to revise the proposed rule accordingly through further subcategorizati on to ensure that all coals are able to meet the applicable standards.

Response to Comment 49: The EPA determined further coal subcategorization is unnecessary for compliance since commercially available technologies for 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 subcategoriz ation issues elsewhere in the final rule record.

Comment 50: Commenter 17775 commissioned a consultant to conduct IPM modeling runs using control technology assumptions the comme nter considers to be more real istic than those chosen by the EPA. The modeling involved three runs to evaluate the consequen ces of the EPA’s decision to regulate all HAP, not just Hg. The commenter says the refe rence case was run assuming CAIR was implemented in 25 states and the District of Columbia, and one sensitivity run assuming that the proposed Transport Rule would be implemented with the proposed rule with only Hg emission limits. The final run was the same as the sensitivity run, except that the proposed rule was assumed to cover all HAP. The commenter states that the run results show that regulation of the non-Hg HAP adds approximately $10.5 billion to the total system costs in the fi rst years of compliance and over $8 billion annually in following years with the 2030 compliance cost difference at over $9 billion annually. Together with the proposed rule, the Transport rule was estimated to add $22.2 bill ion to total system costs in 2015, $21.1 billion by 2020 and $25.7 billion annually by 2030.

Response to Comment 50: The EPA has updated its modeling in the final rule, co mpliance costs are found in the RIA and the preamble for the final rule.

The agency received numerous comments regard ing independent modeling analysis 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 Lipinski, Leonard, Richardson; published by URS; April 5, 2011

58 Ibid.

59 NESCAUM report; “Control Technologies to Redu ce Conventional and Hazardous Air Pollutants from Coal-Fired Power plants” p. 19, March 31, 2011529 inaccuracies within their models which dramatica lly influence the basis of these comments. For a discussion addressing the limitations of industry performed modeling studies, see the preamble for the final rule.

Comment 51 : Commenter 19114 feels revisions are needed for the inputs to the IPM model. The commenter gives the SCR cost estimates as an ex ample, as they are below industry estimates for installed costs and should be increased by at least 20%. The commenter also states that it is unclear if the EPA is correctly accounting for allowance for fu nds 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 th e 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: IPM calculates fabric filter AFUDC correctly for a 2-year construction cycle; the typically anticipate d cycle for a fabric filter. 60 The B2 calculation descri ption (as illustrated on the spreadsheet view) is in error. The mathemati cal calculation actually pe rformed is: B2 = 6% x (CECC+B1) {incorrectly typed as: 6% x CECC + B1}.

Both ACI and DSI estimated costs calculations include all equipment from unloading to injection.

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 configur ation, 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 disagr ees that gas prices have the most significant impact on unit retirements and considers the exposure of a coal un it to future environmenta l constraints and potential expenditures to be the biggest fact or in retirements. As such, the commenter suggests the EPA include future regulatory constraints withinthe model or risk understating the impact of the rule being proposed.

Response to Comment 52: Besides retrofit controls , payroll, debt service, and maintenance, an EGU’s largest fiscal expense is fuel procurement with mark et conditions determining ope rational viability of an EGU. The EPA approached gas supply market c onditions conservatively. The agency has fully documented its assumptions and framework for mode ling natural gas in IPM for both the proposed and final MATS. This information can be f ound in Chapter 10 of the IPM documentation (http://www.epa.gov/airmarkets/progsregs/epa-i pm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of the na tural gas module, describes the ve ry detailed process-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 Methodol ogy FINAL,” March 2011, Project 12301-009, Perrin Quarles Associates, Inc
61 Assessment of Technology Options Available to Ac hieve Reductions of Hazardous Air Pollutants” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011
62 NESCAUM report; “Control Technologies to Redu ce Conventional and Hazardous Air Pollutants from Coal-Fired Power plants” March 31, 2011530 natural gas resources and reserves and to derive all the cost compone nts incurred in bringing natural gas from the ground to the pipeline. Also documented ar e the resource constraints, liquefied natural gas (LNG), demand side issues, the natural gas pipeline network and capacity, proce dures used to capture pipeline transportation costs, natu ral gas storage, oil and natural ga s liquids (NGL) assumptions, and key gas market parameters. Current and projected natural gas prices significantly impact anticipated coalfired retirements. IPM Natural Gas (NG) modeling is discussed in the preamble for the final rule.

Comment 53 : Several commenters (19536, 19537, 19538) discuss the EPA’s documentation of IPM modeling that shows the EPA found that the costs of complying w ith a 0.0001 lb/MMBtu HCl MACT limit, which would be achieved thro ugh installation of scrubbers or scrubber upgrades, installation of baghouses at fluidized bed boilers, and/ or DSI with baghouses to achieve SO 2 removal efficiencies of 92% to 96%, would be cost effective. The commente rs point out that the EP A did not account for the fact that numerous units will have to achieve the required level of SO 2 controls soon under other state or federal regulation to meet ambient air quality st andards. The commenter goes on to list additional findings by the EPA based on IPM modeling, and ag rees with the EPA’s assessment that the environmental and health benefits outweigh the costs, thanks to the cost-effective technologies and methodologies summarized.

Response to Comment 53: The EPA thanks the author for the comments submitted.

The EPA’s IPM modeling of MATS accounts for all finalized state and federal regulations. See RIA chapter 3 and “Documentation Supplement for EPA Base Case v.4.10_MATS – Updates for Final Mercury and Air Toxics Standards (M ATS) Rule” for additional discussion.

10. Difficulties with control technologies.

Comment 54 : Commenter 17702 acknowledges that they have compliance options to meet the proposed emission reduction requirements, such as adding carbon injection or switch ing to a wet scrubber. However, the commenter points out that these options will increase cost and defeat the environmental objectives because they will increa se water use and eliminate the sa le of the byproduct material from a dry fabric filter.

Response to Comment 54: The EPA does not anticipate units with fabric filters necessarily increasing water consumption because scrubber retrofit be comes unnecessary with the DSI option for rule compliance. Depending upon treatment rate and reagent (sorbent) select ed, ACI or DSI may impact fly ash sales; on the other hand, activ ated lime reagent eff ectively removes acid gases and should not adversely impact fly ash marketabil ity. Mineral-based Hg sorbents are effective and commercially available for overcoming concerns with activated carbon. 63 Additionally, see response to comment 4 (above).

Comment 55 : Multiple commenters (17868, 17912, 19213) state that the EPA did not address physical space and age-of-plant issues when setting BDT, MACT, and NSPS because it did not recognize that older coal-fired power plants have space constraints and may only be able to “build up” if they install a fabric filter. This means that smaller and older plants will not be able to comply with the proposed rule. Commenter 17868 considers the EPA’s projection that only3% of the industry’s co al-fired capacity will

63 Hizny, W., Magno, G., Yang, X., “BASF Mercury So rbent ZXTM for Control of Coal-fired Power Plant Hg Emissions,” Paper # 176, Power Plant Air Pollutant Control “MEGA” Symposium, August 30 – September 2, 2010, Baltimore, 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 a nd revisions to effluent guidelines which may take power plants offline for weeks or months in the next 5 or more years. Commenter 17868 believes the EPA’s estimates of the number of plants that will require additional controls, and these impacts will hit the upper and lower midwest, southeas t, and southwest the hardest.

Response to Comment 55: For discussion on available space limitations, small stations, small companies and control equipment available, see Response to Comments section 5C01 “Compliance Dates” which discusses controls fo r congested sites and combing emissions from multiple units into a single control device. Additional discussion is provided in the preamble for the final rule.

The agency accounts for current state air emissions regulations in its IPM modeling platform; for detailed discussion, see RIA chapter 3 and “D ocumentation Supplement for EPA Base Case v.4.10_MATS – Updates for Final Mercury and Air Toxics Standards (MATS) Rule.”

Comment 56 : Commenter 18433 states that the suggested method of controlling PM emissions from oil-fired units is ESP because the PM is generally too “sticky” from organic content to be collected reliably in fabric filters due to plugging the pore holes in the bags.

Response to Comment 56: The EPA thanks the submitter for their input. The agency responded by creating a subcategory for liquid oil- fired, non-continental unit s (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 typically control PM emissions with an ESP and believes the final MATS standard for oil-fired units can be met with a well-designed, well maintained ESP for maintaining PM control. The EPA does not select any specific tec hnology for MATS compliance; rather the standard sets permissible emission rates which a llow the owner flexibility in selecting controls and fuels for compliance. See the preamble for the final rule.

11. Natural gas prices.

Comment 57 : Commenter 17810 does not believe that the EPA has adequately considered the best available data on natural gas prices and supply, and requests that the EP A perform additional analyses of control options using updated information.

Response to Comment 57: The agency has fully documented its assumptions and framework for modeling natural gas in IPM for both the proposed and final MATS. This information can be found in Chapter 10 of the IPM documentation (http ://www.epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). The documentation provi des a thorough overview of the natural gas module, describes the very detailed process-engineering model and datasources used to characterize North American conventional, unconventional, and fr ontier 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, pro cedures used to capture pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key gas market parameters.

Comment 58 : Commenter 18033 considers replacing coal with natural gas to be problematic given that the cost of natural gas is volatile and makes up over 70% of the levelized cost of electricity (LCOE). The commenter describes a price spike from $6/MMBtu to $13/MMBtu in 2005 and details some of the532 environmental issues recently created by harvesti ng shale reserves. The commenter asks the EPA to examine a constructive policy framework that rem oves this and other regulatory impediments and promotes the deployment of advanced coal technologies . The commenter states th at replacing older U.S. coal plants with advanced superc ritical generation could create $1.2 tr illion in economic benefits and 6 million jobs during construction as well as avoidi ng the release of 440 million metric tons of CO 2
. Response to Comment 58: The agency fully documents its assumptions and framework for modeling natural gas in IPM for both the proposed and final MATS. This information can be found in Chapter 10 of the IPM documentation (http://www. epa.gov/airmarkets/progsregs/epaipm/docs/v410/Chapter10.pdf). The documentation provi des a thorough overview of the natural gas module, describes the very detailed process-engineering model and datasources used to characterize North American conventional, unconventional, and fr ontier 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, pro cedures used to capture pipeline transportation costs, natural gas storage, oil and natural gas liquids (NGL) assumptions, and key gas market parameters.

12. Fuel switching.

Comment 59 : Commenters 18433 and 19213 disa gree with the assumption th at all coal and fuel-oil units can be used with available control technolo gies. The commenters state that such fuel switching from one fuel type to another or fu el blending can be expensive, and faci lities in Guam are restricted in their fuel choices and mu st rely on oil currently.

Response to Comment 59: The difficulties American territor ies experience is acknowledged. The agency created a subcategory for oil-fired, non-c ontinental units (excluding Alaska-based units) realizing the unique situation and limitations these units face – see final rule. The MATS standard allows the owner flexibility to select controls and fu els plus establishes alternatives for compliance. See the preamble for the final rule.

Comment 60 : Commenter 19114 expresses concern with the IPM analysis suggesting that units will switch fuel to meet the beyond-the-floor standard. The commenter considers this unreasonable because fuel switching could change the subcat egory of the unit, thus subjecting itto a more stringent Hg limit. Also, the commenter points out that fuel switching costs used by the EP A do not account for all required coal conversion activities or for projects such as new coal unloadi ng and coal yard facilities to accommodate subbituminous coal which is often delivered by rail instead of truck or conveyor like lignite fuel generally is. Additiona l facility upgrades that the comment er would like to see in the EPA’s estimate include dust collection, new coal conveyers, fire protection, ventilat ion, ESP performance and water cannons to handle new fuel, soot and ash characteristics.

Response to Comment 60: Compliance issues, subcategories, and beyond-the-floor (BTF) issues are discussed elsewhere in the final rule record.

The agency believes that the fuel switching costs us ed 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 th ey choose. The IPM modeli ng indicates that some sources may choose to switch fuels as a valid comp liance option. If sources ar e unable or unwilling to employ fuel switching, they can comply through the inst allation 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] approachto reducing HCl at a s ite burning Powder River Basin (PRB) coal and another site burning an eastern bituminous coal. Both of these studies were shortterm in nature, with the test period of several week s, evaluating a number of different parameters each day. Thus these results are not able to provide any insight on the long-term performance and impacts of dry sorbent injection. The commenter is not aware of other demonstrations of this approach that have been conducted by independent, third parties. Howeve r, because of their c itation in the technical supporting documents for the proposed MACT rule, we also discuss tests conducted by a sodium sorbent supplier.

The commenter participated as a technical advisor in the first co mmercial demonstration of the TOXECON(r) process at We Energi es’ Presque Isle Power Plant. The project was co-funded by DOE under the Clean Coal Power Initiativ e. The primary objective of the project was to demonstrate the TOXECON configuration-downstream of a hot-side ESP in this case -with ACI for Hg control. A secondary goal was to determine the abilityof powdered Trona in jection to reduce SO 2 by 70% and also to realize some NO X emission reductions. These pollutant re ductions were to be obtained while simultaneously injecting activated carbon for Hg c ontrol (ADA-ES, 2008). The tests showed that the Trona could reduce SO 2 , but that it also converted enough nitr ogen oxide (NO) to nitrogen dioxide (NO 2 ) to produce a visible brown plume. Trona inject ion also reduced Hg capture by ACI significantly. Without Trona injection, the Presque Isle unit was able to maintain 90% Hg reduction at ACI rates of 1 to 2 pounds per million actual cubic feet (lb/MMac f). 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 befo re 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 te sts do not inform us about the amount of Trona or sodium bicarbonate that would be needed to meet the proposed HCl li mit, nor whether that amount would cause a brown plume and/or plugging, as well as impact Hg capture by ACI. Tests by Solvay Chemicals (a major supplier of Trona and sodium bi carbonate) at a low-sulfur easter n bituminous-fired power plant (reporting ~ 0.5-1% sulfur in the coal and 50-60 ppm HCl in the flue ga s) 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 inj ection rate (Davidson, 2010).

Since brown plumes have been observed atplants 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 fo r western bituminous coals with coal chloride concentration slightly greater thanthe proposed limit for HCl. However, this may not be possible for subbituminous coals with chloride concentration great er than about twice the proposed limit, where HCl removals up to 90% may be required. The situatio n for eastern bituminous coals, with their higher chlorine content, is discussed be low. To go beyond a reliance on engineer ing judgment, it is important to determine-via independent tests fully open to public scrutiny-whether these singl e results obtained on an eastern bituminous coal are representative of results for the fleet of PRB-fired power plants. Only then will the public and the industry truly understand the abil ity of sodium sorbent in jection 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 In 1996-97, the commenter conducted tests of both sodium bicarbonate and hydrated lime DSI upstream of a pilot baghouse at Hudson Generating Station ow ned by Public Service El ectric and Gas (EPRI, 1998). This plant burned a coal th at typically contained less than 1.0% sulfur and less than 0.1% chlorine; the corresponding flue gas HCl concentrat ion at the pilot’s inle t duct was 61-97 ppm. The results of these tests, presented in the document, s how 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 increa sing the ash loading by 50-60% or by 250-300 tons/day (normal ash load ing is about 500 tons/day).

The Hudson site, with an HCl concen tration in the mid-range for eastern bituminous coals, would have required 97-98% HCl removal to ac hieve the proposed MACT limit (equivalent to ~ 2 ppm). Plots of pollutant removal versus sorbent inj ection rate typically become very flat at high injection rates-i.e., increase very slowly if at all with increasing sorbent injection-so it is not clear from the available data if hydrated lime or sodium bicarbonat e could routinely prov ide greater than 90% reductions at any injection rate.

Response to Comment 61: The EPA appreciates the commenter’s observations. See the preamble for the final rule for more discussion on DSI technology.

13. Miscellaneous.

Comment 62 : Commenter 18033 questions the EPA assumption that 50% or more of the current fleet have scrubbing technology installed and that th e number will be nearly two-thirds by 2015. The commenter says that over half of the scrubbers men tioned will be at the end of their useful life by 2015, so cost will be associated with upgrading these scrubbers to achieve compliance. Also, the commenter points out that the scrubbers were only required to achieve 70% SO 2 removal when constructed. Bringing these scrubbers into compliance will requi re 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 approximat ely 25% of the current coal -fired fleet will retire early as a result. The commenter also mentions that as the MACT floor is set on the average of the top 12%, only 6% can be expected to meet the standard without modification.

Response to Comment 62: The agency has a different outlook regarding replacement of existing control equipment. The EGU sector continuously de monstrates 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 th e coal fired fleet) exceed 40 years of age. 64 Consequently, the agency believes owners will op erate emissions control equipment well beyond a 20- year period and shall attempt the more economically attractive option of upgr ading 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 existi ng controls by 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 “Character istics of U.S. Coal Plants.” Ref: http://www.mjbradley.com/sites/default/files/ MJBAandAnalysisGroupRe liabilityReportAugust2010.pdf
65 Assessment of Technology Options Available to Ac hieve Reductions of Hazardous Air Pollutants” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011535 Comment 63: Commenter 18023 reports that many of their un its have SCRs and scrubbers but will not be able to meet proposed emission limits in most cas es and will need baghouses and CEMS installed at a cost of $8.5 billion to comply w ith the proposed limits and monitoring requirements. The commenter notes that this price could increase due to the large number of plants rushing to comply with all existing and proposed regulations which could drive up the cost s of materials and skilled labor. The commenter also shows that the EPA’s estimate for the same f acilities gives a $4 billion cost, showing that the EPA’s estimates are understated.

Response to Comment 63: The EPA disagrees with commenter’ s assertion that the EPA’s cost projection is understate d, and maintains that the EPA’s incremen tal cost projections are reasonable. The RIA includes projected controls retr ofits and costs as updated in the EPA’s analysis for the MATS final rule. The EPA has provided the maximum 3-year peri od for sources to come into compliance. Sources may also seek a 1-year extension of the compliance period from their Title V permitting authority if the source needs that time to install controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule and address specif ic issues. For discussion on some of the issues mentioned above, see the preamble for the fina l rule and Response to Comments section 5C01 “Compliance Dates.” In addition, ther e are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 64 : Commenters 16826 and 17386 consider the cost a nd logistic burdens to comply with the proposed rule a concern because they know of a un it containing a once-through circulating water system that must meet NPDES water discharge limits. The commenters say that these permit limits indirectly restrict the hours of operation and load, and request a “Limited Use” cat egory to relieve this and other oil-fired facilities in a similar scenario.

Response to Comment 64: Based on the concerns submitted, the EPA established a “limited-use” subcategory for liquid oil-fired E GUs. For a detailed discussion, s ee the preamble to the final rule.

Comment 65 : Commenter 16849 reports a compression of resources available between 2007 and 2008 that led to the price of SCR in stallation to jump from $31 million in 2007 to $58 million in 2008 at a neighboring, like-sized facility.

Response to Comment 65: Many factors influence retr ofit cost besides locality; 66 a neighboring facility does not necessarily mean an “identical” facility. The present economic conditions differ drastically from the situation experienced in 2007-2008; retrofit c ontrols cost models were determined during this time period and based on 2009 pricing. With excess resour ces currently available, the agency anticipates aggressive competition by suppliers to win project aw ard subsequently resulting inprice relaxation from pre-2009 levels.

Comment 66 : Commenter 17296 provides information regardi ng the use of calcium bromide as a costeffective way to reduce Hg emissions from coal-fire d units. The commenter says that calcium bromide has been found to effectively oxidize elemental Hg so that it can be better controlled by traditional control devices. (The commenter provides a White Paper on Calcium Bromide Technology for Mercury Reductions (August 2010) as partof EPA-HQ_OAR-2009-0234-17296-A5 a nd additional research as - 17296, -17296 and refers to NESCAUM report “Technologi es 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 Company536 Response to Comment 66: The EPA thanks the submitter for the information provided in support of the proposed rule. Multiple comments were received advocating control techno logies that were not represented in the EPA’s compliance cost analysis of the MATS proposal. The ag ency notes that control technologies mentioned within the pr oposal 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 partic ular technologies in th is rulemaking but is instead allowing each facility to determine its preferred means of compliance with the emission rate standards.

Comment 67 : Commenter 17807 discusses a new $1.2 billion pr oject to upgrade environmental controls and repower a power station which led to an annual re duction of Hg, SO 2 , NO X and PM emissions in 2010 by 90%, 94%, 91% and 87%, respectively, below 1998 levels. The commenter says that the EPA’s proposed emissions limits will likely require further optimization and adjustments and be difficult to implement despite these recent upgrades.

Response to Comment 67: The agency set emissions standards based on data collected (ICR) from existing EGUs within the domestic EGU fleet; ther eby, demonstrating operational, existing control technologies for compliance. Owners have a multitude of options and may choose to: retrofit, optimize current controls, upgrade ex isting controls, fuel switch/blend, empl oy a combination of technologies, or retire and replace power. The EPA understands recen tly retrofitted units may require further upgrades for compliance; however, controls for SO 2 mitigation typically suffice for MATS acid gas capture while economical upgrades of existing controls or optimization may suffice for compliance. 67

Comment 68 : Commenter 17842 believes the implementation of a “total” PM limit in the proposed rule contributes largely to the rule’s es timated costs as utilities will need to replace existing PM controls with more costly fabric filters.

Response to Comment 68: Although the EPA proposed a total PM standard, the EPA is finalizing MATS to include a filterable PM standard instead. See the preamble for the final rule. The EPA does not believe that MATS automatically necessitates replaci ng existing PM controls w ith fabric filters. Many older ESPs are oversized and suffer from inadequate maintenance resulting indegraded 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 metr ics. In fact, many older ESPs have sufficient room for extension thereby increasi ng collecting area by 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 69: Commenter 17885 states that many cooperative EGUs will be forced to retrofit with additional emission controls under the proposed rule and others will need to shut down because they will be unable to retrofit under the timelines or cost-effectively justif y the retrofits. The commenter expresses

67 Assessment of Technology Options Available to Ac hieve Reductions of Hazardous Air Pollutants” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011
68 Assessment of Technology Options Available to Ac hieve Reductions of Hazardous Air Pollutants” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011
69 NESCAUM report; “Control Technologies to Redu ce 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 pr ocedures used by the EPA in the rulemaking process.

Response to comment 69: The EPA believes that the flexibility of the rule permits a multitude of options for economical compliance. Flexibility, other regulations, and compliance date attainment are discussed in the preamble for the final rule, feasib ility TSD, and in Response to Comments section 5C01 “Compliance Dates.”

Comment 70 : Commenter 19122 describes the startup and sh utdown process for their oil-fired unit, which requires bypassing of the fabric filters to prev ent damage that would require replacement of bags after each startup. Requirements th at include startup and shutdown episodes in PM emissions on a lb/MMBtu basis would lead to the ne ed to use the fabric filter with temperatures well below the acid dew point, leading to bag binding an d acid degradation. The commenter e xplains that this would involve using at least one casing out of three in service to handle flowduring start up. One casing has 16 compartments with 396 bags each. The bags in the compartment that would need replacement cost $1.2 million, leading to an additional cost of $15 million per year.

Response to Comment 70: The EPA acknowledges start-up/shut dow n issues involving fabric filters (acid attack, blinding, etc.) during oil firing. The agency points out th at 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 em ploys 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/CM SFiles/Fabric%20Filte r%20Material[0].pdf ]
71 CoalPower mag; May 1, 2007; “Coal Plant O&M: Ri ver Locks and Barges ar e an Aging Workforce, Too” ref.: web site: http://www.coalpowermag.com /plant_design/Coal-Plant -O-and-M-River-Locksand-Barges-Are-an-Aging-Workforce-Too_36.html538 6G - Impacts/Costs: Testing a nd Monitoring Cost Assumptions

Commenters : 17197, 17386, 17681, 17696, 17716, 17718, 17730, 17737, 17761, 17772, 17795, 17796, 17843, 17856, 17881, 17886, 18014, 18444, 18502, 18023

Comment 1: Commenter 17197 believes the 18 months burne r 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-boi ler entry slag blasting for personnel safety costs approximately $10-12,000, scaffolding the boiler for burner access is about $80,000 and requires at least 6 weeks of pre-planning and post-outage boile r combustion testing a nd tuning costs around $50,000.

Response to Comment 1: The EPA generally agrees with the commenter and has altered the burner inspection interval to reduce the cost burden of this rule. Under the fi nal rule, the inspection and tune-up must be conducted at each planned major outage and in no event less frequen tly than every 36 months, with an exception that if the uni t employs a neural-network system for combustion optimization during hours of normal unit operation, the required freque ncy is a minimum of once every 48 months.

Comment 2 : Commenter 17386 objects to the requireme nt to conduct monthly or bimonthly performance tests, as it is an economic burden, esp ecially for smaller facil ities. The commenter also states that such testing could result in increa sed annual HAP emissions exceeding any reduction in hourly emission rates achieved by the rule. The commenter points out that oil is a homogenous fuel for which metal concentrations are unlikely to fluctuate. The commenter goes on to say that since oil-fired EGUs are a minor source of HAP except for nickel, th e frequent testing is unw arranted. The commenter states that the cost of such a testing program invol ves the ancillary cost of operating the EGU on a mustrun basis for the testing, even on EGUs that operate intermittently. Such testi ng will interfere with the ability to meet regional electricity demands if the E GUs 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. Howeve r, for testing purposes, the commenter will be required to fire the fuel with the capacity to genera te the most HAP emissions, leading to emissions that would not have otherwise been rele ased. The commenter requests that for these reasons, the EPA require only one performance test for oil-fire d 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 regardi ng oil-fired testing during the ozone season and is changing the rule language accordingly to require that testing be conducted on the fuel type fired during the operating quarter that is likely to result in the highest emission rate. In th is manner, if there are no oil-fired operations during ozone s eason quarters, there is no requireme nt 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 th at a more reasonable approach would be to perform an initial stack test for PM followed by the use of PM CEMS, and annual PM stack tests as long as the coal type or mixture of fuels did not change. The commenters state that a stack test vendor estimates that annual total PM and non-Hg metals stack testing pl us 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 co mpliance if the suggested approach were used.539 Response to Comment 3: The EPA disagrees with the commenters’ notion that PM is an appropriate surrogate for HCl emissions. HCl testing frequency ha s been reduced to a quart erly requirement and is required only if SO 2 controls and monitoring, or HCl mon itoring (optional) are not employed. PM CEMS and PM CPMS options are being added to this rule to optionally reduce th e burden of monthly or bimonthly stack testing.

Comment 4 : Commenters 17716 and 18014 discuss linear ity checks required under Appendix B. Commenter 17716 states that section 63.10010(e)(6)(iii) should define th e term “nominally,” and should not require the introduction of a ca libration gas. The commenter point s out that Part 75 requirements already assure an analyzer span th at provides accurate data. Coupled with the Part 75 requirements, the three linearity gas concentrations are sufficient to determine that the analyzer is linear. Commenter 18014 states that the system will need to be modifi ed to include an additional regulator, the data acquisition and handling system (DAHS) will need to be reprogrammed and costs will be incurred for a fourth calibration gas and monthl y 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 commente r that Part 75 requirements already provide for a linear instrument resp onse that should, by definition, in clude the emissions limit level and beyond, and has removed this requirement from the final rule.

Comment 5 : Commenter 17718 requests guidance from the EPA on what should be included in a sitespecific test plan mentioned in the proposed rule (40 CFR 63.10007(a)) as the development of quality assurance programs with testing firms canbe burdensome without clear guidance.

Response to Comment 5: Section 63.100007(a) points to secti on 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 ex pectations of precision, accuracy, and completeness of data.

An example of a DQO requirement is:

“The sample volume must be sufficient to provide th e required amount of anal yte to meet both the MDL of the analytical method and the a llowable stack emissions. It may be calculated using the following formula:

Sample Volume = A x 100/B x 100/C x 1/D

Where:

A = The analytical Method Detection Limit in ng

B = % (%) of the sample required per analytical run

C = Sample recovery (%)

D = Allowable stack emissions (ng/dscm)

Test contractors are experienced with devel oping and working with Test Plans, DQOs, and QA programs and the EPA feels this requirement s hould 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 base d on representative data and the limit will be difficult to achieve routinely and will eliminate new coal-fired units. However the commenter appreciates the EPA’s providing of the al ternative of conducting fuel analysis for ongoing compliance for existing low emitting electric generati ng units (LEEs), and urges the EPA to make it available to new units as well. Commenter 18023 questi ons the EPA’s assumption that “most, if not all, of the units that were subject to CAMR purchased Hg CEMS and/or sorbent trap systems prior to the rule vacatur...” The commenter reports that while th eir facilities did install Hg CEMS, the systems will need extensive upgrades as they will require thre e more CEMS be installed to meet the proposed requirements. Also, full quality assurance measures have only been completed on a fraction of the previously installed CEMS. The commenter goes on to say that the Hg CEMS have required an unexpected degree of maintenance, which will incr ease with lowered emission limits and some Hg CEMS have been inexplicably unreliable. The commenter believes others in the industry are in a similar situation, which means that the EPA cost estimat es underestimate the cost of new installations, expensive upgrades and additional maintenance re quired by the proposed rule. In addition to the equipment-related expenses, the commenter lists cost s associated with modifying the data acquisition and reporting systems associated with the Hg CEMS to meet the new procedur es and requirements. The commenter estimates that these changes will cost approximately $20 million upfront and another $2.5 million annually.

Response to Comment 6: The EPA generally agrees with the commenter that many Hg CEMS installations were not unde rtaken or fully implemented as a resu lt of the CAMR vacatur, and we are increasing our estimated cost impacts accordingly. Th e EPA does not agree that existing mercury CEMS installations would need upgrades to comply 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 requi rements. Commenter 17737 reports that in addition to the cost of the inspection and repa ir work, the facility may be requi red to purchase power during outages at higher prices that the electricity normally produ ced. This cost could exceed $1 million for a 3-week outage during peak season. By requiring a major outag e 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 mainte nance outages are generally scheduled only every 4 or 5 years. The requirement to do burner inspections every 12 to 18 mo nths 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 w ith system reliability. Commenter 17886 considers the requirement of an outage for burner inspection and re pair more often than every 36 months to be excessive because of increased costs without actual be nefit. Commenter 18023 estimates thatthe impact of shortening its outage interval by only 6 months would amount to approximately $140 million for 5 years across their system, taking into account the cost of replacement generation.

Response to Comment 7: The EPA acknowledges the concerns raised by the commenters and has altered the requirement for burner inspections to a sc hedule more likely to coin cide with planned major outage schedules.

Comment 8 : Commenter 17772 requests clarif ication on the proposed rule language that verifies no requirement to retrofit boilers w ith viewing ports where none previ ously 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 thatdo not have viewing ports. The541 commenter considers the addition of vi ew ports to units without them cos tly and of little benefit as flame pattern viewing can be subjective when trying to assess CO levels and tells little about NO X levels.

Response to Comment 8: The EPA generally agrees with the commenter and has revised the rule language as suggested.

Comment 9 : Commenter 17772 discusses the option of calibrating oxygen monitors instead of calibrating all other equipment to optimize total CO and NO X emissions. The commenter recommends that oxygen monitors be calibrated a nnually instead of the air flow or fuel measurement devices, as proposed in section 63.100021(a )(16)(iii). The commenter reports that air-to-fuel ratios are usually fixed by the manufacturer at the time of installation and calibration is done as needed or during a planned outage. Some systems are difficult to adjust or unable to be adjusted. Therefore, the commenter considers CO and NO X emissions to be dependent on oxygen, so monitoring oxygen levels is a better indication of optimal emissions. Inaddition, 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 ar e set by the manufacturer at the time of installation, but the operato r is responsible for adjustments based on future operational changes such as coal quality.

Response to Comment 9: The EPA generally agrees with the commenter in that not all parameter changes are applicable at all facilities and for all burner installations. We are modifying the rule language to clarify this requirement and allow for adjustment of burne rs that have had post-manufacturer modifications or adjustments for fuel quality or type.

Comment 10 : Commenter 17795 requests that the facility averag ing requirement to not exceed current emission levels be removed on the grounds that the curr ent language penalizes units that have controls in place and are currently meeting the EPA’s HAP standards, which is c ounterintuitive to how these units should be viewed. The commenter lists the following r easons for the requested change in the provision:

1. Facilities in many cases do not have CEMS inst alled (e.g., Hg and PM CEMS) and do not know the current rate being ach ieved 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 esse nce requiring an initial compliance test shortly after the rule is finalized and again 3 years later when the compliance is required. Again this scenario places too much emphasi s 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 proposedHg standard) at one of GenOn’s facilities in the first seven months of 2 011. [EPA-HQ-OAR-2009-0234-17795-A1, 17795_2011_Hg_Emission_Data.doc]

Response to Comment 10: The EPA disagrees with the co mments provided. The ICR testing requirements were designed with the goal of collecting data representative of th e cross section of units. The UPL calculation performed on emissions test data ta kes 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 effectiveness are standard compliance procedure.

Comment 11 : Commenter 17796 considers the option of stack testing with Method 5 or 201/202 monthly or bimonthly depending onPM control equipment to be burdensome for the source and the state agencies required to witness the tests and revi ew the reports. The commen ter also points out that the proposed testing does not assure additional public health benefits.

Response to Comment 11: The EPA has modified the requirementfor monthly and bimonthly testing to a quarterly testing requirement. This requirement is an option and as such is not a necessary burden for the facility to bear. The proposed testing is in lieu of continuous m onitoring and as such is meant to assure that public health bene fits are akin to what would be shown by continuous monitoring of emissions.

Comment 12 : Commenter 18023 reports that the cost to in stall and operate PM CEMS for compliance with the proposed rule will exceed $30 milli on initially and at l east $0.6 million annually.

Response to Comment 12: The EPA recognizes the costs associated with PM CEMS compliance requirements and is modifying the rule language to reduce the cost burden while maintaining continuous monitoring using the technology as a con tinuous parameter monitor (PM CPMS).

Comment 13 : Several commenters (17796, 17761, 17843, 17856, 18444) comment on the costs for state agencies required to observe or re view emissions tests, read reports and protocols related to the proposed rule, and send the EPA summaries of the data. Co mmenter 17843 suggests that once the initial test is conducted for PM and non-Hg metals, and fuel samp ling or operating parameters are established, fuel sampling would be a simpler and less costly approach than stack testing. The commenter mentions that having the EPA revise the monthly and bimonthly test ing requirement to quarter ly or biannual testing would be more reasonable. Commenter 17856 also di scusses the need to modify each unit’s Title V permit and the time required for state agencies to co mplete the extensive modifications to each unit’s unique operational characteristics. The commenter s ees these requirements as especially burdensome because they would be required to repeat the proce ss every two months, indefinitely, and for every unit subject to the bimonthly performance tests. The comm enter 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. Co mmenter 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 ope rating limits in need of establishment will require multiple load testing, which is anothe r resource drain for state agencies.

Response to Comment 13: The EPA generally agrees with the comments and has dropped fuel sampling requirements for non-Hg metals since the detection levels are not low enough to show compliance with the limits. This removes the requirement to update Title V permits as the rule will also drop the control device operational limits. Now, s ource owners/operators would establish the milliamp value during successful Method 29 tes ting, and use just that value as an operating limit. The EPA has also modified the rule requirement to require te sting 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 me tals, rather than reporting filterable and condensable values because the separate analysis will add costs without providing necessary information.

Response to Comment 14: The EPA disagrees with the comment and is not modifying the requirement. EPA Method 29 has always included the analysis of the impinger contents for all of the metals. For several of the metals such as selenium and arsenic there are specific reagents in the impingers which are designed to collect the metals that pass through th e filter. Since digestion and analyses would be required for the filterable component and digestion of the impinger cont ents is required for those metals with special reagents, the additional cost is due to the analysis by the ICP instrument. Since this instrument analyzes all metals conc urrently, there would be no or little reduction in the analysis cost for the impinger contents. In addition, for a few of the Method 29 tests conducted for the Phase III portion of the ICR, substantial percentages of the metals we re in the impinger analysis. Eliminating the results of the impinger contents woul d introduce a significant negative bias into the results.

Commenter 15 : Commenter 18502 discusses the increased cost for non-continental EGUs of emissions testing to document compliance with the proposed limits. The commenter explains that as a noncontinental unit, they contract with emissions tes ting firms located in the continental U.S. and have higher costs per test despite having smaller units than is common in the continental U.S. The commenter also cites the requirement to test for individual meta ls rather than filterable PM as a cause of increased cost of compliance testing per megawatt of capacity to be significantly higher than for continental EGUs with little environmental benefit associ ated with frequent emissions testing.

Response to Comment 15: The EPA generally agrees with the co mmenter and has modified the testing requirements and monitoring options of this rule in an effort to decrease costs to affected units.

Comment 16: Commenter 17758 states that DSI will be a us eful and cost-effective control tool for many units, but it is not a viable option for all co al-based units for compliance with the acid gas standard. In many circumstances, the EPA’s analys is of DSI significantly underestimates the time needed for, as well as the cost of, compliance in many circumstances. First, DSI could have limited application as a compliance option due to operational impacts and cost considerations that the EPA has not taken into consideration. Second, the use of DSI could impact benefi cial use of fly ash, resulting in increased disposal volumes, costs and loss of revenue . Third, DSI is not a viable option for eastern bituminous coals, which require the use of wet FGD; compared to DSI, wet FGD is more costly and takes more time to implement, leading to timing concerns for compliance. Many companies will need more than the 3 years and will spend more th an the EPA estimates to achieve compliance.

Response to Comment 16: The EPA also believes that DSI has th e potential to be a useful and costeffective control technology option for many units. We also agree that it is not an appropriate option for many facilities. Overall the EPA believes that the technology is most applicab le for units burning lowersulfur content coal (including, potentially, low-sulfur bituminous coal). The EPA has considered operational impacts and cost consider ations. In some cases the EPA has assumed that a “polishing” fabric filter will be installed downstream of the prim ary control device. This configuration (similar to the TOXECON(tm) configuration for Hg c ontrol) allows dry sorbent to be injected after the primary PM control device, thus keeping the ash and dry sorbent (both alkaline sorbent for acid gas control and activated carbon sorbent for Hg contro l) separate. This will help to pres erve the salability of the fly ash and may reduce the costs of disposal if the ash an d spent sorbents can be disposed of separately. However, the EPA did include an analysis evaluati ng the impact of increased disposal costs for ash residuals that contain sodium c ontaining sorbents (such as Trona or sodium carbonate). The EPA’s544 analysis of the final rule include s an IPM sensitivity case using a DS I waste disposal cost of $100/ton. The sensitivity case indicates that a 100% increase in assumed DSI wast e 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 fact ored in the cost of additional catwalks required due to the additional CMS and/or sorbent tr ap system equipment. According to the commenter some facilities cannot place additional CMS ports where the current catwalk is lo cated due to a lack of physical space on the stack surface area at the elevation and such additional equipment may require additional catwalk levels. Commente r notes that the Lakeland coal unit does not appear to have sufficient room on its current elevation where the mon itors are located at this time for an additional monitor without bringing the integr ity of the stack into question (if additional stack ports must to be carved out). Lakeland’s Unit 3 coal unit already has existing monitor equipment and the addition of a PM CEMS and/or Hg monitor/sorbent may require the installation of an additional catwalk.

Response to Comment 17: The Agency’s analysis represents the average cost of purchasing, installing, operating, and maintaining emissions control equipment. Application of emissions control equipment at an individual site with unique ci rcumstances may cost more or le ss than the average, depending on factors such as the owner or operator’s ability to e ngineer effective approaches that ensure compliance with the rule’s emissions limits.

Commenter 18: Commenter 16849 states that the EPA make s the assumption most units currently monitor moisture content. The commenter does not m easure moisture content con tinuously 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 ha s been made for this rule, even though the Agency is aware that owners or operators of many EGUs subject to the acid rain program choose to monitor stack moisture on a continuous basis.545 6H - Impacts/Costs: Pr ojection of New Units

Comments are addressed in Section 4 of this document.546 6I - Impacts/Costs: Economic Impacts/Employment Impacts

Commenters : 12050, 15002, 16469, 16549, 16705, 16849, 16856, 16858, 16859, 17004, 17022, 17026, 17028, 17123, 17137, 17254, 17265, 17386, 17400, 17403, 17409, 17620, 17623, 17627, 17629, 17638, 17639, 17640, 17648, 17654, 17656, 17676, 17681, 17682, 17689, 17690, 17692, 17697, 17698, 17701, 17702, 17705, 17707, 17710, 17711, 17712, 17716, 17718, 17725, 17730, 17731, 17732, 17736, 17743, 17745, 17751, 17756, 17761, 17765, 17767, 17771, 17772, 17774, 17775, 17791, 17797, 17799, 17800, 17805, 17806, 17807, 17808, 17811, 17812, 17813, 17815, 17817, 17821, 17824, 17829, 17834, 17839, 17840, 17842, 17844, 17853, 17854, 17855, 17867, 17868, 17875, 17877, 17879, 17880, 17881, 17884, 17886, 17887, 17901, 17903, 17904, 17909, 17911, 17917, 17919, 17921, 17930, 17931, 18014, 18016, 18017, 18018, 18021, 18025, 18026, 18030, 18033, 18038, 18039, 18419, 18421, 18422, 18422, 18424, 18425, 18428, 18430, 18432, 18433, 18433, 18433, 18435, 18436, 18437, 18441, 18447, 18477, 18478, 18480, 18481, 18484, 18486, 18488, 18489, 18497, 18498, 18500, 18502, 18538, 18540, 18575, 18907, 18933, 18961, 19041, 19042, 19114, 19121, 19199, 19211, 19212, 19213, 19214, 19580, 19653, 19536, 19537, 19538, 19742, 18023

1. Job losses and economic impact/cost.

Comment 1: Multiple commenters (16549, 17137, 17656, 17736, 17840, 17887, 17901, 17931, 18488, 18023, 19742) believe the proposed rule will weakenindustry, cause job losses and hurt power consumers. Commenter 16549 reports that the proposed ru le will affect 1,350 coal- and oil-fired units at 525 power plants and that NERC reports that by 2018 nearly 50,000 MW of capac ity 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 repo rt of $358 billion and a Representative Upton and Senator Inholfe estimate of $300 billion by 2015 show th at some believe the EPA’s cost estimates to be very low. The commenters express concern for the elec tricity price increases that are likely to be up to 24% in some regions as a result of the proposed rule. In addition to the economic difficulty the proposed rule could place on consumers, the commenters believe that many in the energy sector will lose their jobs due to coal-fired capacity losses. The commenters believe coal -fired plants in the southeast especially will mean the loss of high-paying, high-ski lled jobs and drastic pr ice increases in energy
costs.

Response to Comment 1: The agency has estimated the annual costs of the rule in 2015 to be $9.6 billion in 2007 dollars. The estimate of early retirements of coal-fir ed units is 4.7 Gigawatts. Both of these estimates were prepared using the IPM, a mode l that has been extensivel y reviewed and has been utilized in several rulemakings affecting the power generation sect or over the last 15 years. The agency’s analyses are credible and accurate to the exte nt possible. Limitations and caveats to these analyses can be found in the RIA for the rule. Retail electricity price impacts ar e estimated to increase by 3.1% in 2015.. The agency also found that the im pact on employment nationally should be small on net, with about 46,000 job-years of one-time construction labor supported or created by this rule, and a loss of 15,000 to an increase of 30,000 jobs expected on an annual basis. The agency has used peerreviewed studies in the preparati on of the employment impact analys es. In addition, commenters are not comparing apples to apples. EIA ha s at no time provided an analysis of the costs of MATS as proposed or finalized, and other studies showing large ne gative impacts have many flaws. The primary weaknesses with these studi es are the poor reflection of the actu al rule requirements, inadequate inclusion of proven technologies, and speculation with regards to other policy, like climate policy.

Comment 2: Several commenters (16705, 17403, 17123, 17400, 17771, 17817, 17829, 17909, 18437, 18575) express concern that the propos ed rule, if finalized in its curr ent form, will significantly impact547 jobs and electricity rates, leadi ng to closed businesses. Commente r 17123 also calls for a practical, affordable, achievable energy solution. Commente r 17771 expresses concern sp ecifically about the burden of the proposed rule on New Mexico. Comme nter 17909 believes the leveling of the national electricity price and modernization of the fleet is outside the scope of the EPA’s regulatory authority. Commenter 18575 expresses concern for the impacts likely in South Dakota, Minnesota and Iowa.

Response to Comment 2: The agency has estimated that there could be employment impacts on the power sector of up to 46,000 job-years of construc tion labor supported or cr eated from new pollution control equipment installed, and a ra nge of annual employment impacts of a loss of 15,000 jobs to a gain of 30,000 jobs. Although the agency does not claim what the total employment impact will be of this rule, it is important to note that there will be so me 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 ar e found in the RIA for the rule. The agency also examined the impact of the increas es in electricity prices to indus tries outside of the electric power sector and found that changes in product price and output should be less than 1 % in 2015 for the many industries (100) included in the analysis. There may be impacts on a firm-level that could be higher than this, but these analysis results suggest that the economic impact s on average nationally should be modest.

Comment 3: Commenter 19212 urges the EPA to give state re gulators the flexibility in implementation to allow consumer protection agains t massive utility rate increases.

Response to Comment 3: Utilities have discretion in how to meet the requirements of this rule, and EPA analysis indicates that the impact to electr icity consumers will be reasonable given the large benefits,

Comment 4: Several commenters (16858, 17022, 17028) express c oncern 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) repor t being advised by their utility provider that the proposed regulation could resu lt in double-digit price increases for power.

Response to Comments 4 - 5: The agency’s analysis in the RIA for the rule finds that retail electricity prices will increase by 1.3 to 6.3% in 2015. No region ofthe U.S. is expected to experience a doubledigit increase in retail electricity prices in 2015 or in any year la ter than that, according to the agency’s analysis. In addition, the agency finds that sectors experiencing these electricity price increases will not experience increases in prices or decreases in out put of more than 1 %. The agency believes the economic impact of this rule is mo dest in light of the benefits thatwill accrue to those who will now experience less pollution of HAP and other pollutants than previously.

Comment 6 : Commenter 17842 questions the lack of cons ideration of the cumulative effects of interrelated rules, which may collectively lead to mo re retirements. The commenter states that local utilities have reported temporary job gains due to the replacement of retired generation, but a net decrease in full-time work. The commenter asks th e EPA to reassess the costs and impacts of the proposed rule.548 Commenter 18424 states that the EPA’s conclusion th at bituminous coal production will increase as a result of Utility MACT is based on two flawed assu mptions. First, as discussed above, the EPA assesses the impacts of the Utility MACT as if it were the only regulatory driver affecting a company’s compliance and economic decisions. The EPA analysis ignores the cumulative impact of all the new CAA regulatory requirements a utility will have to consider when it determines its compliance strategy. As a result of ignoring the cumulative impacts on decision making by utili ties, the EPA projects approximately 10 GW of coal units will be retired because of Utility MACT. In contrast, the NERA analysis, which considers the impacts of both U tility MACT and CSAPR together, projects nearly 48 GW of coal unit retirements - most of which are smaller and older units burning bituminous coal. Other studies predict similar levels of coal unit retire ments. This degree of retirements would have a devastating impact on Indiana’s coal i ndustry and consumers of electricity.

Response to Comment 6: The final CSAPR was included in the baseline analysis for MATS. The agency did not prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO requirements that the agency must complywith 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 regu lation; 3) estimates specific to a particular rule are more transparent than those from a cumulative impact analysis. A cu mulative impact analysis lumps several regulations together and can potentially mask a high-cost/low-b enefit regulation among other rules that may have large net benefits. By analyzing each regulation separately, the EPA makes clear statements about what impacts, costs, and benefits will be generated as a result of this particular regulation. The EPA analysis also indicates that there will be relatively modest amounts of re tirements and insta llation 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 positio ned to comply with this rule with modest changes to operations. In addition, the EPA has conducted anupdated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 7: Commenter 17824 reports that the majority of coal-fired units that do not have scrubbers are small units that may find the cost of upgrades too expensive and will shut down instead, leading to job loss and decreased local revenue.

Response to Comment 7: The requirements of the rule do no t 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 thatreflect differences in cost across unit sizes, and the projected impacts reflect these effects.

Comment 8: Commenter 17639 encourages the Federal Govern ment to implement cost benefit and job impact analyses before enactment of all rules and regulations. This commenter also states that the proposed rule compliance costs would make it challenging for older coal -fired units to comply and lead to retirement and energy cost increases of 17.6% in 2016. These in creases would disproportionately affect economically vulnerable families.

Comment 9: Commenter 18502 believes there is a disjunctio n between the President’s public policies and the proposed rules as they relate to job cr eation, public burden, and economic development. The commenter cites EO 13563, EO 13132, EO 12866, and EO 13211 as the Executive Orders of concern.

Response to Comments 8 - 9: The agency followed all requirem ents under Executive Orders 12866, 13563, 13132, 13175, 13045, 13211, 12898, and the Unfunded Mandate s Reform Act in preparing this549 proposed rule. The analyses completed in adherence to these requirements can be found in the RIA and in various TSDs in the public docket for this ru lemaking. 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 mitigat e these price increases. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. This is also consistent with the economic literature on this subject.

Comment 10 : Commenters 17656 and 18023 quote an IHS/Global Insight estimate that every $1 billion spent on upgrades to comply with the proposed ru le will put 16,000 jobs at risk and reduce gross domestic product (GDP) by as much as $1.2 billion.

Response to Comment 10: The agency’s modeling of impacts for this rule is concentrated on effects to the electric power sector. Our analysis of employm ent impacts finds a short-term impact of 46,000 jobyears supported or created, with a longer-term imp act of between a loss of 15,000 jobs and a gain of 30,000 jobs annually. We do not include impacts of em ployment beyond the regulated sector. We do not provide an estimate of a change in GDP. The EPA has conducted an updated employment analysis which shows some potential positive and negative em ployment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. This is also consis tent with the economic literature.

Comment 11 : Commenter 17840 considers the proposed rule to discourage technology improvements, raise electricity costs and harm the economic well-bei ng of the country, so the EPA needs to rescind the proposed rule.

Response to Comment 11: The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring public health is prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices.

Comment 12 : Commenter 17839 questions the concerns expre ssed about increased costs for electricity consumers. The commenter states that public utility commissions in each state will determine a fair and reasonable rate structure. The commenter states that any increased cost to the utility caused by the proposed rule will be amortized as a capital expenditure over a numbe r of years, reducing the rate impact. The commenter calls on utilities to substantia te their claims of incr eased costs and points out that it is not the EPA’s responsibil ity to factor rate increases into the adoption of the proposed rule.

Response to Comment 12: The EPA will work with relevant auth orities to ensure a smooth transition with this rule. Public utility commissions and othe r 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 othe r response measures. In a ddition, there are certain provisions for granting utilities so me additional time to comply, if conditions warrant (see preamble).550 Comment 13 : Commenter 17716 rejects the EPA’s view that the proposed rule will encourage energy efficiency savings to offset higher electricity cost s. The commenter points out that table 23 of 76 FR 25074 does not support this claim and shows only a slig ht reduction in complianc e costs from 2015 to 2030.

Response to Comment 13: The EPA believes energy efficiency meas ures 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 federa l agencies, states and other groups. This will contribute to additional environmental and public health improvements while lowering the costs of realizing thos e improvements. A reduction in compliance costs with the rule does take place over time, and so does a re duction in retail electricity price increases across the U.S. as seen in the RIA for the rule. Thus, while this reduction in impacts is modest, it does suggest that energy efficiency increases may somewhat mitigate the impacts of the rule.

Comment 14 : Commenter 17868 refers to the American Coalition for Clean Coal Electricity (www.cleancoalusa.org ) projecting net nationwide employment losses totaling 1.44 million job years by 2020 as a result of the proposed rule.

Response to Comment 14: The estimate of employment losses supplied by the commenter reflects a cumulative estimate of employment losses ove r the time period of 2012 to 2020 related to implementation of both the CSAPR and the MATS proposal, and has many weaknesses. Thus, this estimate is not for the proposed rule alone, and is not a transparent analysis whose assumptions and inputs can be verified. In addi tion, the report upon which this estimate is based (NERA report, September 2011) does not show what type of empl oyment impacts are assessed (construction, operation, etc.). The Agency’s estimates both short-term and l ong-term employment impacts specific to this rule, which can be found in the RIA for the rule. The upda ted employment analysis for the final rule shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in compar ison to the affected sector and the overall economy. This is also consistent with the economic literature.

Comment 15: Commenter 19042 presents the results of ananalysis by the EOP Foundation on the proposed rule. The commenter estimates that the pr oposed rule will increase federal outlays by $286 million annually due to electricity purchases and costs absorbed by federal agencies for boiler modifications. The analysis shows increased annual federal agency costs from $1 million to $17 million annually per region, or an increase of 1 to 5%.

Response to Comment 15: The agency has considered this data as part of its UMRA analysis for the final rule.

Comment 16 : Commenter 18023 estimates that capital spending and fuel switching required for compliance with the proposed rule could increase elec tricity prices by 10 to 20% over the next 10 years in the south. The commenter also cites a NERA an alysis showing a 10 to 25% increase in the same timeframe, with job loss es of 250,000-500,000. These losses could result in financial difficulty for local governments dependent on tax revenu es that have a short time period in which to implement budget cuts. The commenter estimates that there are 6 to 10 jobs at a coal-fired EGU for every job at a comparably sized NGCC EGU, and the jobs lost to coal-fired EGU closur es are among the higher quality jobs. Also, jobs associated with mining and tr ansportation of coal will be lost, creating a net loss of jobs for decades.551 Response to Comment 16: The agency’s analysis of impacts on retail electricity prices resulting from this rule shows that there is anaverage increase nationwide of 3.1% in 2015, with a range of increases from 1.3 to 6.3% in that same year. The employmentimpacts estimated by the agency include a shortterm increase of 46,000 job-years of construction labor , and a range of impacts on long-term labor from a loss of 15,000 to an increase of 30,000 jobs annually nationwide. We disagree th at the rule will cause the size of impacts that are presented in the NERA analysis, which actually estimates the impacts from four EPA power plant rules - not just from MATS, and has many flaw s. The EPA has conducted detailed economic impacts analysis on the regulated sector, a nd finds the impact of the rule on the regulated sector is small compared to the overall benefits, a nd the industry has an excellent track record of installing pollution controls without greatly impacting electricity prices. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. This is also consistent with the economic literature.

Comment 17 : Commenter 17761 expresses conc ern about the potential impact s on electricity rates and grid reliability problems created by the proposed rule and the cost of replacement generation alternatives. (The commenter shares the following link to the organizations resolutions concerning the proposed rule: See Resolutions ERE-5 and EL-3 at: http://summer.narucmeetings.org/20 11SummerFinalResolutions.pdf and http://www.naruc.org/Resolutions/Resolution%2 0on%20the%20Role%20of%20S tate%20Regulatory%2 0Policies%20in%20Development% 20of%20Fed%20Enviro%20Regs.pdf .)

Comment 18 : Commenter 17877 urges the agency to include in its consideration the negative impacts of increased electric power costs as it finalizes the rule and believes that significant changes should be made to the proposed standards.

Comment 19: Many commenters (17829, 17830, 17831, 17889, 17892, 18480, 18481, 18924, 19564, 19565, 19574, 19581, 19601) express concerns about the negativ e impacts that the pr oposed rule could have on the economy and ask that the EPA reconsider the rule.

Response to Comments 17 - 19: The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring public health is prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices.

Comment 20 : Commenter 17919 discusses the impact on the Federal Budget Deficit. The commenter explains that the federal government is a major c onsumer of electricity, and the proposed rule is estimated to increase the federal outlays for el ectricity by a minimum of $286 million annually, plus embedded energy costs associated with good and serv ices. States and munici palities will be likewise impacted.

Response to Comment 20: The UMRA analysis done by the agen cy 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 by the commenter in the analyses for the final ru le as well and found them to be reasonable in light of the exp ected benefits of the rule.

Comment 21 : Multiple commenters (12050, 17844, 17854, 17875, 17880, 18025, 18421) support the EPA’s impact analysis and disput e claims by other commenters thatthe projected rule will harm economic growth. Several commenters (12050, 17875, 18421) mention testimonials by power company CEOs stating that the proposed rule will not affect the economic hea lth of the industry and a survey showing nearly 60% of the coal-fir ed units already comply with th e EPA’s proposed Hg standard, as well as several other meaningful quotes from utility executives. Commenters also point out that 17 states already require plants to address Hg pollution, with some imposing more stringent emission limits than the EPA proposes. Commenters believe that utilities use the threat of power plant closures and lost jobs to delay Hg reductions from coal -fired plants. Commenters 17875 and 18421 also believe that the rules will drive innovation and job creation as new tec hnologies 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 Mass achusetts study that showed an increase in 1.4 million jobs in 5 years, and the Constellation Energy Group installation project that employed nearly 1,400 skilled workers. Commente rs 17844 and 17854 also cite the University of Massachusetts study statement that a net gain of over 4200 long-term operation and maintenance jobs will result.

Response to Comment 21: The agency thanks the commenters for their comments. The agency’s estimates of employment impacts, which are found in the RIA for the rule, are smaller than the commenters’ though we use a diffe rent methodology that focuses on impacts to the electric power sector. The EPA has conducted an updated employmentanalysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the a ffected sector and the overall economy.

Comment 22: Several commenters (17265, 17638, 17681, 18023) expr ess concern about the impact of the proposed rule on electricity rates and Florida’ s economy and job loss. Commenters believe the EPA has underestimated the impact. Commenter 17265 remi nds the EPA of the Presidential Order 13563 which calls for the EPA to exercise its authorityto minimize burden, explor e 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 th e elderly, minorities, and low income populations, resulting in:

1. Average electricity rate increase of nearly 25% 2. Gross State Product loss of near ly $18 billion (nearly 2.5%) 3. Annual job losses of 157,000 4. Unemployment rate of nearly 13% 5. Lost annual manufacturi ng output of $1.3 billion 6. Lost annual state and local governme nt tax revenues of $2.1 billion 7. Additional costs for control and monitoring equi pment, upgrading transmission capabilities and impacts to municipal generating utilities.

Response to Comment 22: The agency has estimated economic im pacts to the extent possible and as accurately as possible. The agency is also mi ndful 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 av erage retail electricity price na tionwide of 3.1% in 2015. The agency553 also estimates employment impact s of an increase nationally of 46,000 job-years due to construction of new pollution control equipment, and a range of a loss of 15,000 jobs to a gain of 30,000 jobs nationally for operating this equipment. We do not include em ployment estimates specific to individual states due to a lack of specific information to provide cr edible estimates. The EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 23: Commenter 19580 believes that if the EPA finalizes this rule it is only a matter of time before our strong manufacturing ba se moves overseas, taking high wage jobs. The commenter sees the proposed rule as an excessive regulation that will cost billions of dollars, lead to higher electricity prices and job losses as well as compromising reliability.

Response to Comment 23: The EPA has designed a rule that is inte nded to offer flexibility, to the extent possible, while ensuring public health is protected inaccordance with requirements outlined in the CAA. History has shown that industry adapts to regul ations 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 de tailed economic impacts an alysis 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 in stalling pollution controls without greatly impacting electricity prices. Based on the in formation provided in the RIA and supporting materials, the EPA does not agree that the impacts of th is rule will transfer significan t industrial production overseas.

Comment 24: Several commenters (19536, 19537, 19538) state th at the EPA is oblig ated to impose lower HCl emission limits because the cost-benefit an alysis did not quantify the improved reductions of other acid gases such as HF that should be achie ved with HCl controls, and the EPA’s cost-benefit analysis likely underestimates true benefits of a 0.0001 lb/MMBtu HCl limit. Also, commenters point out that the EPA analysis does not take into account the SO 2 controls required to meet other rules, so the costs are likely to be overstated.

Response to Comment 24: The agency has quantified the reductions in HF emissions as part of its analysis of the impacts of setting HAP emissions limits as part of the rule. We are unable to monetize the benefits of such emissions; this is also true of other acid gas HAP reduc tions that could occur as a result of this rule. Finally, the agency has included SO 2 controls in existence or pl anned that it is aware of for sources to be subject to this rule in the ba seline for the analysis presented in the RIA.

Comment 25 : Commenter 17648 believes the proposed rule will promote long-term economic health by encouraging investment in modern, efficient EGUs . The commenter cites upgrades to existing nuclear plants to improve zero-pollution nuc lear generation by several gigawatt s, investments in alternative, renewable technologies, co-generation, improved ener gy-efficient combined cycle gas-fired plants, modern coal-fired plants, coal gasification combin ed cycle plants and technology to recover domestic shale gas resources as potential opportunities.

Response to Comment 25: We thank the commenter for their comments and the data they have provided. The agency’s employment impact analysis does not include estimation of impacts using this BLS data, but we think our analysis of employment was appropriate given our approach and the data available to the agency for the proposal. Investme nt in more modern power generation capacity and pollution control technology is a li kely outcome of this rule. The agency does believe that retail554 electricity prices nationwide will be higher in 2015 as a re sult of the rule, though th at increase is modest (3.1% on average in 2015, with a range of regional impacts from 1.3 to 6.3%).

Comment 26 : Commenter 18419 cites the Edison Electric Ins titute study of impacts from the proposed rule and found that 50% of the U.S. coal fleet may be unavailable by 2015 due to insufficient time to acquire controls or find replacement generation. In addition, the commenter notes that the study shows that utility providers will spend up to $20 billion in the next 50 years dispos ing of coal ash, and the proposed ozone limits are also a concern if lowe red to 0.060 ppm because 13 of 14 monitored counties in Alabama will become non-attainment areas. Acco rding to the commenter, nationwide, 85% of monitored counties will become non-attainment for oz one and the cost for coming into attainment will be $20-$90 billion annually.

Comment 27: Comment 18488 cites the ICF report that c oncludes the proposed rule will impose incremental capital costs on industr y of $141-247 billion and will lead to significantly more retirements than the EPA predicts, leading to reliab ility issues and increases in costs.

Response to Comments 26 - 27: The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring public health is prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices. In addition, th e EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has al so shown that it can build new capacity quickly in response to dema nd. Studies done by industry have several flaws, including a poor reflection of the actual rule requiremen ts, inadequate inclusion of proven technologies, and unsupported speculation with regard to other policy, like climate policy. Changes to the national ambient air quality standards for ozone are not a subject of this rulemaking.

Comment 28 : Commenter 18023 states that the estimated costs do not include billions of lost economic productivity that may be incurred due to load shedding to manage the bulk power system.

Response to Comment 28: The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring public health is prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices.In addition, th e EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has al so shown that it can build new capacity quickly in response to demand.

Comment 29 : Commenter 17682 requests the EPA consider the added cost impacts for generation of electricity from coal, the cumulative impacts of new wind turbines and solar panels and new electrical distribution lines.555 Response to Comment 29: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 co al-fired generation. Industry has shown that it can install large amounts of pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has analyzed resour ce adequacy issues and finds that there is ample existing spare capacity to serve loa d, 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 ru le estimate of a 3.7% price increase for electricity in 2015, 2.6% in 2020 and 1.9% in2030. Commenter 17702 believes this increase will impact areas with dependence on coal and oil generation more than other regions, and the prices there will increase more. The commenter encourages the EPA to work with state and federal energy and environmental regulators to craft solutions that will enable utilities to comply with the proposed rule and other EPA rules to minimize cost impacts to consumers.

Response to Comment 30: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electric ity prices. Industry has shown that it can install large amounts of pollution controls and often finds more cost-effectiv e compliance options than the EPA can anticipate. In addition, the EPA has analyzed re source adequacy issues and finds th at 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 releva nt 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 measur es. In addition, there ar e certain provisions for granting utilities some additional time to co mply, if conditions warrant (see preamble).

Comment 31: Commenter 18033 considers the low estimate of early retirements to be one reason the EPA’s impacts are so much lower than other estimates . The commenter explains that the biases within the EPA’s model are incorrect because the model assumes that regions with excess supply will absorb the capacity lost by retirements, making retireme nt decisions a product of geography rather than economic factors.

Response to Comment 31: The EPA has conducted detailed updated economic analysis of the rule, and believes that the impact on potential retirement s to be driven by both economic and geographic (locational) consideratio ns, which the EPA modeling fully reflect s. In addition, the EPA has analyzed resource adequacy issues and finds that there is ampl e existing spare capacity to serve load, and industry has also shown that it can build new capacity quick ly in response to demand. The EPA will work with relevant authorities to ensure a smooth transition with this rule. P ublic utility commissions and other regulatory authorities have extensiv e experience with regulatory require ments and treatment of costs to consumers, and are prepared for responding to the co st of future pollution c ontrol equipment or other response measures. In addition, there are certain provi sions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 32 : Commenter 18961 cites a study done by a cons ortium of electric companies that found, “Industry data counter concerns that it will cost the industry too much to comply with EPA’s proposed air regulations, that pollution controls cannot be in stalled soon enough, or thatthe EPA regulations will lead to the closure of otherwise economically healthy power plants.” The commenter reports that the study also notes that the proven technologies for controlling Hg and other air toxics are commercially556 available, and adds that the coal-fired units that are most likely to be retired inthe face of the new rule are smaller, 40- to-60-year old un its that are already “ec onomically challenged ̈ a nd nearing the end of their design life expectancies. (Ens uring a Clean, Modern Electric Ge nerating Fleet while Maintaining Electric System Reliability, M.J. Bradley & A ssociates LLC and Anal ysis Group. August 2010. http://www.mjbradley.com/documents/MJBAand AnalysisGroupReliabili tyReportAugust2010.pdf )

Response to Comment 32: The EPA agrees with the commenter. The EPA has conducted detailed updated economic analysis of the rule, and believes that the impacts to be r easonable given the large benefits.

Comment 33 : Commenter 17761 states that the impact analysis conducted by the EPA is inaccurate and not comprehensive and needs to be re vised to account for true costs and benefits of the rule on regulated entities and the general public.

Response to Comment 33: The EPA has conducted as detailed and comprehensive an updated economic analysis of the rule as reasonably possi ble to reflect the true costs and benefits, and commenter does not substantiate the claims made.

Comment 34: Multiple commenters (16549, 17114, 17639, 17698, 17782, 18033) ask that the EPA delay indefinitely its proposed U tility MACT rule until further study can be undertaken on the potential costs and negative incomes to i ndustry, jobs, and consumers. Comm enters state that the current compliance deadline of 3 years does not meet the tests of reasonability or realism.

Response to Comment 34: The EPA does not have the flexibility to delay the rule, which is governed by a consent decree and the requirements of the CAA. However, it has conducted detailed economic impacts analysis on the regulated sector, and finds the im pact of the rule on the regulated sector is small compared to the overall benefits, and the industry ha s an excellent track reco rd of installing pollution controls without greatly impacti ng electricity prices. In additi on, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into comp liance. Sources may also seek a 1-year extension of the compliance period from their Title V permitting authority if the source ne eds that time to install controls.

Comment 35 : Several commenters (17811, 18436, 18478) offer support for the EPA’s proposed rule, stating that many power plants cu rrently utilize the technology re quired and the EPA is providing adequate flexibility in the require ments by allowing facility-wide aver aging for all HAP emissions from existing units in the same subcategory, effectively providing for equivalent, le ss costly technology in achieving the proposed emission standards. Comm enters 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 fr om the Jefferson County Health Dept. in Alabama that estimates 15 manufacturing bus inesses and roughly $5 billion in econo mic investments were lost in the Birmingham metro area due to n on-attainment air quality status.

Response to Comment 35: We thank the commenters for these comments. The EPA notes that the rule does not require specific technology, but that the leve l of performance called for by the rule is currently being achieved by a number of sources using certain technologies. The agency will be flexible in allowing sources to comply with this rule c onsistent with the requi rements of the CAA.557 Comment 36 : Commenter 17877 believes that finalization of the proposed rule will result in increased costs that non-profit cooperatives will need to pass on to consumers, which will negatively impact economic development and jobs.

Response to Comment 36: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies, and is unlikely to lead to extensive subs titution away from coalfired generation. Industry has shown that it can in stall large amounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy 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. The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule. P ublic utility commissions and other regulatory authorities have extensive experience with regulato ry 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 cert ain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 37: Commenter 18025 reports that their plants ar e 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 ge neration. The commenter states th at these installations were successfully coordinated with unit outa ges and position the faci lities to comply withthe proposed rule in advance of the deadlines.

Response to Comment 37: The EPA believes that coal units th at have already installed pollution controls will be well situated to comply with this rule by taking relatively modest steps to ensure compliance. The EPA also believes that the pollution control installations can be managed by industry. Industry has shown that it can inst all large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate.

Comment 38 : Commenter 18033 quotes legislative intentin The House Report on Section 112 that states: “In the determination of MACT for new and existing sources, considera tion of cost should be based on an evaluation of the cost of various co ntrol options. The Committ ee expects MACT to be meaningful, so that MACT will require substantial reductions in emissions from uncontrolled levels. However, MACT is not intended to require unsafe contro l 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 st ates their belief that th is is exactly what the proposed rule, in combination with other new or pe nding rules, will accomplish in addition to impairing electric reliability and increasing costs.

Response to Comment 38: The agency is not requiring the us e 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 numbe r 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 by 2015 in response to the rule, and this re sult is the product of business decisions rather than a specific requirement of the rule. This analysis has been updated for the final rule.

Comment 39: Commenter 18421 supports the EPA’s proposed rule and explains thatnew standards are always met with claims of infeasibility and impractic ality. Yet, the commenter st ates that history shows558 the reverse to be true. The commenter outlines prove n benefit-to-cost ratios of up to 23 to 1 for EPA regulations from 2000 through 2010 and economic gr owth and benefits from public health. The commenter also outlines cost-benefit ratios for re gulations from 1970-1990 that show a net benefit in present value over the period were $22 trillion and the benefits outweighed the costs by 40 to 1.

Response to Comment 39: The EPA generally agrees with comme nter’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 w ill 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 reliabi lity and affordability. The Commenter requests that the EPA reconsider the regulating of acid gases as they are not re quired 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 prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices.

Comment 41 : Commenter 18430 believes that job losses and cost burdens for consumers will outweigh any benefit from the proposed rule and asks that th e EPA reconsider the rule in light of the public comment and withdraw the proposed rule until further impact studies can be done.

Response to Comment 41: The EPA does not have the flexibility to delay the rule, which is governed by a consent decree and the requirements of the CAA. However, it has conducted detailed economic impacts analysis on the regulated sector, and finds the im pact of the rule on the regulated sector is small compared to the overall benefits, and the industry ha s an excellent track reco rd of installing pollution controls without greatly impacti ng electricity prices. In additi on, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. The EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into comp liance. Sources may also seek a 1-year extension of the compliance period from thei r title V permitting authority if th e 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. Commenter 18023 notes that less affordable electricity pri ces would have other indi rect consequences, such as the loss of energyintensive manufacturing operations, the loss of U.S. manufacturing jobs, a declin e in tax revenues, and risk to national security if military bases and ke y manufacturing and production operations do not have a steady and reliable supply of electricity. Commenter 17765 st ates that utilities are already requesting residential rate increases of up to 19% (see h ttp:/ /www.courier-journal .com/article/20110525/BUSIN ESS/305250080/LG-E-seek-19-rateincrease) and points out that recent regul atory 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 by Bernstein that predic ts costs in both the PJM and MISO RTOs are expected to go up significantly and remain volatile.

Commenter 18484 believes the proposed rule will cause irreparable harm to the economy and national security due to energy cost increases negatively affecting the ability to compete in the global market and increasing unemployment. The commenter believes increased energy costs will harm the development of mineral resources and the mining industry, resu lting in fewer projects and jobs and increasing dependency on foreign resources. The commenter explai ns that coal currently provides around 50% of electricity in the U.S. and the na tion has coal reserves to continue this for hundreds of years without even considering the massive coal reserves in Alaska . The commenter also says that coal resources have less environmental impact in many cases that altern ative energy production sin ce coal produces 100 to 1000 watts per square meter of land, while solar pr oduces 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 reflect s the cumulative impacts of using one compliance technology to control one pollutant onthe ability of other technologies to control other pollutants and that reflects the cost for makeup energy for lost generation and the ultim ate 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 bi o-fuels or not implement the proposed rule. The commenter also explains that the proposed rule with cost the governme nt more money for electricity as well, resulting in less money for basic servic es, including other environmental programs. The commenter requests that the EP A withdraw the proposal and de velop a more balanced rule.

Response to Comment 42: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies, and is unlikely to lead to extensive subs titution away from coalfired generation. Industry has shown that it can in stall large amounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy 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. The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule. P ublic utility commissions and other regulatory authorities have extensive experience with regulato ry 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 cert ain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 43: Commenter 18489 believes the estimated comp liance cost of $10.9 b illion will impact the economy and jeopardize the recovery our nation needs.

Response to Comment 43: As discussed elsewhere in this do cument, the EPA has conducted detailed impact analysis of the rule, which does not show significant impacts to the ec onomy, and the costs of the rule are greatly outweighed by the benefits.

Comment 44: Commenter 18907 foresees negative effects for smaller businesses, including retail gasoline outlets.560 Response to Comment 44: The EPA does not anticipate a notable im pact on retail gasoline outlets as a result of this rule, and its detail ed economic analyses, discussed else where in this do cument, show the impacts to businesses and consumers to be relatively small.

2. State/regional impacts, low income.

Comment 45: Commenter 17731 expresses concern that the EP A’s overview of the price increases does not see the hardships that will be the reality of increased prices on low-income or fixed-income households or small businesses. The commenter repor ts 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 inrates 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 cust omers will need to use less electricity due to economic necessity. The commenter also sees large pr ice increases for customers if units are converted to natural gas, which is approximately 2.5 times mo re expensive than the co al that the commenter currently uses to ge nerate electricity.

Response to Comment 45: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies, and is unlikely to lead to extensive subs titution away from coalfired generation. Industry has shown that it can in stall large amounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy 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. The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule. P ublic utility commissions and other regulatory authorities have extensive experience with regulato ry 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 cert ain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 46 : Commenter 17743 expresses particular concern over the proposed rule’s impacts on the Oklahoma economy, such as the poten tial increase of electri city rates and resul ting economic impacts on residents and businesses.

Response to Comment 46: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies, and is unlikely to lead to extensive subs titution away from coalfired generation. Industry has shown that it can in stall large amounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy 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. The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule. P ublic utility commissions and other regulatory authorities have extensive experience with regulato ry 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 cert ain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).561 Comment 47: Commenter 17772 is a utility with a large perc entage of coal-fired generation. As such, the commenter’s concern is the ability to meet custom er’s needs for electricity if the proposed rule is finalized, since it will le ad to unit closures.

Response to Comment 47: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies, and is unlikely to lead to extensive subs titution away from coalfired generation. Industry has shown that it can in stall large amounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy 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. The EPA will work with relevant authorities to ensure a smooth tr ansition with this rule. P ublic utility commissions and other regulatory authorities have extensive experience with regulato ry 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 cert ain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 48: Commenter 19213 states that the proposed rule c ould result in the re tirement of one or more units and increased electricity rates in Illinois, driving out businesses.

Response to Comment 48: The agency has estimated that less th an 2% of all coal-fired generating capacity may be uneconomic to maintain and remove d form operation by 2015 in response to the rule, and this result is the product of business decisions rather than a sp ecific requirement of the rule. The EPA has conducted detailed impact an alysis of the rule, which show s reasonable impacts to retail electricity prices. The EPA will work with relevant authorities to ensure a sm ooth transition with this rule. Public utility commissions and other regulatory authorities have exte nsive 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 so me additional time to comply, if conditions warrant (see preamble).

Comment 49: Commenter 19214 believes the EPA should e xpand the quantity and quality of their review so that accurate, realistic and broadly-accepted expectations of the cost, development timeline and performance of emission control system s can be considered in the final rule.

Response to Comment 49: The EPA has revised the detailed imp act analysis of the proposed rule for the final rule in a number of ways, and believes that the analysis presents an accurate and comprehensive evaluation of the rule’s impacts. The analysis incl udes the specific operating parameters and variability of other technologies, and is unlikely to lead to ex tensive substitution away from coal-fired generation. In addition, the EPA has analyzed re source adequacy issues and finds th at 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 releva nt 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 measur es. In addition, there ar e certain provisions for granting utilities some additional time to co mply, if conditions warrant (see preamble).

Comment 50 : Commenter 17911 questions the accuracy of th e RIA and states that the EPA skipped a number of procedural steps in thei r effort to meet the rule deadline. The commenter questions the EPA’s estimates as a result and calls into ques tion the EPA’s estimates of the following:562 1. Impact of Rule on the National Economy 2. Increase in Electric Rates (commenter expects co sts to increase by several percentage points) 3. Financing costs for emission retrofits 4. Loss of external revenue streams from sale of CCR 5. Increased costs for disposal of CCR 6. Loss of revenue from increased parasitic load at power plants 7. Decrease in Disposable Income 8. Increase in Cost of Operation for Small Political Subdivisions

The commenter requests that EPA conduct a more robus t study of the economic im pact of this rule.

Response to Comment 50: The EPA has analyzed many of these impacts, which can be found in the RIA of the rule. The EPA has not analyzed the impact of other regulations, which will be conducted in accordance with the relevant requirements for each individual rulemaking (like CCR).

Comment 51: Commenter 17774 discusses plant closures in South Carolina which are expected to occur in response to the proposed ru le. The commenter disagrees with the EPA’s prediction of job gains and believes job losses will be focused on co al-dependent regions like the southeast.

Response to Comment 51: The agency’s employment impact an alysis for the proposed rule shows some increase in short-term (i.e., by 2015) employment associated with the in stallation and operation of pollution control equipment. The EPA has conducte d an updated employment analysis which shows some potential positive and negative employment changes from the rule in the long-t erm, but overall expects the employment impact in th e short-term and long-term to be relatively small in comparison to the affected sector and the overall economy. This is also consistent with the economic literature.

Comment 52 : Commenters 18424 and 18425 believe the EPA has underestimated the impact of the proposed rule on EGUs burning bituminous coal and will severely impact the Indiana coal industry and Indiana jobs in general. The first commenter explains thatIndiana produces bitu minous coal and expects severe job losses in coal, mining and transportati on industries, which will have a multiplier effect causing more job losses throughout the state. The commenter quotes an ICC study showing Indiana job losses at more than 12,000 due to the loss of coal pr oduction. The commenter also notes that the cost of compliance will increase electricity costs and erode the competitive advantage enjoyed by Indiana in manufacturing, leading to a total loss of 50,000 jobs in the state.

Response to Comment 52: The EPA’s analysis of the rule shows that it is unlikely to lead to extensive substitution away from coal-fired generation. Industry has shown that it can install large amounts of pollution controls and often finds more cost-effectiv e compliance options than the EPA can anticipate. In addition, the EPA has analyzed re source adequacy issues and finds th at 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 releva nt 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 measur es. In addition, there ar e certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). The EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. This is also consistent with the economic literature.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 u tilization.

Response to Comment 53: The EPA analysis shows that industry can comply with the rule largely by installing pollution controls, and coal will continue to remain an important part of the generation mix. By addressing revisions to the NSPS and standards for emissions of mercury and other HAP, and by accounting for the multi-pollutant co-benefits of the rules, the EPA has sought to coordinate requirements for the control of multiple pollutants and thus is being responsive to the goal of multipollutant control strategies.

Comment 54: Commenter 19041 expresses concern that the proposed rule will have effects on the ability of their cooperative to pr ovide affordable and reliable se rvice to consumers in Ohio. The commenter reports that the coopera tive has already installed SCR on coal-fired units, and has or is installing scrubbers all for around $1.8 billion but is concerne d that it will not be enough to comply with the proposed rule.

Response to Comment 54: Utilities that have alr eady installed pollution contro ls are likely to be well positioned to comply with this rule with modest modifications.

Comment 55: Commenters 19653 and 19199 state a concern that the proposed rule will have an impact on the price of electricity in Indian a. The commenter sees the price of energy to be a major cost of doing business, and worries that increases in energy co sts will negatively impact businesses. Commenter 19653 especially expresses concern about the constructi on industry because the electricity cost impacts on construction could limit availability of affordable housing in Indiana. Also, di sruptions in service as a result of the compressed timeline could delay progress on new construction and remodeling.

Response to Comment 55: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 complianc e options than the EPA cananticipate. In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has also shown that it can build new capacity quicklyin response to demand. The EPA does not anticipate large impacts on the home construction industry, a nd is unable to see why the rule would impact availability of affordable hous ing since electricity prices are projected to increase only modestly.

Comment 56: Commenter 17805 has concerns about the poten tial economic and reli ability impacts of the proposed rule on customers in Montana and the Dakotas.

Response to Comment 56: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 issu es are not expected to be significant. Industry has shown that it can install large amounts of pollution controls and often finds more cost-effective compliance options than the EPA can anticipate. In addition, the EPA has analyzed resource adequacy564 issues and finds that there is ample existing spare capacity to serve load, a nd industry has also shown that it can build new capacity quickly in response to demand.

Comment 57: Commenter 18907 reports that a provider in the midwest has announced the shutdown of up to 25% of its coal-fired generating capacity, which will increase electricity rates. This price increase will impact businesses and create problems with remaining competitive for manufacturers.

Response to Comment 57: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 complianc e options than the EPA cananticipate. In addition, many announced coal retirements are due to reasons not related to EPA actions, such as low natural gas prices and lower electricity demand. These units are typically the oldestand least efficient units in the coal fleet.

Comment 58: Commenter 18933 states that textile production in North and South Carolina and Georgia will suffer from an estimated increase of 11.5%. Th is expense is likely to make the industry less competitive with foreign businesses.

Response to Comment 58: Retail electricity prices are proj ected to increase roughly 3.1% in 2015 nationwide, based on the agency’s an alysis contained in the RIA for th e rule. This increase, while not trivial, is not expected to yield significant impacts to manufacturers. The EPA’s analysis indicates that coal-fired generation will maintain its large share of gene ration. In addition, 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. The EPA has conducted de tailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 co mpliance options than the EPA can anticipate.

Comment 59 : Commenter 18502 expresses conc erns about the impact the proposed rule will have on Puerto Rico when the costs of compliance are passe d on to consumers. The commenter points out that the impacts of the proposed rule on the local economy will limit the economic recovery and increase electricity costs that are already twice those of the continental U.S. The commenter estimates that 70% of the electricity on the island is oil-fired generation and 70-75% of the consumers’ costs are for fuel, so the proposed rule will strongly impact the system reliab ility and costs, despite ha ving little benefit to an island with trade winds that produce excellent air qua lity. The commenter asks that the EPA reconsider controlling emissions from oil-fired units since the HAP emissions are much lower than from coal-fired units and the compliance costs are much higher.

Response to Comment 59: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic operating parameters and variability of other technologies and coal types, and is unlikely to lead to extensive substitution away from coal-fired generation. In addition, separa te standards are being fi nalized for non-continental oil-fired EGUs (see preamble).

Comment 60 : Commenter 18538 states that the Texas economyand service reliabi lity will be impacted by the proposed new rule. The commenter believes th e proposed rule will nega tively impact residential565 customers and energy-intensive business and the j obs they create. The co mmenter points out that environmental regulations in Europe have sent manufacturing businesses el sewhere. Commenters 18538 and 13526 state that because Texas generates more en ergy 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 re tirements will occur, and the future of planned plants is in question. Commen ters cite various studie s 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 inthe state, with one study estimating a reserve margin of -8.6%. The commenter states that the EPA’s impacts analyses are flawed and asks that theybe revised to consider the full impact of all th e new and proposed rules.

Response to Comment 60: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis includes the speci fic 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 complianc e options than the EPA cananticipate. In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has also shown that it can build new capacity quicklyin 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 experien ce with regulatory requirements and treatment of costs to consumers, and are prepar ed for responding to the cost of future pollution control equipment or other response measures. In addition, there are certai n provisions for granting utilities some additional time to compl y, if conditions warrant (see preamble).

Comment 61: Commenter 18538 states that a competitive mark et 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 th e 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 notdistinguish between energy markets, and participants in competitive ma rkets understand the risks inherent in those markets, such as the potential costs associated with po llution controls. In addi tion, these markets are largely driven by the cost of the marginal producing electricity generating unit(s), which is most often natural gas. Industry has shown that it can install large amounts of pollution controls and often fi nds more cost-effective compliance options than the EPA can an ticipate, irrespective of whether it is located in cost of service or competitive markets.

Comment 62: Commenter 18538 considers the EPA’s predicti ons about energy efficiency mitigating impacts of the proposed rule and ex plains that Texas has a robust e fficiency 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 efficiency measures that are likely to occur by 2015, but will continue to pursue energy efficiency improvements throughout the economy, along with other federa l agencies, states and other groups. This will contribute to additional environmental and public health improvements while lowering the costs of real izing those improvements.566 Comment 63: Commenters 17137 and 18021 believe that if the proposed rule is implemented with the current timeline and stringency, industryin the southeast, which relies onaffordable, reliable electricity, will be weakened, jobs will be lost, and power cons umers will be hurt. Commenters point out that the southeast is particularly vulnerabl e to the proposed rule because it relies heavilyon manufacturing and provides hundreds of thousands of jobs and billions in economic impact as a result. Commenters state that the abundant, reliable and inexpensive electricity from native coal resour ces is a factor in the thriving skilled labor market and foreign manufac turing investment. Commen ter 18021 points out that regulated utilities have no choice but to pass cost increases on to customers. The commenter also explains that in addition to capital costs, the addi tion of control technology reduces efficiency of the plants, increasing fuel costs.

Response to Comment 63: The implementation date for this rule is set to be consistent with the requirements of the CAA for standards such as these. Retail electricity prices ar e projected to increase roughly 3.1% in 2015 nationwide, based on the agency’s an alysis contained in the RIA for the rule. This increase, while not trivial, is not expected to yield significant impacts to manufacturers. The EPA’s analysis indicates that coal-fired generation will maintain its large share of generation. In addition, industry has shown that it can inst all large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate.

Comment 64 : Commenters 17712 and 17743 explain that cooper ative EGUs will generally need to add controls to comply with the proposed rule, and othe rs will need to shut down because they will be unable to comply in a cost -effective and timely manner.

Response to Comment 64: The EPA will work with relevant auth orities 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 EP A analysis also indicates that there will be relatively modest amounts of retirements and installation of pollution controls will be a cost-effective compliance measure. In addition, many coal facilities have already invested in pollution controls, and they are well positioned to comply with this rule with modest changes to operations.

Comment 65 : Commenter 17718 considers the pr oposed rule to be hardest on states which rely heavily on coal-fired plants and uses Kentucky as a state which is jeopardize d by the proposed rule due to the loss of inexpensive electricity givi ng it a competitive advantage at a ttracting industry. Kentucky runs the risk of seeing lucrative local busines ses such as auto plants leave the region if electricityprices increase due to the proposed rule.

Response to Comment 65: The EPA’s analysis indicates that co al-fired generation will maintain its large share of generation. In addi tion, industry has shown that it can install large amoun ts of pollution controls and often finds more cost-effective co mpliance options than the EPA can anticipate.

Comment 66: Commenter 17055 mentions that their initial assessment did not consider impacts the RICE regulations may have on the potential loss of small units relied upon by many municipalities. Elimination of these units could, the commenter believes, lead to local congestion and require transmission expansion and local programs to meet demand. The commenter believes that working with the industry to institute these change s will help preserve reliable system operations and also allow for a more gradual integration of the costs of compliance that could significantly mitigate reliability issues and sudden increases in consumer electricity prices.567 Response to Comment 66: The agency is currently reconsider ing the Compression Ignition and Spark Ignition RICE NESHAP. The outcome of this reconsid eration may affect the c ongestion and other issues the commenter points out.

Comment 67: Commenter 17821 explains the additional hardship s for small cooperative utilities, which often share several small units in order to split th e risk and increase reliabi lity. 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 pract ice standards, subcategorization, he alth-based compliance options or emissions averaging will adequately reduce the burdento such organizations and their financial wellbeing will be strained by the proposed rule. The co mmenter believes more flexibility is needed, as well as more time, to minimize risk to small businesses.

Response to Comment 67: The EPA will work with relevant auth orities 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 EP A analysis also indicates that there will be relatively modest amounts of retirements and installation of pollution controls will be a cost-effective compliance measure. In addition, many coal facilities have already invested in pollution controls, and they are well positioned to comply with th is rule with modest changes to operations.

Comment 68 : Commenter 17745 expresses concern over th e impacts on the Georgia state economy by the proposed rule, especially the increased cost of electricity and the impacts on residents and businesses.

Response to Comment 68: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electric ity prices. Industry has shown that it can install large amounts of pollution controls and often finds more cost-effectiv e compliance options than the EPA can anticipate. The EPA will work with relevant authorities to ensure a smooth transi tion with this rule. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). Although certain regions will need to do more in order to comply, those same regions will also benefit from the emission reductions. Overall, coal use is not anticipated to be greatly impacted as coal-fired sources install pollution controls, with only mode st amounts of retirements. Retail electricity prices are projected to increase slightly on averag e 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 prematur e 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 employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.

Comment 69: Multiple commenters (16705, 17400, 17697, 17868, 18038, 18433) consider the EPA’s RIA to be flawed in suggesting that only 97 muni cipal utilities will face a compliance cost of $666.30 million annually. Commenter 16705 states that these cost s underestimate the impact on states such as Indiana, Ohio, Wisconsin, Michigan, Minnesota, Ke ntucky, Georgia, Alabama and Texas. Commenter 17400 notes that these costs ignore Guam, where an additional $49 to $103 million is expected to be spent in capital costs with $1.2 to $2.6 million in a nnual costs. Commenter 17697 explains that the cost analysis 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 to Comment 69: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. Th e EPA has also updated its UMRA analysis. Industry has shown that it can install large amounts of pollution controls and often fi nds more cost-effective compliance options than the EPA can anticipate. The EP A will work with relevant authorities to ensure a smooth transition with this rule. In addition, there are certain provi sions for granting utilities some additional time to comply, if cond itions warrant (see preamble). There are also separate standards for non-continental liquid oil-fired EGUs . The EPA is addressing coal co mbustion residuals in a separate rulemaking.

Comment 70 : Several commenters (17689, 17697, 17710, 18433) explain Guam’s dependence on a single fuel-oil electric utility plan t 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 th e rule’s burden is unacceptable and that the cost of energy is a more signifi cant 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 Gu am’s power production comes from fuel costs. The commenters believe this rate increase will increase unemployment and cause economic hardship for the already disproportionately high pe rcentage of the island’s popul ation currently unemployed or underemployed.

Response to Comment 70: The EPA is required to regulate aci d gas HAP such as hydrochloric and hydrofluoric acids under this rule, as explained elsewh ere 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 71 : Commenter 17730 estimates that the proposed rule will cost hundreds of millions of dollars in initial capital costs for their region, whic h will be passed on to consumers in some of the top 100 poorest counties in the country.

Response to Comment 71: The agency’s analysis of changes in the national average retail electricity price associated with this rule finds is projected to be 3.1% in 2015. If this increase in retail electricity price is a concern, then state and local agencies are be st equipped to manage rate structures to mitigate any impacts associated with this increase. In additi on, the increase in retail el ectricity price should be understood in light of the substantia l benefits (including co-benefits).

Comment 72 : Commenter 17791 requests that the EPA avoi d compromising energy system reliability, seek ways to minimize cost impacts, ensure availa bility of electricity and natural gas, consider cumulative impacts of multiple rules and employ rigor ous cost-benefit analyses. The commenter also suggests the EPA consider regional differences that will impact system reliability and costs, such as the increased impacts on regions relying heavily on coal and oil and encourages cooperation between the EPA and state and federal energy and environmental regulators.

Response to Comment 72: The agency has studied possible impact s on reliability as a result of this rule, and has determined that these impacts should not be si gnificant. The agency has prepared a detailed TSD to document this study, and this document is the docket for this rulemaking. The agency has considered impacts on a regional basis as part of its overall analyses done using the IPM; these results are documented in the RIA for th e rule and in several TSDs.569 Comment 73: Commenter 18497 says the group’s six “footpr int 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 regi on’s summer generating capacity (143 units) can be considered at risk fo r 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 by 2015 in response to the rule, and this resultis the product of business decisions rather than a specific requirement of the rule. In addition, the EPA has analyzed resour ce adequacy issues and finds that there is ample existing spare capacity to serve loa d, and industry has also shown that it can build new capacity quickly in response to demand and also manage the installa tion of pollution controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule. P ublic utility commissions and other regulatory authorities have extensiv e experience with regulatory require ments and treatment of costs to consumers, and are prepared for responding to the co st of future pollution c ontrol equipment or other response measures. In addition, there are certain provi sions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 74: Commenter 17829 explains that their power supplier estimated that if scrubbers are required for their plant, the cost could reach $1 bill ion. The commenter goes on to state that the resulting cost increase will most impact the elderly, poor and those who have lost jobs at a time when the Low Income Home Energy Assistance Program has been decreased significantly.

Response to Comment 74: The rule does not dictate any part icular technology and the EPA has attempted to provide the maximum de gree of flexibility to source owners within the limitations of the CAA. The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The analysis indicates that coal will remain the largest source of electricity. Industry has shown that it can inst all large amounts of pollution controls and often finds more costeffective compliance options than the EPA can anticipate. In additi on, the EPA has analyzed resource adequacy issues and finds that there is ample existi ng spare capacity to serve load, and industry has also shown that it can build new capacity quickly in res ponse 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 exte nsive 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 so me additional time to comply, if conditions warrant (see preamble).

Comment 75 : Commenter 17884 quotes NMA statistics show ing 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 su ch as Appalachia, the midwest and Rocky Mountain west will be significantly affected by the rule, including increased unemployment.

Response to Comment 75: The agency’s analysis as found in the RIA shows that the overall impact of the rule to be relatively small, in the context of the entire power sector. Although certain regions will need to do more in order to comply, those same re gions will also benefit from the emission reductions. Overall, coal use is not anticipated to be greatly imp acted as coal-fired sources install pollution controls, with only modest amounts of retireme nts. 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 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 employment analysis which shows some poten tial positive and negative employment changes from the rule, but overall expects the employment im pact to be relatively small in comparison to the affected sector and the overall economy.

Comment 76 : Commenters 17901 and 18023 state that communiti es near existing coal-fired generation units will be especially hard-hit if the plants are permanently retired. The communities will suffer from job loss and diminished tax revenue.

Response to Comment 76: Although it is possible that there may be some negative local economic impacts associated with this rule, impacts such as retail electricity price increases should be modest. Also, the estimated number of early retirements accordi ng to the agency that may result from this rule is 4.7 GW in 2015, or about 2% of all U.S. coal-fired capacity in that year. Overall, coal use is not anticipated to be greatly impacted as coal-fired sources install po llution controls, with only modest amounts of retirements. These resu lts are presented in the RIA for the rule. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overa ll economy. Although certain regions will need to do more in order to comply, those same regions will also benefit from the emission reductions such as through reduced premature mortality from less exposure to PM 2.5 emissions as shown in Appendix C of the RIA.

Comment 77 : Several commenters (18422, 18433, 18575) reque st that the EPA reconsider the regulating of acid gases as they are not required and will impose greater cost and difficulty. The commenters ask that the rule be reevaluated to be more realisti c and cost-effective.

Response to Comment 77: The agency believes the regulation of acid gases that are HAP is both required and appropriate under this rule. The preamble to this rule provides the rationale for this position.

Comment 78: Commenter 18447 disagrees with the EPA’s assessment that the reductions can be achieved without significantly affecti ng availability or cost of electric ity and with an increase in jobs. The commenter expects job losses from the proposed ru le and explains that the City of Ames, Iowa has one base load plant and two dies el combustion turbine “peakers” and cannot shift power away from older units to newer plants. The co mmenter explains that while switch ing to natural gas may seem like the preferred compliance option, ther e is not enough of a natural gas supply to support the needed generation. Also, the city’s power plan t provides disposal for all munici pal 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 dispos al 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 ysis indicates that coal will remain the largest source of electricity. The EPA will work with relevant authorities to ensure a smooth transition with this rule and address specific issues. Public utility commissions and other regula tory authorities have extensive experience with regulatory requirements and treatment of costs to consumers, and are prepared for responding to the cost of future pollution contro l 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 79 : Commenter 17648 offers projections showing th at 2015 electricity prices in most areas will be the same or lower than they were in 201 0 as a result of the proposed rule. The commenter retained NorthBridge Group to estima te the potential rate impact resul ting from the proposed rule on its customers in both the ComEd and PECO service te rritories. NorthBridge c oncluded 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 partlydue to the decline in natural gas prices in recent years. Exelon’s customers will benefit from lower gas prices, and this price decline will mitigate any potential rate increases related to the Toxics Rule. The results of NorthBridge’s analysis are set forth in Figure 1 (See 17648-A2_Figure 1_ComEd and PECO Generation Rates.docx).

Response to Comment 79: The Commenter’s statements are not inconsistent with the results of EPA’s analysis, which indicates that impacts on retail electr icity 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 n ecessary, called “capacity markets.” The commenter suggests that capacity markets need more oversight to ensure newer, more advanced facilities take precedence over less efficient plants because Sy napse Energy Economics states that capacity markets keep electricity prices high and less efficient pl ants operating. 2. The commenter also suggests pushing FERC to be more proactive about market violations by encouraging competitive regional markets with ba lanced rules, monitoring such markets for anticompetitive behavior and enforce market rules. 3. The commenter also suggests better energy efficien cy programs for domestic and imported electric products and better building codes to decrease energy demand can save consumers money and limit the amount of pollution released by EGUs.

Response to Comment 80: We thank the commenter for these suggestions. The agency has worked with FERC and other Federal agencies to examine ways of mitigating potential negative consequences associated with this rule. The EPA believes that ther e are many approaches that can help mitigate price increases, and is a strong supporter of energy effici ency measures. The EPA will work with relevant authorities to ensure a smooth transition with this rule and address specific issues. Public utility commissions and other regulatory authorities have extensive experien ce with regulatory requirements and treatment of costs to consumers, and are prepar ed for responding to the cost of future pollution control equipment or other response measures.

Comment 81 : Several commenters (17682, 17884, 18033, 18484, 18023) consider the proposed rule to be a tax on the American public, since utilities implementing upgrades will pass the costs on to the consumer. Commenter 17682 questions the preference of Americans to subsidize renewable energy sources and put money into the proposed rule inst ead of other environmental programs with greater benefits. Commenters 17884 and 18484 e xplain that the tax-like pri ce increase reduces income of energy consumers and depresses busin ess development. The commenters used California as an example of a state that uses low rates of co al-based electricity and cite companies that have left the state as a result of substituting higher-cost forms of electricityfor coal. Commenter 18033 states that coal-derived energy will rapidly become more expe nsive, especially in the “rust be lt” and southeast region, as can be seen by the rate increase alre ady requested in Louisville. Co mmenter 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 am ounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy issues and finds that th ere is ample existing spare capacity to serve load, and industry has also shown that it can build ne w capacity quickly in resp onse to demand and also manage the installation of pollution controls. Although el ectricity consumers will likely see a small price increase, it should be noted that these consumers will also experience the improvement in air quality from the reductions due to the rule, and the benefits of this improvement will greatly exceed costs. The price increases in electricity and na tural gas should be considered in light of the substantial benefits offered by this rule. In addition, history has shown that the impact of EPA regulations is much lower than anticipated, and predictions of severe economic impact have been often repeated, but not realized.

Comment 82 : Commenters 16705 and 18038 believe the proposed rule will have a significant impact on jobs in their community and increase th e electric rate, driving out businesses.

Response to Comment 82: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ysis indicates that coal will remain the largest source of electricity. Industry has shown that it can install large am ounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 83 : Commenters 16856 and 18038 believe the prop osed rule will severely impact the economy of the coal-producing states and utilities that provide almost 50% of their electricity from coal. Commenters ask that the EPA bring jobs back to the U.S. and stop sending manufacturing jobs to countries where environmental impacts are not considered.

Response to Comment 83: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The anal ysis indicates that coal will remain the largest source of electricity. Industry has shown that it can install large am ounts of pollution controls and often finds more cost-effective complian ce options than the EPA can antic ipate. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 84 : Commenter 17627 considers the EPA’s RIA document to be lacking in local economic impacts associated with reduced operations or plant closures.

Response to Comment 84: The EPA has conducted detailed impact analysis of the rule, which includes regional information and impacts, and more detail can be found in the corre sponding IPM output files for the final rule, which has deta il for the 32 power regions across th e country. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.573 Comment 85 : Commenter 17701 mentions that the proposed rule will have different reliability and cost effects on different regions of th e country due to differing resources , transmission and capacity, market structures, approaches to energy efficiency, transmission options, el ectricity demand projections and

consumer concerns.

Response to Comment 85: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. The an alysis provides a rich char acterization of regional issues, and reflects the differences in the power sector composition acros s those regions. The impact of the rule will vary across regions, and the EPA ha s presented some of those impacts in the RIA.

Comment 86 : Commenter 18030 quotes the NERA study coul d cost Michigan 40,000 jobs and increase electricity prices by 20.5% in 2016 and likely lead to the closing of numerous Michigan plants. The commenter requests the implementation of the proposed rule be suspended.

Response to Comment 86: The EPA has designed a rule that is intended to offer flexibility, to the extent possible, while ensuring public health is prot ected 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 pr edict, thus lowering the actual cost of its rule relative to what the EPA initiall y 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 ha s an excellent track record of in stalling pollution controls without greatly impacting electricity prices. The report cited by the commenter is not transparent with regards to several key criteria, and it is thus impossible to fully assess the credib ility of the results. It has often been claimed that regulations do harm to the economy and jobs, but th e evidence is weak or nonexistent, while there is a large body of literature that shows overall, the impacts of regulations on jobs and the economy is very small.

Comment 87 : Several commenters (17705, 17732, 18540) discuss the unique situatio n of the Navajo Generating Station (NGS), which pl ays a key role in water delivery to Native American communities, farmers and cities in Arizona and which provides cr itical energy to the region. The plant also provides good jobs to 540 skilled workers and provides ec onomic support for several communities through tax payments and other jobs. The plant also helps the U. S. meet its federal trus t responsibilities under the 2004 Arizona Water Settlements Act, and provides pow er and funding for the Central Arizona Project (CAP). The commenter states that the IPM model defi nes the plant as uneconomic to maintain, but given the importance of the facility, the owners want to work with the EPA to retain the plant. The commenter believes the NGS should not have to install a baghouse to comply with the proposed rule and asks that the EPA evaluate all impacts of cl osure on the Navajo Nation on a region al economic basis, rather than on a Nation-wide basis. Commenter 18017 agrees with these comments and expresses concern about the closing of NGS affecting many enti ties, if sufficient time isn’t gi ven for compliance. The commenter details the difficulties to this region of Arizona w ould have in finding alternative power sources for electricity use and to pump water. The commen ter estimates pumping costs could go up 50-300% by 2017. Commenter 18540 explains that it receives its en tire water supply through the CAP system and is concerned with the effect of the proposed rule on th e viability of the CAP. Th e 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 asse rt water claims held from “time immemorial” in return for specifi c provisions by the U.S. governme nt of water from the CAP and Yuma-Mesa Division of the Gila project. The comme nter explains the various water settlement legislation in place and urges the EPA to carefullyconsider the possible effects of its proposed rulemaking on the continuing viability of the CAP syst em 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 Consultation Policies.

Comment 88 : Commenters 17732 and 18017 report that the po wer plant associated with the Navajo Nation (FCPP) employs nearly 600 people, most of them Navajo Nation members. The commenter goes on to explain that the Navajo Mine provided $69 m illion into the Navajo Nation’s revenue in 2007 and employs 427 people, 87% of whom are Navajo tr ibal members. The Peabody Kayenta Mine employs another 400 workers, many of whom are Native Amer ican. 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 estima tes that revenues derived from the plants and mines make up 88% of their tribe’s opera ting budget. Details of this revenue and supporting numbers may be found at: http: //www.navajobusiness.com/pdflCEDS/CED NN Final_09_10.pdf

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Comment 89 : Commenter 17732 describes the impact of EP A regulation shutting down the Mohave Generating Station, which led to th e closing of the Black Mesa Mine. The commenter explains that 160 people were put out of work at the mine, and Navajo Nation’s general revenue was decreased by 30%. The commenter states that if the proposed regulati ons lead to a shutdown of the remaining two power plants due to cost-prohibitive em ission controls, the mines supplyi ng them would also close. These closures would lead to revenue a nd job losses so extreme they would impugn the solvency of the Navajo Nation government. The commenter states that the EP A failed to analyze the impacts to the Navajo Nation as part of the impact analysis. The comment er points out that unemployment is over 50% among the Navajo people, and no skilled labor force or indus try exists in the pollution control technology field among their population. Therefore, the new jobs expected to be create d by the proposed rule would not help the Navajo Nation, but the closing of the coal and power industry would lead to the loss of 31,000 jobs. This would force migration of many worker s, a “social cost” not analyzed by the EPA.

Comment 90: Commenter 19214 requests that the Table 8.8 s howing that NGS will be likely to shut down by 2015 be changed to show continued operation of this important coal-fired plant. The owners acknowledge that the rule will be ch allenging, but are committed to working with the EPA to keep this critical resource open.

Response to Comments 87 - 90: The EPA modeling and projections ar e intended to be a reflection of possible compliance using specific t ools, assumptions, and methodologies that the agency believes to reflect the best and most current in formation related to the power sector. It is not intended to reflect actual compliance decisions, since those will be made individually by the affected industry based on what makes most sense using existing technologies or other, more cost-effective strategies. The EPA will work with relevant authoritie s to ensure a smooth transition with this rule and address specific issues as they arise. Public utility commissions and other authorities, such as tr ibes, will need to develop and implement compliance plans in or der to address harmful emissions.

Comment 91: Commenters 17807 and 17901 expresses concern about economic impacts to residential and commercial customers, particularly minoritie s, the elderly and economically disadvantaged
customers.

Response to Comment 91: The EPA has conducted detailed impact analysis of the rule, which shows reasonable impacts to retail electricity prices. Th e average impact on household energy expenditures (electricity and gas) is anticipat ed to be less than $3 per month.575 Comment 92 : Commenter 17813 questions the results of th e IPM model because it shows a heat input of 25.353 TBtu for their facility, while averag e from 2006-2010 is 35.285 TBtu. Because of this discrepancy, the commenter questions the assumption that the plant will retire.

Response to Comment 92: The EPA modeling and projections ar e intended to be a reflection of possible compliance using specific t ools, assumptions, and methodologies that the agency believes to reflect the best and most current in formation related to the power sector . It is not intended to reflect actual compliance or retirement decisions, since thos e will be made individually by the affected industry based on what makes most sense using existing technol ogies or other, more cost-effective strategies.

Comment 93 : Commenter 17815 reports that in 2010, coal -fueled generation provided approximately 40% of electricity in the El ectric Reliability C ouncil of Texas region and provided over 33,000 permanent jobs as well as $10 billion in annual e xpenditures. The commenter says that the average income for a lignite mining employee in Texas is 2.14 times the state average income for all industries and has a tax contribution of $1.012 billion.

Response to Comment 93: The EPA has conducted detailed impact analysis of the rule, which provides a rich characterization of regional issues, and reflec ts the differences in the power sector composition across those regions. The impact of the rule will varyacross regions, and the EPA has presented some of those impacts in the RIA. Overall, coal-fired generation is not expected to cha nge significantly since sources are anticipated to insta ll pollution controls. In additio n, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy

Comment 94: Commenter 17901 questions the benefits of the proposed rule in the face of job losses likely to hit coal-producing regions especially hard. Commenter 18500 ag rees and points out that some regions will see almost no impact from the rules, su ch as the Pacific northwest while the midwest and other regions will face large cost increases.

Response to Comment 94: The EPA has conducted detailed impact analysis of the rule, which provides a rich characterization of regional issues, and reflec ts the differences in the power sector composition across those regions. The impact of the rule will varyacross regions, and the EPA has presented some of those impacts in the RIA. Overall, coal-fired generation is not expected to cha nge significantly since sources are anticipated to insta ll pollution controls. In additio n, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 95: Commenter 18430 cites a Unions for Jobs and the Environment (UJAE) study that estimated job losses due to the proposed rule to be over 250,000, with more than 11,000 in Virginia. The commenter states that the importance of the coal industr y to Virginia makes that state especially painful.

Response to Comment 95: The EPA has conducted detailed impact analysis of the rule, which provides a rich characterization of regional issues, and reflec ts the differences in the power sector composition across those regions. The impact of the rule will varyacross regions, and the EPA has presented some of those impacts in the RIA. Overall, coal-fired generation is not expected to cha nge significantly since sources are anticipated to insta ll pollution controls. In additio n, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the576 rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 96: Commenter 18477 believes that non-continenta l oil-fired EGUs should have a separate regulatory impact analysis. The commenter explains th at non-continental utilities have fewer economic resources available to address propo sed rule requirements and as regul ated utilities they must obtain approval for rate increases to offset costs. Since non- continental electricity prices are already higher than on the continental U.S. the economic consequences associated with comp liance 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 associat ed with the proposed rule, as well as its effect on the economy and public health. The commenter asserts thatthe RIA only addressed coal-fired EGUs; the EPA stated that it would address regulatory impacts rela ted to liquid oil-fired units in th e final rule. Of the 154 oil-fired EGUs identified in the proposed rule, 31 of the un its are located on the islands of Oahu, Puerto Rico, and Guam. The commenter states that since the EPA intends to analyze regulatory impacts related to oilfired units as part of the final rulemaking, the EP A should address non-continen tal liquid oil-fired units separately in that analysis.

Response to Comment 96: The final rule contains provisions th at are specific to non-continental liquid oil-fired EGUs. See preamble for further disc ussion of the treatmen t of these sources.

3. Retiring coal-fired EGUs, shutdowns.

Comment 97: Commenter 17403 says that capital that will be deployed by EGU owners to implement emissions control measures under the proposed rule s hould create well-paying jobs for skilled workers across the country. However, the co mmenter goes on to say that prem ature shutdown of existing coalfired EGUs will also result in an estimated 50,000 directjob losses in the coal, ut ility and rail industries with a total job loss including i ndirect jobs of 251,300. The commenter considers the costs and benefit analyses of the proposed rule to be incomplete and misleading and the proposed ru le structured to avoid unnecessarily eliminating jobs.

Response to Comment 97: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired cap acity). In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 98: Multiple commenters (17623, 17656, 17834, 17868, 17930, 18018, 18497, 18023) discussed predictions for the number of coal-fired E GUs that are likely to retire as a result of the proposed rule and Transport ru le. Several commenters (1762 3, 17868, 18497, 18023) cite and provide references to seven studies predicting retirements of 5 to 65 GW in 2015, where six of the seven predict retirements of 35 GW or more. Commenter 17656 estimat es that the proposed rule, when viewed in conjunction with the entire body of new regulatory initiatives on the ut ility 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 coul d jeopardize 30 to 70 GW of generating capacity by 2015. Commenter 17834 predicts the early closure of many facilities as a result of the proposed rule and reports that these EGUs play a central role in a region’s economy since they are a source of jobs and577 contribute to the tax base. Commenter 17868 believe s that the EPA has grossly underestimated the number of coal-fired generation reti rements at only 9.9 GW, which is only 3% of all coal-fired capacity by the year 2015. The commenter believes that the EP A chose to view the proposed EGU NESHAP in isolation and not in the CSPAR (the replacement of the Regiona l 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 disc usses the resulting problems from the predicted shut downs, which include adverse impacts of displaci ng coal-fired generation with other forms that do not provide the same kinds of grid support functiona lity, increased interconnec tion 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 f acilitate transmission fac ilities is also mentioned, and Commenter 18023 requests a thorough reliability analysis given the compliance framework and timeline of the proposed rule.

Response to Comment 98: The agency prepared a resource adequ acy analysis for the proposed rule and has revised that analysis for the final rule. The ag ency is working with FERC regarding the reliability impacts of this rule. The EPA estimates 4.7 GW of capac ity will retire early as a result of this rule. We have not prepared a cumulative impacts analysis fo r the various power sector rules that have been finalized or are in process of bei ng finalized because the agency does not believe such an analysis would be as accurate and transparent as analyses for each of these individual rules. The EPA has outlined the various flexibilities associated with the rule, and the approaches to re liability issues in the preamble.

Comment 99: Commenter 17648 discusses the economic factor s behind EGU retirements. These factors include the cost of alternative generation using na tural gas, the cost of implementing demand response measures that can be bid into capacity markets, and the cost of continuing to generate power from an existing unit. The commenter states that regardless of the costs associated with the Toxics Rule and other EPA electric power industry regulations, so me power plants were already economically unsustainable. The commenter quotes M.J. Bradley, w ho points out, “Of the 122 coal units in PJM with capacity less than or equal to 200 MW, 35 failed to recover their avoidable co sts and another 52 were close to not recovering those costs. Therefore, in PJM . . . in addition to approximately 10 GW of coal generation that has or will be retired during the seven years from 2004 to 2011, another 11 GW faces a troubling economic outlook.” The comm enter provides confirmation of this by the most recent PJM capacity auction, where approximately 6.9 fewer GW of coal-fired capacity cl eared the auction (1.85 fewer GW were offered) as compared with the pr ior 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 ar e overstated and misleading. The commenter gives the example of the American Electric Power attempt to li nk its planned plant closur es to the Toxics Rule, but those plants already are slated to either close or to upgrade contro ls to comply with existing laws. The commenter goes on to quote three independent st udies that support the findi ng that over 50% of the fleet is equipped with scrubbers and the number will increase to nearly2/3 by 2015. (Footnotes in comment provide references to the studies and further quotes.)

Response to Comment 99: As discussed elsewhere in this document and in the preamble to this rule, the EPA believes there will be modest levels of coal retirements, and many units slated for retirement are being taken offline for other reasons aside from requi rements to reduce emissions.

Comment 100 : Commenters 17812 and 17736 believe the proposedrule will adversely affect the costeffective operation of industry energy operations and quote the U.S. Chamber of Commerce testimony before Congress: “American Electric Power Co. made headlines last mo nth 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 th e utility to retire 6,000 megawatts of coal-fired ge nerating capacity and spend another $6 billion to $8 bi llion reworking the rest of its fl eet.” AEP would close three power plants in West Virginia, one in Oh io and one in Virginia, and would re tire several boilers at coal plants in Indiana, Kentucky, Oh io, Texas and Virginia.

AEP is not alone. Six other power plants have announ ced early retirement due to excessive regulation: Portland Gas & Electric’s Boardman coal-fired po wer plant in Oregon; Exel on Corporation’s Oyster Creek Nuclear Generating Station in New Jersey; TransAlta Corporatio n’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 installin g several hundred million dollars’ worth of pollution controls to comply with the EPA regulations, or simp ly shut down early. In all cases, the utility chose early retirement.”

Commenter 17812 also expresses con cern that increasing energy costs will reduce the ability of U.S. industry to compete in the global marketplace, expand in the U.S., cr eate jobs and increase contribution to the GDP. The commenter quoted the 2010 EIA outl ook which showed a 9.1% decline in industrial electricity demand, the lowest since 1987.

Response to Comment 100: As discussed elsewhere in this documen t 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 requi rements to reduce emissions.

Comment 101 : Several commenters (17682, 17813, 17904, 17930) me ntion the proposed rule’s impact on mining. Commenter 17682 mentions in creasing energy costs for the U. S. mining industry resulting in fewer projects and associated jobs, as well as increasing dependence on foreign mineral resources. Commenters 17904 and 17930 see mining impacts being di sproportionally large for lignite mines, which are dependent on their co-located lignite-fired power plants. Commenters state that if the plant closes, there is no market for the lignite and the mine will al so close, displacing plant workers. These impacts are largest in Texas, the largest coal consuming stat e and fifth largest coal pr oducing 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 partic ular believes the proposed rule does not take into account the emission reductions alre ady achieved by industry in general and their company in particular. Commenter 17813 states that impacts will be magnified in Texas, since it is the largest coal consuming state and mines lignite. Commenter 17813 also states it is unclear the extent to which the EPA includes the impacts on the mining industry that will result from this rule.

Response to Comment 101: The agency presents impacts on the coal mining sector from this rule in the RIA. Given the modest increase in coal and other en ergy 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 analysis indicates that there will be a small amount of coal retirements (less than2% of all coal-fired capacity). In addition, the EPA has conducted an updated empl oyment analysis which shows some potential positive and negative employment changes from the rule , but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 102 : Commenter 18500 states that the EPA has ju stified 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 regul ation on market parity, the EPA579 must recognize that by changing market dynamics in single clearing price mark ets, every incremental increase in price applies to all electricity sold in th at market, not just to the impacted unit. Given that half of the American population lives in Regi onal Transmission Organizations (RTOs) where incremental cost increases apply to all energy costs, this will be a si gnificant factor. The EPA has failed to account for the impact these rules will have on the total cost of energy across RTO markets where every incremental increase in price applies to all electricity sold in that market, not just to the impacted unit, while at the same time asserting beneficial market impacts.

Commenter 17868 asks that the EPA address the unproductive costs of compliance that occur due to RTO market structures, since the rule is expected to l ead to plant closures of pl ants dispatched to meet demand. As a result, power generated by plants not faci ng 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 pl ant can affect the prices paid for by all the electricity generated by nuclear, hydropower, wind, and all other plants within that hour. The commenter believes this market structure will lead to costs be yond that of compliance being passed on to consumers and gives the following example: “i n the most recent Reliability Pricing Model (or RPM) auction, held in May 2011 to procure capacity for the June 2014 through May 2015 time period, a number of plants added to their supply offers the co sts associated with instal lation of emission control technologies to meet environmental regulations. PJM estimated that th ese higher costs were responsible for at least half of the 350% price increase between th e past two auctions in the western region of PJM, from $27.73 per MW/day to $125.99 per MW/day. Although the number of units or MWs that included these compliance costs is not yet available, PJM’s graphical representation shows that of the roughly 150,000 MW that cleared the auction and will receive this capacity pr ice, about 120,000 MW offered to sell capacity at a zero or close to zero price. (Zer o price offers are typically submitted by existing base load plants who are price takers in the auction.) Th erefore the half of the $98 price increase attributable to environmental upgrades will be paid to a ll 120,000 MWs of capacity that did not include environmental compliance costs in their offers, equal to an unproductive cost of at least $2.1 billion for just one year...These factual P JM auction results from May 2011 de monstrate that the U.S. EPA’s assertion that the electricity consum er will see no more than a 3.6% incr ease in the cost of electricity does not match recent actual market performance. Th e U. S. Census reports that currently there are 307,006,550 people in the U.S. and approximately 51 million of them live in the PJM Market. This means that approximately 15% of the U.S. popula tion is affected by PJM Market” The commenter provides figures showing how coal plant closures will impact different locations. (EPA-HQ-OAR-2009- 0234-17868-A2)

Response to Comment 102: The EPA provides regional estimates of the projected retail electricity price impacts of the rule, and the impacts vary across regions for a variety of reasons (market structure being one of them). In addition, the auction results cited are not a reflection of retail price impacts, which will be dampened since the cost of generation is just one of several components of retail prices. The auction also resulted in significant new capac ity and additional demand-side resources, which show that there are multiple avenues for how utilities can respond to the requirements of this rule. The auction also indicates that there will be adequate reserve margin. The most important point that the commenter ignores is the baseline. The EPA a ssesses the impacts of its rules not in relation to what is happening today or from the 2013/2014 PJM auction, but in relati on to what would have happened in the absence of this rule in the same year (in 2015 for MATS). The commenter is unable to fully ascertain, based on the analysis presented, the incremental effect of the rule alone and is lumping in other important industry trends and dynamics that will impact future prices. The EPA has updated its analysis of price impacts of MATS, which are presented in the RIA on a regional and nationwide basis.580 Comment 103 : Commenter 18497 explains that the EPA’s re tirement 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, Mi chigan, Ohio, and Wisconsin), ICF identified 25 GW of at-risk capac ity- more than in all other census regions combined and over two times the next most impacted region (East South Centra l - 11 GW). The Brattle Group analysis estimated 50- 65 GW of coal-unit retirements nationwide by 2020 based on the need to install scrubbers and SCR controls. Of that total, 12-15 GW were located in the Midw est Independent Transmission System Operator (MISO) regional transm ission organization (RTO), and 8- 15 GW were located in the PJM Interconnection (PJM). The commenter references th e DOE deputy assistant secretary for clean coal, James F. Wood who states, “Number one, electric rate s are going to go up. Number two, whether or not construction jobs in the green indus try are created, I think there’s [s ic] virtually no manufacturing jobs that are likely to be created from the replacement of coal. Three ... transmission gr id 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 imp act shutting down one power plant could have on the local community. The commenter also quotes the Cred it Suisse analyses showi ng around 60 GW of coal closed in 2013-2017 and 100 GW requiri ng 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 Tc f increase in annual natura l gas demand, leading to increased prices as much as $92/MW a day.

Response to Comment 103: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 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 ar eas of flexibility. The analyses also conflate other issues , like natural gas prices and low electric ity demand, and do not isolate the effect of this rule separately. The EPA believes there will be modest levels of coal retirements, and many units slated for retirement are being taken offline for other reasons as ide from requirements to reduce emissions. The impact of the rule will vary across regions, and the EPA has presented some of those impacts in the RIA. Overall, coal-f ired generation is not expected to change significantly since sources are anticipated to install pollution controls. The EPA will work with relevant authorities to ensure a smooth transition with this rule and address specif ic issues. Public utilitycommissions and other regulatory authorities have extensiv e experience with regulatory require ments and treatment of costs to consumers, and are prepared for responding to the co st of future pollution c ontrol equipment or other response measures. In addition, the EPA has conducte d an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.

Comment 104 : Commenter 16469 states that the coal units more likely to retire due to the proposed rule are over 40 years old, under 400 MW and are cycling or “load-following” units for which the costs associated with additional controls would be too high for the infrequently run units to recoup. The commenter expects combined cycle natural gas units to pick up the share of generation for these units.

Response to Comment 104: The EPA agrees with the commenter.

Comment 105: Commenter 17881 explains the process by which the regulated utility created a Strategic Plan with the state and the EPA which commits th em to a $1.6 billion upgrad e through the year 2018. The commenter reports that they now find themselves in a position where they will need to retire a significant percentage of th eir coal-fired fleet in re sponse to the proposed rule.581 Response to Comment 105: Industry has shown that it can instal l large amounts of pollution controls and often finds more cost-effective compliance opti ons than the EPA can antic ipate. In addition, the EPA has analyzed resource adequacy issues and finds that there is ample existing spare capacity to serve load, and industry has also shown that it can bu ild new capacity quickly in response to demand. The EPA will work with relevant author ities to ensure a smooth transition with this rule. In addition, there are certain provisions for granting utilities some a dditional time to comply, if conditions warrant (see preamble).

Comment 106 : Commenter 16849 reports that they plan to convert a Riverton, Kansas plant to use natural gas, rather than retiri ng it, as predicted in the “IPM Parsed Results Policy Case.”

Response to Comment 106: The EPA modeling and projections ar e intended to be a reflection of possible compliance using specific t ools, assumptions, and methodologies that the agency believes to reflect the best and most current in formation 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 tec hnologies or other, more co st-effective strategies.

Comment 107 : Commenter 17403 believes the EPA has not ad equately assessed th e costs associated with the retirement of smaller units, just as job lo sses and employment shifts as workers are retrained and re-employed elsewhere.

Response to Comment 107: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.

Comment 108 : Commenters 17901 and 19742 believe the proposed rule and other federal rulemakings will force the premature shutdown of many coal-fired power units, resul ting in the loss of thousands of jobs in utilities, coal, manufacturing and transporta tion. Commenter 17901 notes that states such as Ohio that rely on eastern bituminous co al will be especially hard-hit.

Response to Comment 108: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired capacity ) 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 w ill be of the oldest units that owners find least economically viable to control. In addition, the EPA has conducted an updated employment analysis which shows some potential positive and negative em ployment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 109: Commenter 17931 disagrees with the EPA’s c onclusion that few coal-fired units will retire in response to the proposed rule because theystate that DSI use will not provide the expected compliance.

Response to Comment 109: There are many compliance options, and each affected source will choose the most effective strategy to meet the requirements of the rule. The EPA is not prescribing particular technologies, and industry has a su ccessful track record of respondi ng to air reduction programs through innovation, often a cost much less than what the EPA origin ally anticipated.582 Comment 110: Commenter 16850 notes that significant co ntrols 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 ru les should avoid compromising electric system reliability and allow the maximum compliance flexibi lity for electric utilities provided for under the Clean Air Act.

Response to Comment 110: As stated above, there are many compliance options, and each affected source will choose the most effective strategy to meet the requirements of the rule. The agency prepared a resource adequacy analysis for the proposed rule and has revised that analysis for the final rule. The agency is working with FERC regarding the reliabil ity impacts of this rule. The EPA has outlined the various flexibilities associated with the rule, and the approaches to reli ability issues in the preamble. In addition, there are certain provisions for granting utilit ies some additional time to comply, if conditions warrant (see preamble).

Comment 111: Commenter 18016 predicts an 8% decrease in co al 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 th e expedited shutdown of tens of thousands of megawatts of existing coal-f ired generating capacity.

Response to Comment 111: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired ca pacity) and coal-fired generation will not change significantly. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existe nce that will help serve load. In addition, the EPA has conducted an updated employment analysis which shows some poten tial positive and negative employment changes from the rule, but overall expects the employment im pact to be relatively small in comparison to the affected sector and the overall economy. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 112: Commenter 18424 states that according to a study by UJAE, more than 60% of coal shipments in Indiana would not be able to comply w ith that limit when burned in units controlled by scrubbers operating at 95% SO 2 removal efficiency. If sources cannot comply with the proposed limits using bituminous coals, they will not use those fuels or they will retire the units.

Response to Comment 112: : The EPA disagrees with the comme nt. Since scrubbers effectively 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 av ailable to improve performance. 73 Potential impacts to coal supply are discussed in the preamble for the final rule and in the RIA.

Comment 113: Commenter 17852 asserts that the proposed rule can and should promote the orderly retirement of old, high-emitting power plants. It is widely recognized that the current fleet of coal-fired power plants includes many old, uncontrolled, ineffi cient units that lack up -to-date and effective controls for hazardous emissions. Many of these units ar e slated to retire. In fact, over 20 GW of coalfired generation have been recently announced for reti rement. However, current regulatory provisions do not always sufficiently promote utility planning for th ese retirements, causing some in the utility sector

72 Assessment of Technology Options Available to Ac hieve Reductions of Hazardous Air Pollutants” by Lipinski, Leonard, Richardson; published by URS; April 5, 2011

73 Ibid.583 to delay action and then raise concerns regarding perc eived threats to electric system reliability that would not otherwise exist if mo re advance planning had been done. In the proposed rule, the EPA recognized that “Although most RT Os/ISOs only require 90-day not ifications for retirements, construction schedules for all but the simplest retrofits will be longer, so sources should be able to notify their RTOs of their retirements earli er.” To provide an incentive for early planning, the EPA said that it “encourages state environmental regulators to consid er the extent to which a utility engages in early planning when making a decision regarding granting a 4th year for compliance” with the Utility MACT. The commenter supports the EPA’s appr oach of encouraging utilities to engage in early planning and to timely announce the retirements of the oldest an d highest-emitting power plants in the fleet. Notifications of only 90 days are clearly inadequate, and waiting so long maximizes the chance that reliability issues may occur, rather than minimizing it. Response to Comment 113: The purpose of today’s rule is to establish standards to reduce emissions of harmful pollutants in compliance with the requirements of the CAA, not to retire any particular power plants. The EPA continues to encourage utilities to engage in early planning when considering how to respond to the new regulations – whether to comp ly or to retire the EGU – and appreciates the commenter’s support.

4. Flexible regulations.

Comment 114: Several commenters (17004, 17022, 17026, 17028) consid er the purchase of electricity to be a major cost of doing business and question the wisdom of imposing a higher cost on businesses through regulatory inflexibility or needlessly short dead lines. These commenters, along with commenter 17887, urge the EPA to consider deve loping energy policies that will allow businesses to expand and generate jobs by deferring or mitigating price incr eases through adopting more flexible regulations.

Response to Comment 114: The agency recognizes that electricity cost can be an important cost of doing business for many manufacturers. As such, it ha s 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 EP A is also making revisions to the current NSPS. Implementation deadlines in the final rule are in response to the underlying requirements of the CAA, and any flexibility that the agencycan offer must be cons istent with the CAA.

Comment 115 : Commenter 17692 expresses con cern that the proposed rule will increase electricity costs in Louisiana, where businesses depend on ade quate and affordable electricity and domestic productivity could be depressed. The commenter belie ves 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 115: The agency’s analysis finds that the national average retail electricity price increase is expected to be 3.1% in 2015. This incr ease should be understood in th e light of the extensive benefits from HAP and non-HAP emi ssion reductions expected from th is rule. The EPA has attempted to provide the greatest degree of flexibility permitted by law.

Comment 116 : Several commenters (17707, 17824, 18419) state that Alabama uses coal to supply nearly 60% of electrici ty needs and employs 1500 workers to run the coal-fired power plants. Commenters worry the proposed rule will jeopardi ze efforts to increase economic growth and job opportunities in the state. The commenter urges the EP A to adopt more flexible standards and timelines to achieve affordable utility bills, stable j obs and reliable power. Commenters 17824 and 18419 state that Alabama Power has spent $2.6 b illion to install technologies to reduce emissions from coal-fired584 units and succeeded in dropping NO X and SO 2 emissions by 65% since 1 996. Commenters consider the proposed rule to be unreasonable and unfounded, w ith the cost vastly outweighing the benefits.

Response to Comment 116: The agency’s analysis shows that the national average retail electricity price is projected to increase by 3.1% in 2015. The EPA has attempted to provide the greatest degree of flexibility permitted by law. The EPA analysis indi cates that there will be a small amount of coal retirements (less than 2% of all coal-fired ca pacity) and coal-fired generation will not change significantly. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existe nce that will help serve load. In addition, the EPA has conducted an updated employment analysis which shows some poten tial positive and negative employment changes from the rule, but overall expects the employment im pact to be relatively small in comparison to the affected sector and the overall economy. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 117 : Commenter 17648 observes that “the positive economic impacts of the proposed Toxics Rule strongly militate in favor of its adoption. Contrary to the unfounde d assertions by critics of the EPA and the rule, the EPA has conducted a technica lly sound and conservative benefit-cost analysis showing that the proposed rule’s bene fits are at least five times as hi gh as its costs. With sound, albeit unduly conservative, econometric mode ling, the EPA has also determinedthat the Toxics Rule will promote economic growth and create jobs in boththe long and short term .” This commenter and commenter 18432 cite the EPA impactanalyses by Dr. Charles Cicche tti 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 annua lly, create 115,200 jobs, generate annual health savings of $4.513 billi on, annual increases in GDP of $7.17 billion and $2.689 billion in additional annual tax revenues, and spur innovation and modernization of EGUs. The commenter states that the study findings show no need to delay implementation of the rule or needlessly duplicate economic analyses already completed.

Comment 118 : Commenter 17648 reports that multiple resear chers confirmed that the EPA’s estimates of economic stimulus are conservative and that th e proposed rule will st imulate job growth. The commenter quotes Dr. Josh Bivens of the Econom ic Policy Institute, who also found that EPA’s conclusions were conservative. Dr. Bivens concluded, “The EPA RIA on the proposed toxics rule makes a compelling case that the rule passes any reasonable cost-benefit analysis with flying colors—the monetized benefits of longer lives, better health, and greater productiv ity dwarf the projected costs of compliance. . . . Whether regulation in general and the toxics rule in par ticular costs jobs is an empirical question this paper attempts to answer. In particul ar, this paper examines th e possible channels through which the proposed toxics rule could affect employmen t in the United States and finds that claims that this regulation destroys jobs are fl at wrong: The jobs-impact of the rule will be modest, but it will be positive.” His report details the following major findings:

1. The proposed rule would have a modest positive ne t impact on overall employment, likely leading to the creation of 28,000 to 158,000 jobs between now and 2015. 2. The employment effect of the [Toxics Rule] on th e utility industry itself could range from 17,000 jobs lost to 35,000 jobs gained. 3. The proposed rule would create between 81,000 and 101,000 jobs in the pollution abatement and control industry (which includes suppliers such as steelmakers). 4. Between 31,000 and 46,000 jobs would be lost due to higher energy prices lead ing to reductions in output.585 5. Assuming a re-spending multiplier of 0.5, and since th e net impact of the above impacts is positive, another 9,000 to 53,000 jobs would be created through re-spending.

Commenters 17648 and 18961 also provide information from The Univers ity of Massachusetts Political Economy Research Institute, which prepared a Februa ry 2011 study of the jobs impacts of the proposed rule and the Transport rule. Based on estimates that the power sector will invest almost $200 billion total in capital improvements between 2010 and 2015 in thes e 36 states, the research ers found that the total employment created by these capital investments is estimated at 1.46 million jobs, or about 290,000 jobs on average in each of those years.

Response to Comments 117 and 118: The EPA has conducted an update d employment analysis using the approach applied for the proposed rule which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. It should be noted that the agency’s employment impact analysis is focused on short-term estimates of impacts from installation and operation of new pollution control equipment, and long-term estimates of impacts for the regulated industry (electric power generation). Ou r rationale for the analysis and th e analysis itself are in the RIA for the rule.

Comment 119: Commenter 18419 asks the EPA to perform a true economic analys is, evaluate the proposed rule with other new and pending regulations and provide more flexible standards and reasonable compliance guidelines.

Response to Comment 119: The EPA has attempted to provide the greatest degree of flexibility in the rule that is permitted by law.The agency’s economic anal ysis is consistent with the guidelines provided by OMB for rules such as this one that are ec onomically significant unde r EO 12866, an Executive Order issued by OMB in 1993. The agency did not pr epare a cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO requirements that the agency must comply with require us to estimate impacts specif ic to this rule; 2) de cision 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 thos e from a cumulative impact analysis. A cumulative impact analysis lumps several regulations together and can potentially mask a high-cost/low-benefit regulation among other rules that may have large net benefits. By an alyzing each regulation separately, the EPA makes clear statements about what impacts, co sts, and benefits will be generated as a result of this particular regulation.

This does not, however, mean EPA has failed to c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA. Additionally, the Agency does reflec t 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/su mmaryreport.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 di rect 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 Am endments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wi de margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed using any reasonable alternative assump tions or methods. This conclusion is likely to also be attributable to this rule as shown in the RIA.

5. Job analysis: temporary versus permanent jobs.

Comment 120: Commenters 17811 and 18436 believe that instal lation of new pollution controls would be a job-growth opportunity in Alabama because mone y spent on controls for power plants creates highquality jobs in steel, cement and ot her materials, as well as in the assembling of the equipment as well as installing and operating it. Commenter 18436 shares the Alabama Fisheries Association estimate that the water-based recreation indus try 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 threat en the industry with permanent job-losses and lost revenue.

Response to Comment 120: The EPA finds commenters’ economi c predictions and statements of benefits to be reasonable. The EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 121: Commenters 17834 and 18033 disagree with the EPA speculation that job losses will be offset by increasing jobs in air pollution technology production. Commen ters believe the proposed rule will decrease job creation and sees no assurance or conclusive data that jobs will be created. Commenters go on to request that the EPA withdraw the pr oposed rule, citing anunstable regulatory climate and unclear economic impacts. Comm enter 18033 quotes economist David Montgomery’s testimony before Congress in which he said that “Cla ims that regulations that raise the cost of doing business will create new jobs are, at best, a sideshow. Such claims only distract attention from the difficult tradeoffs that must be made between costs and benefits . “Green jobs” is not a subject that leading economists have usually taken seriously enough in prof essional journals. Based on the foregoing, it is difficult for EPA to legitimately clai m that the proposed rule’s benefits analysis is accurate.”

Response to Comment 121: The EPA does not have the flexibility to withdraw or delay the rule, which is governed by a consent decree and the requirement s of the CAA. The EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. All of these analyses are found in the RIAs for the respective rules.

Comment 122 : Commenter 17930 disagrees with the EPA’ s prediction of an annual cost of $10.9 billion by 2015 and estimates it to be up to $100 bill ion 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 loss es. The commenter points out that while jobs running power plants are permanent, the j obs predicted to be created by the proposed rule are short term construction jobs, and will all occur in the same short timeframe for compliance. Further, the commenter states that the EPA estimate does no t include the opportunity cost of lo st construction jobs due to new power plants that will not be constr ucted due to the proposed rules.587 Response to Comment 122: The EPA has conducted extensive analys is of the rule, which can be found in the RIA. The cost analysis by the agency is ba sed on a peer-reviewed power sector model that has been used in multiple rulemakings affecting the el ectric power sector over the past 15 years. The EPA has also conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. Overall impact on re tail electricity prices nationwide is also anticipated to be modest in light of the signifi cant benefits of the rule. The EPA cannot evaluate the basis for commen ter’s claim of higher impacts, but on the basis of its own detailed analysis does not find it to be reasonable.

Comment 123 : Commenter 17761 questions the EPA estimate that the proposed ru le will create jobs. The commenter points out that coal-fired plant closur es will lead to the loss of more jobs than the creation of gas-fired units will cr eate because coal-fired plants employ 75-100 people versus 25-30 for a gas plant of equivalent size.

Response to Comment 123: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in compar ison to the affected sector and the overall economy. The commenter points to only one po tential change in employment, that of a transition from coal to natural gas-fired generation, but does not address other changes, such as jobs created by increases in production of pollution control equipment.

Comment 124: Commenter 17903 agrees with the EPA’s job cr eation estimations for the proposed rule and reports that 20,000 of the new jobs are expected to be in Iowa. The commenter also mentions that utility boards must approve rate increases, and these may not be given at all or will help to control the rate increases claimed by industry.

Response to Comment 124: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in compar ison 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 comm issions and other regulatory author ities have extensive experience with regulatory requirements and treatment of costs to consumers, and are prepared for responding to the cost of future pollution control e quipment or other response measures.

Comment 125: Commenter 19121 says that the EPA appears to have overstated the job creation estimates due to economic growth under the proposed rule.

Response to Comment 125: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.

Comment 126: Commenters 16469 and 18500 estimate the potent ial job losses asso ciated with the closure of coal units could amount to more than 50,000 di rect jobs in the coal, ut ility and rail industries, with a total job loss including indi rect jobs of 251,300. Commenters note that the EPA’s analysis did not estimate the effects of adverse employment or effects of higher electr ic 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 us ing Department of Commerce RIMS II multiplier data588 for the electric, gas and water util ity industries, specific to each st ate and do not account for short-term or permanent job gains from control unit cons truction and operation. The commenter provides a preliminary assessment of coal “units at risk” on wh ich these related potential job losses are based. The assessment is contained in Attachment 4 (see EPA-HQ-OAR-2009-0234-16469-A1), based on data sorted from the 2007 DOE/NETL Coal Plant Data Ba se, 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 shar e of total electric generation in severa l regions (using a 2009 state generation baseline): 18% in the East North Central region, 14% in the West North Centra l, and 12% in the South Atlantic. In several states, these units s upplied 20% or more of total generation.

Response to Comment 126: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired ca pacity) and coal-fired generation will not change significantly. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence that will help serve load. The EPA has al so conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. Overa ll impact on retail electricity prices nationwide is also anticipated to be modest in light of the significant benefits of the rule.

Comment 127 : Commenters 17254 and 17409 quote IBEW president Edwin Hill and United Mine Workers of America who both state that as many as 50,000 workers in the utility, mining and railroad industries could lose their jobs inresponse to the proposed rule. Commenters disa gree with the EPA’s estimate of short and long-term job growth, believi ng that the permanent job losses are underestimated and quotes the HIS Global Insight es timate that for every billion do llars spend on comp liance with the proposed rule, 16,000 jobs will be at risk and the U. S. GDP will be reduced by as much as $1.2 billion. Commenters ask that the EPA’s analysis account for the loss of tax and support for local schools due to job losses.

Response to Comment 127: The EPA analysis indicates that th ere will be a small amount of coal retirements (less than 2% of all coal-fired ca pacity) and coal-fired generation will not change significantly. The agency has also assessed resource adequacy, and has determined that there is sufficient excess capacity in existence that will help serve load. The EPA has al so conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy. Overa ll impact on retail electricity prices nationwide is also anticipated to be modest in light of the significant benefits of the rule.

Comment 128 : Commenter 17409 quotes estimates by ICF In ternational that employment income is estimated to drop in response to the proposed rule by about 2 or 2.5 million full-time workers due to retail electricity price increases.

Response to Comment 128: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in compar ison to the affected sector and the overall economy. The EPA cannot evaluate the basis for ICF Internationa l’s projections, but believes that its own analysis is as accurate, transpar ent, and well-supported.589 Comment 129 : Commenter 17839 states that the transition to clean, renewable energy will create many more jobs than may be lost due to the proposed rule and questions if jobs will ac tually be lost at all.

Response to Comment 129: The EPA agrees that this can be one source of new employment resulting from today’s rule. It has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule , but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 130: Commenter 17767 reports that th eir organization could lose 30 jobs as a result of complying with the proposed rule , and the reduced need for coal could put those employed by coal mines or trucking companies out of work as well.

Response to Comment 130: The EPA analysis indicates that co al-fired generation will not change significantly. The EPA has conducted an updated empl oyment analysis which shows some potential positive and negative employment changes from the rule , but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 131: Multiple commenters (17811, 18421, 18436) agree with the EPA’s projections that the proposed rule will lead to the creation of 31,000 shor t-term construction jobs and 9,000 long-term utility jobs. The commenter also quotes th e World Resources Institute, wh ich announced that compared to overall spending in the economy, spending on envir onmental protection and clean-up employs more than twice as many workers in constr uction and 25% more in manufacturing.

Response to Comment 131: The EPA generally agrees with the th rust of commenters’ assertions and those of the World Resources Institute. The EPA has conducted an updated empl oyment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.

Comment 132 : Commenter 17813 disagrees with the EPA’s estimate of created jobs because the commenter expects retirements to be much higher than predicted, costing more jobs. The commenter argues that the jobs the EPA categor izes as new cannot be compared to the permanent jobs lost, because they will be temporary. The comment er also believes the EPA’s asse ssment does not take into account the lost opportunity of constructi on jobs that would have been created by constructing new power plants that will not be built as a result of the proposed rule.

Response to Comment 132: The EPA disagrees and notes that its analysis indica tes 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 significantly. The EPA thus believes there will be modest le vels 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 anticip ated to install polluti on controls. The EPA has conducted an updated employment analysis which shows some potential positive and negative employment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

6. Natural gas.

Comment 133: Numerous commenters (17403, 17639, 17640, 17797, 17799, 17806, 17829, 17919, 18488, 18023) point out that the complia nce dates underestimate the time needed to comply 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 thre aten reliability. Commenter 17919 agrees with the other commenters and cites the NERA Economic Consulti ng study done in May 2011 that projected average U.S. retail electricity prices in 2016 to increase by 12%, with regional increas es up to 24%, with a 13% reduction in coal-fired generati on and a 10% decline in electric sector coal demand in 2016. Also, Illinois Power Agency estimates that by 2017 ener gy bills could jump 65% from current levels. Commenter 18023 refers to the EEI report showing thatover 150 GWs of coal uni ts, approximately half of the U.S. coal fleet, is at ri sk of being unavailable in 2015 due to insufficient time to achieve compliance. This commenter points out that the time frame strains the supply of equipment and related resources, which increases costs that are passed on to consumers. A footnote offers and estimated electricity price increase of up to 25% in the Southeast.

Response to Comment 133: The agency has prepared analyses of the costs, benefits, and employment impacts associated with the rule and included them in the RIA for the rule. The projected impact on national retail electric ity prices is anticipated to be relatively small, and no region of the country is expected to experience a double-digit increase in retail electricity prices as a result of this rule. Although economically vulnerable families could experience so me increase in electric ity price in 2015, this increase should be understood in the context of th e substantial health bene fits from Hg, HAP, and reductions of other pollutants that will result. Indust ry has shown that it ca n install large amounts of pollution controls and often finds more cost-effectiv e compliance options than the EPA can anticipate. In addition, the EPA has analyzed re source adequacy issues and finds th at 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 releva nt authorities to ensure a smooth transition with this rule. In addition, there are certain provisions for granting utilit ies 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 stab le since their peak in the early 2000s.

Comment 134: Commenter 17852 states that natural gas pric es are not more volatile than for other comparable commodities. Though not strictly part of the EPA’s “beyond the floor” analysis, the EPA’s RIA also creates a misimpression by stating that “The natural gas market in the United States has historically experienced significant pr ice volatility from year to year, between seasons within a year, and can even undergo major price swings during short

‐ lived weather events.” Simply put, natural gas prices today are not inherently more volatile than other comparable commodities, and the U.S. - given the abundance of natural gas - is likely to experience significantly less volatility than in the past. The commenter and the Bipartisan Policy Center have jointly commissioned an entire report that demonstrates why natural gas price volatility occurre d in the prior decades (inc luding due to the federal government discouraging production), and why these conc erns are less likely to occur in the foreseeable future. These reasons include: an enhanced resource base due to sh ale gas, improved drilling technology, improved storage and delivery infrastructure, and th e elimination of government price control that artificially constrained pr oduction. Furthermore, coal prices have experienced similar volatility in the past, and have been widely reported to be facing upward pric e pressure due to the export of coal to meet Asian demand.

Response to Comment 134: The EPA’s analysis and conclusions concerning natural gas were not intended to suggest abnormal vola tility relative to other commoditi es, but only to acknowledge the volatility that has been observed historically. The reasons given by commenters for expecting less591 natural gas price volatility in the future are not unreasonable, however, nor are observations about increasing coal demand elsewhere.

Comment 135: Commenter 17725 states that natural gas us e is only an option in places where infrastructure exists to supply su fficient natural gas to the EGU and other local needs and reports that year-round reliable gas delivery is rare due to requirements to meet the other needs. The commenter says that gas interruptions are preval ent in the winter, but can happ en year-round, and the costs of establishing a natural gas line to a power plant can be tens of millions of dollars or more, and moving a plant to a gas source can take many years. The comm enter describes the options for a Norwalk Harbor plant, and explains that the m odifications are costly and difficu lt even before considering the modifications needed to alter the boiler and fu el supply system to allow natural gas combustion.

Response to Comment 135: The EPA’s analysis of the impacts to the power sector can be found in the RIA of the rule. The agency has analyzed resource ad equacy issues and finds th at there is ample existing spare capacity to serve load, and industry has al so shown that it can build new capacity quickly in response to demand. For example, the power sector brought online over 140 GW of gas capacity from 2001 to 2003. The EPA will work with relevant authoritie s to ensure a smooth tran sition with this rule. In addition, there are certain provisions for granti ng 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 fairlystable since their peak in the early 2000s.

Comment 136 : Commenter 17640 explains thata Midwest steel company es timates that a 1 cent per kWh increase in electricity cost would add $10 million annually to company costs.

Response to Comment 136: The EPA has designed a rule with as much flexibility as possible and in accordance with the requirements outlined in the CAA for HAP, and does not expect significant impacts on electricity prices generally. Th e EPA believes energy efficiency m easures 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 m easures 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 real izing those improvements.

Comment 137 : Multiple commenters (17403, 17812, 17868, 18500, 19211) disagree with the EPA estimate for natural gas price changes. Commenter 17812 expects the proposed rule to lead to an increase in natural gas prices as utility companies transition to burning natural gas instead of installing emission controls. The commenters quote NERA estimat es that natural gas pric es will increase by 17% in 2016, much higher than the EPA estimate of 0.6% to 1.3% increase. This transl ates to a natural gas expenditure increase by residential, commercial and industrial sector s 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 se t of natural gas prices such as the provided graph of average national monthly gas prices provided (page 35 of EPA-HQ-OAR-2009-17868-A2). Commenter 19211 sees the projected in crease in natural gas prices as a reason manufacturers may lose confidence in the U.S. as a favorable place to do business.

Response to Comment 137: The EPA has provided an assessment of the economic impacts of the rule on the power sector, which can be found in the RIA of the rule. The agency has fully documented its assumptions and framework for modeling natural ga s 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-i pm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of the na tural gas module, describes the ve ry 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 compone nts incurred in bringing natural gas from the ground to the pipeline. Also documented ar e the resource constraints, liquefied natural gas (LNG), demand side issues, the natural gas pipeline network and capacity, proce dures used to capture pipeline transportation costs, natu ral gas storage, oil and natural ga s liquids (NGL) assumptions, and key gas market parameters. IPM modeling of natural gas pr ices uses both short- and long-term price signals to balance supply of and demand in competitive markets for the fuel across the modeled time horizon. As such, it should be understood thatthe pattern of IPM natural gas pr ice projections over time is not a forecast of natural gas prices incurred by end-use cons umers at any particular point in time. The natural gas market in the U.S. has historically experienced si gnificant price volatility fr om year to year, between seasons within a year, and even sees major price swi ngs during short-lived weathe r events (such as cold snaps leading to short-run spikes in heating demand). These short-term price signals are fundamental for allowing the market to successfully align imme diate supply and demand needs; however, end-use consumers are typically shielded from experiencing th ese rapid fluctuations in natural gas prices by retail rate regulation and by hedgi ng through longer-term fuel supply contracts. IPM assumes these longer-term price arrangements take place “outside ofthe model” and on top of the “real-time” shorterterm price variation necessary to align supply an d demand. Therefore, the model’s natural gas price projections should not be mistakenfor traditionally experienced c onsumer price impacts related to natural gas, but a reflection of expected aver age price changes over the time period 2015 to 2030.

Comment 138 : Commenter 17868 discusses the f actors that could lead to hi gher natural gas prices not currently reflected in the EPA impact projections, including industr ial load and demand not rebounding to 2008 levels and the influence of liquefied natural gas exports. The commenter asks that the EPA address these factors:

1. Higher natural gas demand for use in vehicles (a la The Pickens Plan ) or some amount of transportation el ectrification. 2. Constraints either on shale resour ces allowed to be extracted due to regional opposition or reflect drilling restrictions or a cost a dder for environmental remediation. 3. Starting oil prices “adapted from AEO 2009,” of about $62/bbl for 2011 are well below current oil prices. 4. No documentation of any indication that the gas market module of IPM reflects the drilling lease inventory buildup that may be causi ng some producers to drill at less economic prices in exchange for cash flow and retenti on of their lease options. 5. Unclear what the production per we ll or depletion assumptions ar e or whether they have been updated (i.e., lowered) for the shift to more shale production. 6. Figure 10-7 from U. S. EPA’s proposed rule provide s 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 of U. S. EPA’s proposed rule indicates that the undiscovered gas resource is “assumed” to grow at 0.2% per year for co nventional gas and 0.75% for undiscovered gas. Nothing provides the basi s for testing that assumption’s validity. The discussion admits that technology drives the abil ity to produce undiscovered resources but does not test the technology assumption and no curves are provided at all for the existing discovered resource base. 7. The model covers North America only, so it must be fed an exogenous assumption on LNG imports (or exports) and cannot predict or capture changes in world-wide development and trading of natural
gas.593 Response to Comment 138: The EPA has provided an assessment of the economic impacts of the rule on the power sector, which can be found in the RIA of the rule. The agency has fully documented its assumptions and framework for modeling natural ga s 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-i pm/docs/v410/Chapter10.pdf). The documentation provides a thorough overview of the na tural gas module, describes the ve ry 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 compone nts incurred in bringing natural gas from the ground to the pipeline. Also documented ar e the resource constraints, liquefied natural gas (LNG), demand side issues, the natural gas pipeline network and capacity, proce dures used to capture pipeline transportation costs, natu ral gas storage, oil and natural ga s liquids (NGL) assumptions, and key gas market parameters. IPM modeling of natural gas pr ices uses both short- and long-term price signals to balance supply of and demand in competitive markets for the fuel across the modeled time horizon. As such, it should be understood thatthe pattern of IPM natural gas pr ice projections over time is not a forecast of natural gas prices incurred by end-use cons umers at any particular point in time. The natural gas market in the U.S. has historically experienced si gnificant price volatility fr om year to year, between seasons within a year, and even sees major price swi ngs during short-lived weathe r events (such as cold snaps leading to short-run spikes in heating demand). These short-term price signals are fundamental for allowing the market to successfully align imme diate supply and demand needs; however, end-use consumers are typically shielded from experiencing th ese rapid fluctuations in natural gas prices by retail rate regulation and by hedgi ng through longer-term fuel supply contracts. IPM assumes these longer-term price arrangements take place “outside ofthe model” and on top of the “real-time” shorterterm price variation necessary to align supply an d demand. Therefore, the model’s natural gas price projections should not be mistakenfor traditionally experienced c onsumer price impacts related to natural gas, but a reflection of expected aver age price changes over the time period 2015 to 2030.

Comment 139 : Commenter 17868 asks that the EPA consider the infrastructure (pipeline and storage) issues and other concerns found in the APPA study “I mplications of Greater Reliance on Natural Gas for Electricity Generation” found in Ap pendix M. [EPA-HQ-OAR-2009-0234-17868-A2]

Response to Comment 139: The EPA is familiar with the study and has considered it. The EPA’s IPM modeling includes natural gas pipeline requirements fo r coal-to-gas (CTG) convers ions as described in Documentation Supplement for EPA Base Case v4.10_PTox

− Updates for Proposed Toxics Rule( http://www.epa.gov/airmarkets/progsregs/e pa-ipm/docs/suppdoc.pdf, Section 5.3.2).

Comment 140: Commenter 17627 quotes the Babcock & Wilcox White Paper MS-14 “Natural Gas Conversions of Existi ng Coal-Fired Boilers” 2010 and recommends the EPA project capital costs based on the B&W costs.

Response to Comment 140: The EPA is familiar with the study and has considered it. The EPA’s IPM modeling includes a coal-to-gas (CTG) conversion option as described in Documentation Supplement for EPA Base Case v4.10_PTox

− Updates for Proposed Toxics Rule ( http://www.epa.gov/airmarkets/progsregs/epa-i pm/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 conservative ly derived from the $50 to $75/kW costs estimated by B&W for somewhat larger units using their “Opt ion 1,” as described in the cited B&W paper (http://www.babcock.com/library/pdf/MS-14.pdf). T hus EPA’s CTG option and B&W’s CTG Option 1,594 both involve only modifications to th e existing boiler; they do not involve higher co st approaches such as the addition of a gas turbine (as in B&W Option 2).

Comment 141 : Commenter 17879 explains that much of the manufacturing industry cannot pass along increased input costs because it decreases competitivenes s. The paper industry in pa rticular is in decline, the commenter reports, and increased natural gas a nd electricity costs could exacerbate the nation’s weak economic situation. The commen ter worries that the widespread conversion from coal or oil to natural gas by power plants will lead to an increase in natural gas consumption and costs.

Response to Comment 141: The EPA has designed a rule with as much flexibility as possible and in accordance with the requirements outlined in the CAA for HAP. As discussed elsewhere in this document, the EPA’s analysis shows only modest convers ion to natural gas and that coal will continue to play a major role in the nation’s energy econo my. 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 like ly additional energy efficiency meas ures that are likely to occur by 2015, but will continue to pursue energy efficiencyimprovements throughout the economy, along with other Federal agencies, states and other groups. Th is will contribute to add itional environmental and public health improvements while lowering th e costs of realizing those improvements.

Comment 142 : Commenter 17711 discusses the unique concerns of paper mills that produce some of their own electricity, but also purchase some. The co mmenter is concerned that the proposed rule will increase costs and lead to some plants switching to na tural gas, thus increasing the cost of natural gas, putting jobs at risk.

Response to Comment 142: The EPA has designed a rule with as much flexibility as possible and in accordance with the requirements outlined in the CAA for HAP. As discussed elsewhere in this document, the EPA’s analysis shows only modest convers ion to natural gas and that coal will continue to play a major role in the nation’s energy econo my. 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 like ly additional energy efficiency meas ures that are likely to occur by 2015, but will continue to pursue energy efficiencyimprovements throughout the economy, along with other Federal agencies, states and other groups. Th is will contribute to add itional environmental and public health improvements while lowering th e costs of realizing those improvements.

Comment 143 : Commenter 17853 discusses the cost effectiv eness for coal-to-gas with respect to increasing capacity for existing zero HAP base lo ad 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 e fficient, natural gas is comparable to coal in commodity prices. (See Insert EPA-HQ-OA R-2009-0234- 17853-A2_Figure1and2Page3.doc.)

Response to Comment 143: . The EPA has provided an assessment of the economic impacts of the rule on the power sector, which can be found in the RI A of the rule. The EPA generally agrees with commenter’s assessment, noting that it has designed a rule with as much flexib ility as possible and in accordance with the requirements outlined in the CAA fo r HAP. Source owners will be able to ascertain the viability of coal to case conversion relative to other options for reducing HAP emissions.

Comment 144 : Commenters 18480 and 18481 express concern th at the cities of Beatrice and South Sioux City, Nebraska will be unable to meet the compliance deadline. Both receiv e 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 cost s show a preliminary cost of $1 billion, which will lead to a rate increase. The commenters requ est that the EPA reconsider the proposed rule’s aggressive emissions limits and deadline s, in light of the economic effects.

Response to Comment 144: To the extent that sources have al ready installed significant emission controls, the EPA anticipates that the additional costs of complying with this rule will be much less. As discussed elsewhere in this document, electricity prices are not expected to increase significantly as a result of this rule. Nonetheless, the EPA will work w ith relevant authorities to ensure a smooth transition with this rule and address specific issues. Public utility commissions and ot her regulatory authorities have extensive experience with regulatory requireme nts and treatment of costs to consumers, and are prepared for responding to the cost of future polluti on control equipment or other response measures. In addition, there are certain provisions for granting utilit ies some additional time to comply, if conditions warrant (see preamble).

Comment 145: Commenter 18486 expresses concer n that the combined effect of the new rule will increase the use of natural gas for electric gene ration and increase natura l gas prices, decreasing availability for other uses. The co mmenter reports that natural gas is used in the production of ammonia for fertilizer and for heating and other purposed in the agricultural i ndustry. 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 comm enter asks the EPA to consider reports by Brattle Group, ICF, Credit Suisse, CRA, FBR, Wood McKenz ie and Bernstein Research on the ways the proposed rule will lessen the use of coal and increase natural gas use.

Response to Comment 145: The EPA’s analysis of the impacts to the power sector can be found in the RIA of the rule. The analysis indica tes that only a small number of coal plants will retire, and coal-fired generation will continue to be the largest source of electricity. The agency has analyzed resource adequacy issues and finds that there is ample existi ng spare capacity to serve load after retirements are factored in, and industry has also shown that it can build new capaci ty quickly in response to demand. The EPA will work with relevant authorities to ensure a smooth transi tion with this rule. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). Natural gas supplies and reserves have increased significantly in recent years, and prices have remained fairly stable since their peak in the early 2000s. The EPA antic ipates this trend will continue although there may be some modest price effects on natura l gas markets due to this rule.

7. Compliance timeline and general timeline.

Comment 146: Commenter 17806 considers the compliance tim e limits imposed by the proposed rule to be impossible to achieve in light of the other fina l or pending rules. The co mmenter believes the short timeline for these rules will increase the cost of power in most regions and threaten reliability.

Response to Comment 146: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 147: Commenter 19199 believes the utilities will need more time to comply with the proposed rule in order to acquire the materials and labor needed to construct and install the equipment without creating unnecessary cost increases and an unreliable el ectricity supply. The commenter believes the EPA should extend the time to allow fl exibility in implementati on of the proposed rule.596 Response to Comment 147: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 148: Commenter 19213 says that the proposed rule does not allow adequate time to comply. The commenter states that the timelin e brings a risk of needing to incr ease electricity rates significantly and negatively impact the economy and federal budget.

Response to Comment 148: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 149: Commenter 19213 states that small utilities will have a difficult time getting vendors and contractors to commit to projects, since large utilities will be seeki ng larger quantities of equipment.

Response to Comment 149: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 150 : Commenter 17834 states that the proposed ru le will require costs be passed on to consumers, meaning state public utility commissions will be flooded with reque sts for rate increases from utilities trying to recover expenditures. The short deadline will also result in a large number of extension requests made to state permitting authorities, further burdening them.

Response to Comment 150: The implementation of this rule will be 3 years after its promulgation, or the end of 2014. Public utility commissions have exte nsive experience with regu latory requirements and treatment of costs to cons umers, and are prepared for responding to the cost of future pollution control equipment or other response measures. In addition, there are certain provisi ons for granting utilities some additional time to comply, if conditions warrant (see preamble). Thus, there will be some time before the impacts of this rule such as any increase in retail electricity prices become a concern. It also should be noted that increases in retail electricity prices will be 3.1% on average in 2015, with a range regionally from 1.3 to 6.3%. See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 151 : Commenters 17743 and 17761 express concern that the short compliance deadline will require many facilities to be taken offline at that same time to make upgrades, leadin g to reliability issues.

Response to Comment 151: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 152: Commenter 18538 states that the compliance timeline in the proposed rule does not include time to plan and permit new facilities. The commenter believes the EPA assumes owners will be able to determine which plants will retire on the fi rst day of the proposed rule’s implementation period. However, the commenter explains that permitting, pl anning and construction can run longer than 3 years and delays in construction are common. Transmission upgr ades can also take longer than 3 years. Since many of the new plants in Texas will be in th e same areas, permitting could also take longer.597 Response to Comment 152: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 153 : Commenters 17881 and 18033 expresses concern that even with a blanket 1-year extension, the proposed rule still poses risk to the reliability of the nation’s electricity grid and to national security. The commenter asks the EPA to work with industry to lay the groundwork for the Presidential exemptions, as allowed by the CAA.

Response to Comment 153: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 154: Commenter 15002 states that the proposed rule should regulate emissions to the average emissions achieved by the top performing 12% of s ources since this provides a satisfactory balance between emission controls, the monetized value of th e associated health benefits and the projected costs. The commenter also urges the EPA to adopt a review schedule for Hg and HAP emissions, such as a 5-year review cycle as defined under the CAA NAAQS review process.

Response to Comment 154: The rule will impose HAP emissions limits consistent with the requirements of section 112(d) of the CAA. Although the EPA has conduc ted a detailed analysis of the costs and benefits of the rule, the setting of a MACT floor is not based on the costs and benefits of control. Setting standards beyond the MACT floor doe s consider costs and non- air quality health and environmental impacts and energy requirements. The revi ew cycle for standards such as this one is not longer than 8 years as set fo rth in CAA section 112(d)(6).

Comment 155: Commenter 17654 reports that they will need to install add-on pollution controls to meet the proposed emission standards as well as imp lement other physical or operational changes. The commenter expresses concern about the number of pre-construction step s that would be required, as well as the new construction activ ities and the challenges of scheduling sequence relative to interconnections and other tie-in considerati ons involved in compliance.

Response to Comment 155: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 156 : Several commenters (17681, 17886, 18441) have concerns about the tight timeframe imposed by the proposed rule. Commenters 17681 and 17886 argue against the EPA’s suggestion that 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 th at may not be adequate to comply with the final rule. The commenters state that many companies have had to stop their investments for strategies based on prior rules because they are likely to be insufficien t for the proposed rule. Rate-regulated states may not be able to recover capital commitments made be fore the rule is final. Commenters 17886 and 18441 states that early decisions are not appropriate for a MACT rule as they may be for Clean Air Interstate Rules, since the CAIR is a cap and trade program th at allows flexibility, and the proposed rule requires units to meet limits to be shut down. Commenters believe utility decisions on unit retirement versus additional control installations must factor into all anticipated and existing regulations.598 Response to Comment 156: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 157: Commenter 19114 has determined that the pr oposed rule does not provide enough time to permit, engineer, procure and c onstruct the retrofits th eir fleet will need to meet the 2014 deadline.

Response to Comment 157: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 158: Commenter 17911 explains the di fferent approaches used to obtain funding by a private, stock or cooperative company as opposed to a munici pality. A private company comes to an agreement with an entity with funds to le nd. Municipalities, on the other hand need approval from the voting public to issue revenue bonds or general obl igation bonds to begin the process of financing projects, often by a super majority. Additionally, the commenter states municipalities are bound by publicly adopted budgets that cannot be amended, so it may ta ke up to 18 months to get approval to spend money for projects like those necessitated by the proposed rule. The commenter also explains that muni cipal bonds have been hit by threatened bankruptcies of municipalities, which makes it incr easingly difficult to fund projects and many municipalities have seen a reduction in their revenue stream s, including sales tax and water, wastewater or electricity utility bills. A downgrade in the U.S. credit rating may also change municipal borrowing ratings, making money increasingly difficult to borrow. Municipalities are legally prohibited from skipping or speeding up regulat ory or legal processes. All of these factors make it difficult for municipal utilities to move forw ard quickly with construction of new controls or generation.

Response to Comment 158: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). In addition, the deduc tibility of federal tax on capital investment by municipalities may make investment in pollution control somewhat less expensive relative to priv ate, stock or cooperative companies, who do not have this tax advantage for debt.

Comment 159 : Commenter 18447 explains that they will not be able to plan, design, permit, bid and build a new transmission line in 3 ye ars. The commenter states that th ey have been working to build a new transmission line without success since 2005. The commenter says that the initial cost estimate was $18.2 million, but has now surpassed $29 million and w ill not be completed until 2012. The commenter explains that when the city power plant is down, wit hout this transmission line the power in the city will go out any time the demand is greater than 63 MW. Th e commenter also says that committing resources toward rule compliance before it is finalized is no t an option as resources ar e only available when the need is known.

Response to Comment 159: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 160 : Commenters 17808 and 18421 do not believe th at labor availability will constrain control installation in the required timeframe and cite s ICAC response that it will not for these reasons:

1. Power sector has demonstrated ability to instal l large number of systems in short time period. 2. Majority of coal plans have in stalled control systems already.599 3. Fewer resource and labor-intensive contro l options being used for compliance. 4. End users have utilized cost reducing and impl ementation efficiency strategies for efficient deployment of technologies.

Response to Comment 160: The EPA thanks the commenter for their comments. These comments are generally consistent with the conclu sions of the agency’s analyses on f easibility of control installations for this rule as found in the TSD on this subject in the docket for this rulemaking.

Comment 161 : Commenter 18498 considers the complian ce schedule to crea te 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 replacemen t capacity cannot be operational prior to the compliance timelines for retirement or retrofits of ex isting facilities. This results in an inefficient and costly approach that could be addressed by extend ing the compliance deadlines to allow sufficient time to plan for transition to other tec hnologies in a manner that is cost e ffective and assures grid reliability. The commenter requests the compliance deadlines to be increased to at least 5 years with extensions allowed for 2 additional years.

Response to Comment 161: See preamble and TSD on feasibility for further discussion. The EPA has analyzed resource adequacy issues and finds that 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. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). As discussed further in the pream ble, compliance timeframes are prescribed by the CAA.

Comment 162 : Commenters 17812 and 18038 suggest that ma rket realities of installing control equipment will increase the cost of the equipment due to the timeframe for compliance. Commenter 18038 is especially concerned that th e short timeline and resulting increa ses in costs will be a hardship for those already having difficu lty in the current economy.

Response to Comment 162: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 163 : Commenter 18435 states that a wide range of technical and economically feasible practices and technologies ar e available currently to meet the emi ssion limits and are in use around the country.

Response to Comment 163: The EPA agrees with the comment. Our report on feasibility of controls to meet the requirements of this rule can be found in a TSD in the docket for this rulemaking.

Comment 164 : 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 employment oppor tunities while protecting the environment.

Response to Comment 164: The EPA has conducted an updated employment analysis which shows some potential positive and negativ e employment changes from th e rule, but overall expects the employment impact to be relatively small in comparis on to the affected sector and the overall economy.600 Comment 165 : Several commenters (17409, 17736, 18441) e xpress concern over the 36-month compliance timeframe and urge the EPA to provide an extension of at least 1 year to avoid more plant retirements and lost jobs than necessary. Commenters 17736 and 18441 go on to request a clear explanation of the requirements to qualify for an extension and commenter 17736 requests automatic qualification for replacement source provisions, re gardless of location while commenter 18441 does not request a blanket delay.

Response to Comment 165: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble).

Comment 166 : Commenter 17627 discusses the length of time it takes to adhere to permitting requirements and the time needed to design, engineer , fabricate and install equipment. The commenter explains that all these resources will be limited as multiple facilities try to u tilize them during the short timeframe and several commenters (17881, 17911, 18933, 19212) agree with this assessment. Commenter 19212 reports that the compressed timeline will inflate costs to twice that of a more reasonable implementation period of 6 to 8 years, which is wasteful of rate payers money. The commenter suggests petitioning Congress for additio nal time to ensure a reasonable outcome.

Response to Comment 166: See preamble and TSD on feasibility for further discussion. In addition, there are certain provisions for granting utilities some additional time to comply, if conditions warrant (see preamble). As discussed further in the pream ble, compliance timeframes are prescribed by the CAA.

Comment 167 : Commenter 18025 explains that between 200 8 and 2010, approximately 60 GW of coal capacity was retrofitted with scr ubber controls and the industry completed between 50 and 60 scrubber retrofits in each of the years 2009 and 2010, which shows the industry can complete large numbers of retrofits in a short time period. Commenter 18025 encour ages the EPA to finalize the rule on the planned schedule to avoid market uncertainty.

Response to Comment 167: We agree with the commenter and are issuing the rule consistent the consent decree.

Comment 168 : Commenter 18477 estimates that compliance w ith the proposed rule will require new controls on 10 of Hawaiian Electr ic’s 14 steam boilers, and the controls cannot be completed until 2018 without jeopardizing system reliability. This woul d increase costs for consumers by 5% in 2014, and trend up to 10% for 2018 and later years. The comment er notes that the rema ining boilers would be retired, and the cost of replacement generation was not included in the estimates.

Response to Comment 168: See preamble for discussion of requi rements for non-continental liquid oilfired EGUs.

Comment 169: Commenter 18538 believes the EPA has underestimated the time needed to plan, permit and construct sufficient new generation and transmi ssion to compensate for the retirements caused by the proposed rule.

Response to Comment 169: The claims of retirements in recent studies of the impact of EPA rules are addressed in the preamble for the final rule.601 Comment 170: Commenter 19121 states that the rule’s ti meline combined with over-regulated HAP place a threat to grid reliability.

Response to Comment 170: The claims of retirements in recent studies of the impact of EPA rules are addressed in the preamble for the final rule. As di scussed in this document, the preamble, and other supporting materials, the EPA disagrees thatHAP are “over-regulated” by the rule.

8. Large burden, little environmental gain.

Comment 171 : Several commenters (17681, 17731, 17761) state that the EPA has no data relating to benefits from reducing non-Hg HAP, so the costs of the proposed rule exceed the HAP benefits by 29,000 times. Commenter 17761 states that the impact an alysis was largely focused on Hg with little support for other HAP reductions and failed to pr ovide account of true costs and benefits.

Response to Comment 171: The benefits of this ru le 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 benef its reflect extensive analysis that has been reviewed by the EPA’s SAB, and reflects the latest scien tific understanding on the subject. These benefits outweigh the total annual costs of th e rule by at least six-fold. More information on the estimates and the methodology for their preparation can be found in the RI A for the rule. In additi on, we are not able to monetize the benefits from reductions of non-Hg HAP that will take place, but it is clear that benefits will occur from reductions of these HAP.

Comment 172: Several commenters (17765, 17840, 17931, 18018) state that the rule is one of the most expensive in the history of the CAA and is a huge regulatory burde n 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 co mmenter states that little to no incremental public health benefits will be realizedin response to the proposed rule.

Comment 173 : Commenter 17842 cites the EPA estimate that the rule will cost $10.9 billion and create social benefits of $42 to $140 billion annually and states that other anal yses suggest cost s will be more severe due to the cumulative impact of interrelated emission regulations.

Response to Comments 172 - 173: The EPA’s analysis of the impact s to the power sector can be found in the RIA of the rule. Industry ha s also shown that it can build ne w capacity quickly in response to demand. The EPA has not provided a cumulative impact an alysis of various rulemakings for a variety of reasons, which are outlined in the preamble and elsewhere in this document.

Comment 174: Some commenters (17623, 17656, 17799, 17917, 17919, 18023) consider the proposed rule to be the most expensive cleanair rule ever. They point out the estimated $10.9 billion annual cost in 2015 and approximate 1,200 existing coal-fired EGUs affected, both of which were estimated by the EPA. Several commenters (17656, 17681, 17917) believe th e EPA’s estimates are in correct and the true cost will be far more due to cumulative effects of all proposed power sector rules, and indirect costs from job losses, reduced productivity and competitiv eness 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 bene fits. Commenter 17681 in particular re quests that the EPA explain how its approach utilized “the best av ailable techniques to quantify anticipated presen t and future benefits and costs as accurately as possible.” and include analyses by EIA, EEI, NERC, NERA, Credit Suisse, ICF and Burns & McDonnell.602 Response to Comment 174: The EPA’s analysis of the impacts to the power sector can be found in the RIA of the rule. The methodology applied in that anal ysis was subjected to extensive external peer review and this is documented in the RIA and supporti ng materials. In contrast, not all of th e analyses cited by the commenters are completely transparent, and the lack of suffi cient documentation of methodologies and assumptions prevents the EPA from subjecting them to criti cal 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 analysis of various rulemakings fo r a variety of reasons, which are outlined in the preamble and elsewhere in this document. The EPA has conducted an updated employment analysis which shows some potential positive and negative em ployment changes from the rule, but overall expects the employment impact to be relatively small in comparison to the affected sector and the overall economy.

Comment 175: Commenter 17637 states that the emission reductions achieved by the proposed rule would be realized by other rules such as the NAAQS for PM, 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 175: The emission reductions from these ru les are based on the agency’s best estimates of how emissions of HAP and non-HAP po llutants are affected by the control options examined for this proposed rule. The RIA accounts for the impacts of other prev iously adopted rules. These reductions in emissions lead to substantial benefits associated w ith the rule as shown in the RIA for the rule.

Comment 176: Commenter 17386 reports that th eir municipal plant will in cur significant costs while removing minimal HAPS from their two small (28 MW and 114 MW) units, which have limited operating time and combust only fuel oil and natural gas.

Response to Comment 176: Natural gas-firing is not impacted by this rule, and the EPA has included analysis for some modest improvements available to oil-fired units to achieve compliance, which can be found in the RIA.

Comment 177: Multiple commenters (17403, 17640, 17751, 17774, 17775, 17921, 18026, 18033, 18488, 19114, 19211, 18023) quote the NERA study that looked at combined economic impacts of the proposed rule and the Transport rule and projected an $18 billion per year cost. The study also estimates an increase in electricity prices of 11.5 to 23% and an increase in natu ral gas prices as a result of the proposed rules as well. Commenters go on to say that manufacturers will not all be able to absorb the higher costs and quotes the NERA study’s predicti on of 1.44 million job-years lost by 2020 if the proposed regulations are implemented. Commente rs 17774 and 17775 agree with this and quote the estimate of 48 GW of coal-fired elec tric generating capacity (15% of the U.S. fleet) projected to retire in response to the proposed rule. Comme nter 17921 states that not all potential health benefits of the proposed rule are monetized in the EPA impact analys is, so the total benefit of $50 billion per year is likely to be a low estimate. However, the benefit s till exceeds the costs predicted by the EPA or NERA, and the commenter believes the rule will benefit ch ildren’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 un its require 75% fewer people per megawatt of capacity than coal. Commenter 19211 states that some manufacturers will be unable to absorb the price increase and will have to close or decrease production.

Response to Comment 177: The agency’s analysis finds that the nationwide average increase in retail electricity price is 3.1% in 2015, and no region of the country will experience an increase in price 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 es timate 4.7 GW of coal-f ired EGU capacity will retire early by 2015 and that short-term construc tion labor will experience an increase of 46,000 jobyears as an outcome of the rule. Also, in the long-t erm, 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 withthe rule. Finally, the benefits of the rule are estimated to exceed the $9 .6 billion annual cost of the rule in 2015 even though there are several benefit categories that could not be monetized, including the health and other effects associated with non-Hg HAP. All of these analytical results can be found in the RIA for the rule, and various TSDs for the rule also further docum ent various results and the methodology for their estimation.

Comment 178 : Commenter 17702 believes thatby expanding the proposed rule beyond what is necessary to meet the remand and vacatur, the EP A created additional costs without improving air quality.

Response to Comment 178: The agency has issued its rule consistent with the DC Circuit Court’s vacature and with the requirements of CAA section 112(d).

Comment 179 : Some commenters (17800, 17806, 17884, 18014, 18018) c onsider 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 ru le 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 benef its reflect extensive analysis that has been reviewed by the EPA’s SAB and reflect the latest scientific understanding on the subject. Th ese benefits outweigh the total annual costs of the rule by at least six-fold. More information on the estimates and the methodology for their preparation can be found in the RI A for the rule. In additi on, 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 regard ing 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 180: Several c ommenters (17765, 17840, 18033) find the propos ed rule to produce little to no public health or environmental benefit while imposing unnecessary costs or losses of employment. Commenters state that the pollutants are alr eady regulated under the NAAQS program or other regulations.

Response to Comment 180: The agency has estimated the benefits of this rule to be 5 to 13 times the size of the costs in its RIA. Thus, this rule will be be neficial given this comparis on of benefits to costs. The reductions of pollutants regu lated under the NAAQS are co-benef its from the HAP emissions limit requirements in the rule, and occur concomitantly with the HAP reductions.

Comment 181 : Commenter 18421 cites the EPA’s estimate that the proposed rule will yield monetized net benefits of up to $130 billion every year, once the rule is in place. These benefits outweigh the costs by 5 to 13 times. The commenter expl ains that the estimates are conservative since not all benefits could be monetized, such as health and ecosystem benef its 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 182: Commenter 18428 considers the proposed rule to be very costly while offering few benefits. The commenter points out that since the year 2000, their company has achieved a 62% reduction in Hg.

Response to Comment 182: The agency has estimated the benefits of this rule to be 5 to 13 times the size of the costs in its RIA. Thus, this rule will be be neficial given this comparis on 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 emissi on controls, the costs of co mplying with this rule will be less.

Comment 183: Commenter 19041 considers the health bene fits to be overstated and the costs underestimated. The commenter and commenter 19114 cite the AEP estimate of $6-8 billion in capital costs needed in addition to the $7.2 billion already spent since 1990, and a retirement of 6,000 MW of capacity to comply with the proposed rule. The comme nters say that if one u tility will need to do so much to comply, the EPA estimate must be low

Response to Comment 183: The agency has provided the most accurate estimates of benefits and costs possible using peer-reviewed models and comprehensiv e data. The RIA for this rule explains the basis for the benefits and costs and the uncertainties in the results. The agency also estimates that about 2% of coal-fired EGU capacity nationwide may retire early as a result of the rule, and this estimate is based on calculations from IPM, a peer-reviewed model.

Comment 184: Commenter 18477 asks that the EPA consider the natural air quality that exists in Hawaii and other island locations. The commenter e xplains that trade winds give Hawaii and other islands some of the best air quali ty in the nation such that they meet all the NAAQS, so the proposed rule would have minimal impact on air quality despite high costs. The commenter urges the EPA to develop a separate RIA for non- continental oil-fired units.

Response to Comment 184: This rule is a NESHAP, not a rule to implement a NAAQS, and is imposed nationwide consistent with secti on 112 of the CAA. However, the EPA has adopted provisions for noncontinental liquid oil-fired units in the final rule and ha s provided an analysis for non-continental oilfired units as part of th e RIA for the final rule.

9. State regulators.

Comment 185: Commenters 16859 and 17174 requestthat the EPA consider the burden of the proposed rule and other recently promulgated rules on the resources of individual states. Commenters ask that the EPA develop a rule that reduces air pollution and provides efficien t implementation and enforcement strategies for the delegated author ities. Commenter 16859 asks that th e EPA consider ways to secure federal funding for states to cover costs associated with state implem entation of the proposed rule and details the many obligations and costs for state ag encies. 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 fo r 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 administra tive costs, along with state direct compliance costs, the estimates might assist both the EPA in justifyi ng their request for appropriations and states in justifying permit fee increases. The commenter request s 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 accurately assess the implementation co sts on states, so the rule may be implemented properly and in a timely manner to avoid adverse health effects.

Commenters 16859 and 17400 explain that for each new EPA ru le, states may incur slightly different implementation costs. These commenters note that cost categories varyfrom state to state depending on legislative and regulated community differences. One commenter asks that the EPA consider state costs for a wide-range of implementation start-up and r ecurring activities in the implementation cost estimation for this rule, while othe rs discussed in the attachment in cluded with the original comment. The attachment details several implementation costs that must be accurately assessed for the rule to be implemented properly and in a timely manner without adversely affecting human health. The commenter also asks that the EPA seek federal funding for the states to cover the cust omary portion of the costs associated with state implementation and consider th e availability of funding support in its planning for new rule adoption schedules and other implementation activities following the rule issuance.

Response to Comment 185: The agency has addressed the impacts on state and municipal agencies in compliance with UMRA and EO 12866 and 13132. Add itionally, 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 th e 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 res pond accordingly to requests for additional state and local agency funding if it is dete rmined that such funding is neededfor implementation of this rule.

Comment 186: Commenter 17629 explains that a settlement agreement on a rate case in Wyoming created a new layer of review by P ublic Service Commission to examine the Public Need and Necessity for passing on environmental control co sts to consumers. The commenter anticipates that the analytical burden associated with this rule and others recently proposed will increase and reliance on the EPA’s technical and economic analyses will not be sufficien t. The commenter urges the EPA to take steps to change the Grant Agreements to reflect the additional burdens to states.

Response to Comment 186: The agency may consider changing Grant Agreements and help states in other ways if the analytical burden to them is substantial enough to warrant agency action.

Comment 187: Commenter 17620 discusses the increased work load of state and local air pollution control agencies as a re sult of the proposed rule. The commenter explains that the EPA has proposed a number of alternate compliance options that will reduce compliance costs for industry, but increase the cost of administering the program. The commenter stat es that in delegated stat es, permitting authorities will also conduct inspections and commence enforcement actions where sources are found to be in noncompliance, which is important because of the large amount of toxic air em issions 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 fu nding be provided under sections 103 and 105 of the CAA during those years when the majority of implementation activities will occur.

Response to Comment 187: The agency will respond accordingly to requests for additional state and local agency funding if it is determ ined that such funding is needed for implementation of this rule.

Comment 188: Commenter 17620 states that the reductions in SO 2 and PM 2.5 required by the proposed rule will assist state and local air pollution control ag encies to meet health-based air quality standards, reduce haze and improve visibility. The commenter poi nts out that substantia l reduction in emissions606 made by the very large sources under the proposed rule will lead to fewer pollution controls needed at smaller sources to meet health-based ambient air requirements. This is a far more cost-effective approach than controls at smaller facilities and is the lowest cost path to improved public health and a cleaner environment.

Response to Comment 188: The EPA thanks the commenter for the comments. The MATS is a standard to reduce HAP, but we are also finalizing revisions to the NSPS for NO X , SO 2 , and PM emissions limits for utilities. Much of the HAP requi rements will also lead to co-benefits such as PM 2.5 and SO 2 reductions that could be of aid to states working on imple mentation of various NAAQS and regional haze strategies.

Comment 189 : Commenters 17743 and 17745 express particul ar concern over the proposed rule’s impacts on the burden on the permitting authorities in light of the other current and pending EPA air rules also adding to the expected workload. Commenters 17174 and 17834 ask the EPA to consider the burden of the proposed rule that is placed on state ag encies and develop a rule that reduces air pollution but provides for efficient implementation and enforcement.

Response to Comment 189: The agency is careful to mitigate the impacts of this rule to permitting authorities to the extent possible. The agency will respond accordingly to re quests for additional state and local agency funding if it is dete rmined that such funding is needed for implementation of this rule.

10. Miscellaneous.

Comment 190: Commenter 18447 asks that the EPA consider th e 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 hist ory shows they will not.

Response to Comment 190: The agency has prepared this rule in response to the re quirements of the CAA and a court mandated consent decree. The vast majo rity of benefits resulting from this rule will be experienced in the U.S., not outside of it. Additi onally, through a variety of working groups and treaty organizations, the EPA participates in internationa l negotiations to address transboundary air pollution and to achieve a level playing fiel d in the control of air pollution.

Comment 191 : Commenter 17409 quotes a Stanford University study that says the U.S. could be run entirely on clean energy within 10 years, at reas onable cost. The commenter goes on to acknowledge other innovations in the power ge neration industry and points out th at 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 191: We agree with the commenter that new regulations such as this rule could serve to spur innovation to make energy production clean er, a trend already distinctin the electric power sector and that innovation has historically occurred at a more rapid pace than predicted.

Comment 192 : Commenter 17855 discusses the difficulties for waste coal industry in complying with the proposed rule. The commenter e xplains that the waste coal indus try is reclaiming abandoned mining sites to avoid discharging acid mine drainage, at no cost to the taxpa yers. The commenter explains that waste coal power plants control NO X and SO 2 and PM currently, but may be forced to install expensive new controls, which may make the plants economically unviable and lead to an end of mine remediation without public funding. The commenter ex plains that waste coal plants ar e 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 192: As noted elsewhere in this document, coal refuse-fired EGUs are among the units making up the MACT floor pools for all of the HAP. Thus, we believe that such EGUs are capable of achieving the limits in the final rule and are not economically unvi able as suggested by commenter. Should additional controls be required at ce rtain facilities, such controls can be added just as at other EGUs. Facilities that have already achieve d significant control of em issions are likely to face lower costs to comply with today’s rule.

Comment 193 : Commenter 17867 explains the Boardman 2 020 Plan as an innova tive approach to achieving environmental goals by ending coal-fired generation at relatively young and efficient EGUs. The commenter cites to key featur es contributing to successful disc ussions among diverse stakeholders to produce an outcome that achieved a remarkable le vel of consensus for the future of the Boardman Plant and for the people and na tural environment of Oregon:

1. A state-adopted agreement with br oad 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 co al operations to addre ss concerns regarding community impacts, including jobs at the facility, replacement of the energy resource that considers cost to customers, reliability and resource dive rsity, and consistency with CAA requirements; 4. Interim emission controls that appropriately address human health and environmental impacts for the remaining period of coal-fired operations; and 5. A robust resource planning process that consid ers low carbon replacem ent resources among the viable alternatives.

In the case of Boardman 2020, the commenter explains the combined strategy of early cessation of coal operations and interim controls wi ll result in lower aggregate emi ssions of haze causing air pollutants than those projected under a muchmore expensive contro l package that would have otherwise been required to run the plant indefinitely.

Numerous commenters (13902, 14279, 14481, 14695, 14696, 15161, 15590, 15636, 15680, 15823, 15824, 15883, 16406, 16681, 16683, 16825, 17021, 17153, 17194, 17298, 17307, 17308, 17847, 17867, 17872, 17874, 17894, 17899, 17900, 18052, and 18485) urge the EPA to recognize and accommodate appropriate solutions like Oregon ‘s Boardman 2020 plan to allow th e agreement to be fully achieved. The commenters believe that the final NESHAP ru le for EGUs needs to clearly recognize this innovative Oregon approach and provide regulatory flexibility to accommodate the Boardman plan within the framework of the C AA. The Boardman 2020 Plan is discussed in further detail by commenters 17867 and 18019.

Response to Comment 193: We thank the commenters for their comments. The timing for implementation of this rule is set in the CAA. We will allow flexibility in compliance, both in method and timing, consistent with the CAA.

Comment 194 : Commenter 18039 believes that power plants in Massachusetts and other states with reduced Hg limits have been placed at a competitive disadvantage and do not get the full benefit of their own reductions as a result of be ing 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 194: We agree with the commenter that implementation of this national rule may level the playing field, as it were, regarding Hg controls across the country.

Comment 195 : Commenter 18961 believes the rules will leve l the playing field by imposing universal standards for all coal-fir ed units, reducing uncertainties in th e 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 th at by retrofitting or reti ring out-dated coal-fired power plants, the industry will improve the reputati onal risks and relations with local communities and regulators. The commenter shares results from a poll saying that 79% of Americans are in favor of the EPA placing stricter limits on Hg from power plants.

Response to Comment 195: The EPA agrees with the commenter.

Comment 196 : Commenter 19042 cites the Executive Orders and policy directives from the Obama Administration that encourage federal agencies to in crease sustainability, reduce emissions and conserve energy. The Administration claims th is will reduce electric ity 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 intere st in the proposed rule in Congress, and it may be appropriate for reviewunder the provisions of the Congressional Review Act. The commenter states that the impacts analysis is flawed because:

1. it fails to account for the unfunded mandate to every department and agency of the federal government that either generate s or purchases electricity; 2. our analysis of the RIA found no di scussion of federal budget costs; 3. there are no estimates reported by th e federal departments and agencies in their budget projections or in the budget justifica tion materials provided to Congress; and 4. based on informal contacts with senior federal faci lity energy managers, we have found no evidence that interagency review of the Utility MACT standards cons idered federal compliance costs and budgetary priorities.

Response to Comment 196: Every major rule is subject to the CRA and this rule is no exception. UMRA is inapplicable to instrumentalities of the federal government and by its terms applies to federal actions that have impacts on state, local, tribal go vernments or private entities. The EPA’s analysis projects a near-term increas e in the average retail electricity pr ice of 3.1% in 2015 falling to 2% by 2020 under the final rule in the contiguous U.S.

Comment 197 : Commenter 19042 discusses the federal deficit of $1.6 trillion and the states’ deficit of $130 billion and points out that the proposed rule will affect the federal budget in two ways:

1. direct compliance costs to el ectric generating units (EGUs) owned by federal agencies; and 2. pass-through compliance costs paid in the form of higher prices fo r electricity purchased by federal agencies.

Response to Comment 197: The agency estimated the increase in direct compliance costs at federallyowned EGUs, and that estimate for the proposed rule is available in the docket . This estimate has been revised for the final rule. The agency estimated th e retail electricity price nationwide to increase on average by 3.7% in 2015 as a result of the rule. The agency does not expect this increase in price to lead to significant increases in federal government agency operating costs.609 Comment 198 : Commenter 19042 notes the EPA identified 96 state and local government entities with a combined total of 169 EGUs that will have to comply with the Ut ility MACT standards. For these potentially affected units, the EPA es timated the cost of compliance, sett ing that cost equal to the change in operating and capital expe nditures, plus the change in fuel cost s, plus the change in revenues resulting from the sale of electricity to consumer s at presumably high er retail prices.

The results of the EPA UMRA analysis are depicted inTable 1 and Table 2 in th e 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] anal ysis does not examine pot ential indirect economic impacts associated with the proposed [Utility MACT] rule, such as employment effects in industries providing fuel and pollution control equipment, or th e potential effects of elect ricity price increases on industries and households.

Each agency’s annually updated SSPP is intended to pr ioritize agency sustainabi lity activities based on lifecycle return on investment. OMB provides periodi c 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 “g reen light” score to the propos ed scope 1 and 2 GHG emissions targets set by the federal agencies with the larg est 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, inrecent testimony before the U.S. Senate, CEQ Chair Nancy Sutley made the following statement:

“If annual greenhouse gas emissions decrease incremen tally to produce a reduction equal to five % of calculated base year emissions, the Federal governme nt will save an estimat ed $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 justifica tion for the proposed savings. More importantly, the Administration has provided no estimates of the upfr ont capital investment that will be required in order to deploy new clean energy and energy efficiency measures need to achieve the savings. The commenter points out that the cost of electricity purchases is a significant cost in the fede ral budget. As a result of the proposed Utility MACT standards, these costs will increas e, 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 st ates that their analysis shows that the SSPP reports and scorecards failed to repo rt the base year elect ricity and associated GHG emissions data, so it is not possible to determine the percent reducti on in GHG emissions associated with electricity consumption. Thus, these assertions may have more of a political bent than an analytical basis. (See http://www.whitehouse.gov/administration/e op/ceq/sustainability/omb-scorecards .)

Response to Comment 198: The agency estimated the retail elec tricity price nationwide to increase on average by 3.7% in 2015 as a result of the rule. The agency does not expect this increase in price to lead to significant increases in federal go vernment agency operating costs.

Comment 199: Commenter 19042 provides analyses of the estimated federal budget impacts, taking into account the variation by region. However, since publically availabl e data is aggregated by agency, disaggregation by region was not pos sible, and the commenter suggests the government do this analysis. Instead, the commenter based estima tes on federal activity within each state. The commenter used the EPA RIA price increase to estimate federal electricity costs incurred du e to the proposed rule. The result was an increase of $166 million per year. The commenter recommends further anal ysis to estimate the610 magnitude of the unfunded mandate being imposed on states and local governments and the cumulative impact of pending EPA rulemakings.

Response to Comment 199: The agency has revised its UMRA analysis for the final rule. The agency did not prepare a cumulative impact analysis to a ccompany 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 regu lation; 3) estimates specific to a particular rule are more transparent than those from a cumulative impact analysis. A cu mulative impact analysis lumps several regulations together and can potentially mask a high-cost/low-b enefit regulation among other rules that may have large net benefits. By analyzing each regulation separately, the EPA makes clear statements about what impacts, costs, and benefits will be generate d as a result of this particular regulation.

This does not, however, mean EPA has failed to c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.

Additionally, the Agency does reflec t 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/su mmaryreport.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 di rect 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 Am endments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wi de margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed using any reasonable alternative assump tions 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 ru le could have unintended impacts on deregulated oil-fired units that rely on operating revenues and will be unable to have enough projected revenues to justify the cost of compliance. These units may be prematurely retired.

Response to Comment 200: Our analysis of the imp act of the rule on oil-fired units indicates that the costs per unit should be modest, and thus the probability of premature retirement for such units is low.

Comment 201 : Commenter 17648 considers the EPA to ha ve coordinated the various programs involving power plants to be eff ective and explains how the IPM modeling shows the benefits of implementation of the rules. The commenter repo rts investing nearly $5 billion in clean energy generation and Smart Grid technology and from th is experience considers the EPA’s modeling to be unduly conservative. The commenter agrees with the EPA’s modeling that shows the closure of older plants and replacement by gas-fired plants of various types and believes that expansion of nuclear and alternative energy sources will occur as well. The co mmenter also explains that the proposed rule and611 other new regulation will increase the efficiency of the fleet, fu rther benefitting the economy. The commenter questions the report, “M ethane and the Greenhouse-Gas Footprint of Natural Gas from Shale Formations” because it does not account for increased efficiency of gas-fired plants and used the wrong conversion factors from methane to carbon dioxide equivalents.

Response to Comment 201: We agree with the commenter that this rule could lead to an increase in the energy efficiency of the el ectric power boiler fleet.612 6J - Impacts/Costs: Social Costs

Commenters : 11107, 16207, 16824, 16850, 17254, 17408, 17409, 17620, 17709, 17713, 17727, 17766, 17775, 17811, 17842, 17875, 17884, 18432, 18435, 18436, 18541, 18961, 19536/19537/19538

Comment 1: Multiple commenters (16207, 17408, 17620, 17811, 18961, 19536, 19537, 19538) describe the health benefits of the rule, includ ing the $59 billion to $140 bill ion each year, or $5 to $13 in health benefits for each do llar spent on compliance as opposed to the estimated $10.9 billion annual
cost.

Response to Comment 1: The benefits of this rule as estima ted by the agency are quite substantial relative to the costs. These benefits include those a ssociated 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 analysis of the benefits and costs of this rule which is found in the RIA.

Comment 2: Commenter 16824 considers the potential health benefits of the rule to be questionable because it will have no effect on the levels of Hg and other emissions that occur naturally. The commenter considers the rule to be adversely affecting efforts to s timulate the economy and job growth and causing electric rates to rise.

Response to Comment 2: The agency’s analyses of costs and bene fits reflect the la test, peer-reviewed science that is available. The benefits analysis is based on peer-reviewed scientif ic 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 th e reductions in emissions estimated for this rule, and are incremental to a baseline that includes the impacts of regulatory programs up to December 2010. The agency’s cost analyses are also based on peer-re viewed studies and analyses. The RIA for the rule documents both analyses.

Comment 3: Commenter 16850 explains that Florida’s investo r-owned electric utilities can petition to recover the costs associat ed 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 co sts recovered. These costs range from $1.27 to $10.90 for a 1200 square foot residence. The commente r expresses concern for the Florida consumers, approximately 85% of whom rely on electricity for heating and cooling, and in clude a large portion of senior citizens on fixed incomes.

Response to Comment 3 : The agency estimates that the nationw ide retail electricity price increase associated with the rule will be 3.1% in 2015, and th ere will be some variati on in this price increase among different regions. No region of the country, howev er, is estimated to expe rience an increase in price of greater than 6.3%. In Florid a, the increase in retail electricity price is estimated to be 2.2% in 2015 for the power region that includ es the State of FL. State and loca l rate setting agencies are best equipped to deal with the i ssues concerning higher electri city rates in their areas.

Comment 4 : Commenters 16207 and 17620 discuss health benefits, such as the 6800 to 17000 people saved from premature death, 120,000 prevented asthma attacks, 850,000 employee sick days avoided and the thousands of short and long term jobs created by the rule.

Response to Comment 4: The EPA thanks the commenter for these comments. The benefits of this rule are substantial, both on their own an d relative to the costs. The reducti on in incidences and how they are613 estimated can be found in the RIA for the rule. The em ployment impacts estimated by the agency for the rule reflect both construction labor associated with new control equipm ent likely to be needed to meet the rule requirements, and operation of these controls, and the reacti on of the economy to this rule is also taken into account. The RIA for this rule contains the analysis methodology and results for employment changes.

Comment 5 : Commenters 17709 and 17727 express concern about the cost of implementing the proposed rule. The commenters cite an announcemen t by the American Electric Power company that rates would increase in response to the proposed rule and ask that the pr oposed rule be reconsidered and implemented with a compliance plan that will allow the utilities to c ontinue operating their coal-fired plants without additional stipulati ons that will increase rates. Commen ter 17709 states that the rule will exacerbate the slow recovery in the state of Michigan.

Response to Comment 5: The agency estimates that the nationw ide retail electricity price increase associated with the rule will be 3.1% in 2015, and th ere will be some variati on in this price increase among different regions. No region of the country, howev er, is estimated to expe rience an increase in price of greater than 6.3%. The agency is cognizant of the estimated price incr eases. 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 Africa n 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 regulatio ns. Commenter 17766 explains that 71% of African Americans and 80% of Hispanics live in an area that fails to meet one or more EPA air quality standard, compared to 57% Caucasians. Also, the commenter notes that 68% of African Americans and 39% of Hispanics live within 30 miles of a coal-fired power plant. The co mmenter states that this close proximity to power plants means that they are more likely to be a risk to develop health issues thanthose who live in cleaner neighborhoods. The commenter goes on to add that because these same people are more likely to live in poverty, they are less able to move from heavily polluted areas.

Response to Comment 6: We understand the commenters’ concerns. The reductions in Hg will lead to improved health in populations in close proximity to co al-fired power plants, and the benefits from these reductions are discussed at lengthin the RIA for the rule. We show the benefits of Hg and HAP emission reductions, along with th e substantial benefits from reductions in emissions of PM, SO 2 , and other pollutants in our RIA. Popul ations that are the focus of EO 12898 (low-income, minority) will benefit from these reductions as shown in the RIA.

Comment 7 : Commenter 17775 explains that for EPA benef it 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 th e 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 co mmenter believes this change inflates the baseline of PM 2.5 -related deaths and points out the EPA estim ate 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 basi s for this change is gi ven. (Footnotes reference Attachment 13 and a June 2010 Qualitative HealthRisk 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 unreasonably large estimates. The EPA estimat es health benefits below the lowest measured level (LML), as no evidence suggest a health effect threshold for PM 2.5 . These methods have withstood continuous regular reviews by the EP A’s SAB. Analyses conducted for the proposed rule demonstrated that the vast majority of PM 2.5 health benefits occurre d above the LML. Therefore, this methodological issue would not have a substant ial impact on the overall benefits.

Comment 8 : Commenters 17811 and 18436 state that withou t the proposed rule, “particulate matter emitted directly from coal-fired power plants was estimated to account for an average of $3.7 billion of public health damages each year.” The commenters go on to state that the OMB review found that from 10/1/99 to 9/30/09 the cost of a PM rule was $7 bill ion while the estimated benefits range from $19 billion to $167 billion annually. The commenters state that with few po llutants 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 co mmenters believe that the cost savings of the proposed rule represents economics and fewer childrensuffering asthma attacks, fewer hospitalizations, less respiratory tract illnesses, improved lung capacityand function for children and healthier infants and newborns. (Footnotes referencing the cited studies may be found in excerpt 11 for commenter 18436.)

Response to Comment 8: The EPA agrees that the large health co -benefits of this rule resulting from PM 2.5 reductions outweigh the costs.

Comment 9 : Commenter 17842 states that the costs associ ated with the proposed rule will increase costs for North Dakota in the range of 2 to 4 dollars more a month. The commenter is concerned that the estimated costs and affects of the proposed rule do not adequately account fo r other pending regulations and their collective effect on the industry and economy.

Response to Comment 9: The agency estimates that the nationw ide retail electricity price increase associated with the rule will be 3.1% in 2015, and th ere will be some variati on in this price increase among different regions. No region of the country, howev er, is estimated to expe rience an increase in price of greater than 6.3%. The agency is cognizant of the estimated price incr eases. State and local rate setting agencies are best equipped to deal with the issues concerning higher electricity rates in their areas. As to analysis including the effects of pending regulations, the ag ency did not prepare a cumulative impact analysis to accompany the rule for the following reasons: 1) the various EO requirements that the agency must comply with require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the impacts specific to a pa rticular 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 imp act analysis lumps several regulations together and can potentially mask a high-cost/lowbenefit regulation among other rules that may have large net benefits. By analyzing each regula tion separately, the EPA makes clear statements about what impacts, costs, and benefits will be generate d as a result of this particular regulation. We fold in the impacts of final regulations and other actions in to our baseline as appropriate in order calculate the impacts specific to a particular rule as accurately and transparently as possible.

This does not, however, mean EPA has failed to c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.

Additionally, the Agency does reflec t on the broader cumulative impacts of our regulations. In March 2011, the EPA issued the Second Clean Air Act Prosp ective Report which assesse d at the benefits and costs of regulations pursuant to the 1990 CAA Am endments. 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 be nefits from the 1990 CAA Amendments reach almost $2 trillion for the year 2020, a figure that dwarfs the direct costs of impl ementation ($65 billion). The full report is at http://www.epa.gov/air/sect812/prospective2.html

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The direct benefits of the 1990 CAA Amendments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wide margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reve rsed using any reasonable alternative assumptions or methods. This conclusion is like ly 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. Th e commenter adds that history s hows 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 re duce health costs to affected p opulations. 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 polluti on can improve worker productivity an d health as shown in the Second Clean Air Act Prospective Report released in Marc h 2011 which assessed at the benefits and costs of regulations pursuant to the 1990 CAA Amendments. The study examines the cumulative impact of these regulations (found at http://www.epa .gov/air/sect812/feb11/ summaryreport.pdf ). As shown in the report, the direct benefits from the 1990 CAA Amendments reach almost $2 trillion for the year 2020, a figure that dwarfs the direct costs of implementa tion ($65 billion). The full report is at http://www.epa.gov/air/sect812/prospective2.html

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Comment 11 : Commenter 17884 urges the EPA to reconsid er the proposed emission standards. The commenter believes the rule, and ot her recently promulgated rules wi ll 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 di sposable income that would have been spent on food, clothes, heat and air conditio ning, and healthcare. (Commenter pr ovided a bulleted list available in original letter of 8 sets of statis tics about different sects of society’ s income levels and percentage spent on energy costs.) The commenter point s out that these increased energy costs endanger public health and welfare because of the correlation between wealth and health. The commenter cites multiple legal cases in which the decision stated the agency mustconsider safety impacts of regulations. ( Whitman v. Am. Trucking Ass’ns , 531 U.S. 457, 496 (2001) (Breyer, concurring), “[p]reindustrial soci ety was not a very healthy society; hence a standard demanding the return of the Stone Ag e 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 effect s), rev’d on other grounds sub nom. Whitman v. Am. Trucking Ass’ns , 531 U.S. 457 (2001); CEI v. NHTSA , 956 F.2d 321, 327 (D.C. Cir. 1992) (agency must cons ider safety impacts of increasing corporate average fuel economy standards), and refusing to consider the indirect and negative health and welfare impacts entailed by increased regulatory compliance costs. Cf. International Union v. OSHA , 938 F.2d 1310, 1326 (D.C. Cir. 1991) (Williams, J., concurring) (“regulation redu ces incomes and thus may exact a cost in human lives”).] The commenter explains that increased liv ing standards and disposab le income mean people can better afford to eat well, heat and cool hom es 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) statis tics showing strong research in medical population statistics showing that the higher the social status of a person, the lower the probability of illness and mortality. A quoted study showed that “Assuming co sts are distributed proportional to electricity consumption, households with income under $15,000 would incur around 43% of the deaths and households over $50,000 would incur 9% of deaths due to increased energy co sts.” With unemployment rates at 9.2% and effective unemployment at ne arly 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 genera l health and welfare. The commenter points out that the EPA’s “appropriate and necessary” analysis does not consider the harm to public healththat the proposed rule represents, nor does the EPA address the potential he alth disbenefits. The commenter states that low cost, reliable energy allows peopl e to live longer and bett er and human health is threatened by the proposed rule.

Response to Comment 11: The agency’s final rule establishe s emissions standards that require reductions of HAP such as Hg, arse nic, and lead and other metals, am ong 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 focu s of EO 12898 will benefit from these reductions as shown in the RIA. In addition, the increase in electr ic rates to consumers as shown in the RIA will be 3.1% on average nationally by 2015, with some consumer s in certain regions 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 inlight of the substantial benefits to health from the emission reductions that will take place across the country due to this rule.

The agency did not prepare a cumulative impact analys is for the rule for the following reasons: 1) the various EO requirements that the agency must comply with require us to estimate impacts specific to this rule; 2) decision makers and the public need to know the impacts specific to a particular rule in order to judge the merits of the regulation; and 3) estimates specific to a particular rule are more transparent than those from a cumulative impact an alysis. A cumulative impact analysis lumps several regulations together and can potentia lly mask a high-cost/low benefit regulation among other rules that may have large net benefits. By analyzing each regul ation separately, the EPA makes clear statements about what impacts, costs, and benefits will be gene rated as a result of this particular regulation.

This does not, however, mean EPA has failed to c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.617 Additionally, the Agency does reflec t 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/su mmaryreport.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 di rect 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 Am endments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wi de margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed using any reasonable alternative assump tions or methods. This conclusion is likely to also be attributable to this rule as shown in the RIA.

Comment 12 : Commenter 11107 submits an op-ed which must be viewed at http://www.buffalonews.com/editorial-page/viewpoints/ article429987.ece due to copywrite restrictions. The commenter states that money can be saved by improving air quality and cites (along with commenter 17408) the National ResearchCouncil report that says hiddencosts of burning coal were $62 to $156 million for each coal plant. These costs are largely due to SO 2 emission. The commenter also cites a study which estimates emission-related damage s from coal-fired power plants to be between $0.02 and $1.57 per kWh generated.

Response to Comment 12: The EPA thanks the commenter for the comments. The agency estimates substantial benefits from the reduction of HAP and other pollutants from power pl ants as a result of this rule, and these results are presented in the RIA for th e rule. What the agency describes as “benefits” are similar to the health and other co sts described by the commenter.

Comment 13 : Commenter 17254 states that removal of air po llutants 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 stat e 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 clai ming 1,224 deaths caused by local coal-fired power plants, along with 1,710 heart attack s, 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 plan ts account for $62 bill ion in economic damages in 2005.

Response to Comment 13: The agency expects that the benefits of this rule to Fulton County, GA to be large, though we have not quantified the impact to this county specifically (it is included in our benefits analyses in our RIA, of course). The benefits from reductions of HA P 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)

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Comment 14 : Commenter 17408 discusses the Fisk and Crawfo rd coal-fired power plants in Chicago. The commenter says the Fisk plant was built in 1903 and rebuilt in 1959. The newest turbines at the Crawford plant were installed in 1958 and 1961. Th e commenter says that pollution from these two618 plants cost neighboring communitie s $127 million annually in health damages, according to the October 2011 report by Environmental Law a nd Policy Center. The commenter went on to cite the Natural Resources Defense Council studies that have shown a high benefit to cost ration from environmental regulations, with saving in health costs alone surpassing the cost of pollution controls or switching to cleaner energy sources. The commenter acknowledges that some jobs will be lost, but also created with the proposed rule. The commenter cites Jonathan Le vy’s Harvard report whic h 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 ar e being unfairly transferred to peopl e who may not have insurance and in the state of Iowa almost two-th irds of children live within 30 minut es of a coal-fired power plant.

Response to Comment 14: The EPA thanks the commenter for their comments. The agency expects substantial benefits to Chicago and Iowa residents as a result of this rule as HAP and other pollutants are reduced significantly. Estimates of pollution reduction and associated benefits can be found in the RIA for the rule. In addition, there may be a small net gain in employment nationally associated with this rule as shown in the RIA.

Comment 15 : Commenter 17409 questions the use of a 7% discount rate for ove rall benefits. The commenter sees a discount rate thathigh as meaning that future benefi ts lose half their value every 10 years. Because the benefits in question are the hea lth and wellbeing of children, the discount rate means the worth of children decreases by half every 10 years. The commente r suggests that when calculating for generational benefits, the EPA should use a 2.5% di scount rate as used wh en dealing with climate change.

Response to Comment 15: The preferred discount rate for bene fits estimation by the agency is 3%, not 7%. This is explained in the RIA for the rule, wher e the benefits analysis for this rule is presented. Estimates of benefits with a 7% discount rate are pr epared in adherence to OM B Circular A-4, which we must follow in preparing the RIA for a rule such as this one, and that calls fo r presentation of costs and benefits discounted at bo th 3 and 7% rates.

Comment 16 : Commenter 17409 states that the cost of po llution is being borne by children and other vulnerable people and reports that 1 in 11 children has asthma, resul ting 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 annua lly and is built on a ba y. The commenter states that 1/70 of a teaspoon of mercury is enough to cont aminate 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 asth ma or other ailments, and the reductions of HAP and other pollutants associated with this rule will lead to improve d public health and thus reduced health costs for asthma sufferers. In addition, reductions in Hg will also improve health and ecosystems, as the agency shows in the RIA for this rule.

Comment 17 : Commenter 18432 supports the proposed standards as fair and equitable and believes communities will benefit from the reduction in air pollu tion no matter if the regulated facilities choose to add pollution controls, switch fu els or shut down and pursue renewable energy sources.619 Response to Comment 17: We agree with the commenter that the pollutant reductions from this rule will be fair and equitable to the extent we can require them, and do agree that the benefits of the rule will be large regardless of how the reductions are obtained. However, we are mindful of the need to minimize the economic impacts and costs of this rule along with the need to maximize benefits when permissible under the CAA.

Comment 18 : Several commenters (18432, 18435, 18541) urge th e EPA to proceed with finalizing the proposed rule without changing it, as it will prevent more American s and especially children from premature death or chronic illness.

Response to Comment 18: The EPA thanks the commenter for their comments. We have reviewed public comments on the proposed rule as required by law and issued this fina l rule in light after considering and respondi ng to such comments.

Comment 19 : Multiple commenters (18541, 19536, 19537, 19538) say th at the full cost of the regulated pollutants is not adequately reflec ted in electricity costs or the co st-benefit analyses. The commenters state that the cost of the pollution emitted by EGUs is being unfairly placed on th e public instead of the polluting source. The commenters considered the EPA analyses insufficient because they do not assess impacts on wildlife and ecosystems, as they should be under the Biological Assessment, ESA and CAA. The commenters urge that analysis be broadened to include valuation of these impacts, even if the studies are limited.

Response to Comment 19 : The agency recognizes the need to include the effects on wildlife and ecosystems in the benefits analyses for our rules. We include these benefits to the extent that it is credibly possible according to our understanding of th e relevant science in our analyses, and this is shown in the RIA for this rule.

Comment 20 : Commenter 18961 cites a recent study by th e United Nations Environment Program which estimated that a reduction by at least 50% of Hg emissions from current levels pr ovides societal benefits more than double the implementation cost by the year 2020. The commenter reports that the estimate is based on the value of averting human neur otoxic damage, loss of ear nings, 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 fo r 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) annuallyin 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 substa ntial benefits based on the expected reduction in reductions of HAP such as Hg and other pollutants.

Comment 21 : Several commenters (19536, 19537, 19538) report that the Minnesota Pollution Control Agency and Legislative Commission on Minnesota Resources estimate the economic benefits of reduced Hg at $212 million based on 50% reduction. This study understates the total economic benefits, according to the commenter, because it does not take into account factors such as improved public health. Commenters also quote the Harvard School of Public Health estimat e 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 re tardation due to Hg emission at $361 million and the cost of excess cardiovascula r disease from Hg exposure at $3.54 billion.620 Commenters state that a decline in angling of just 25% due to lake and stream fouling by Hg could cost Minnesota $706 million annually and jeopardize 25,955 jobs in the state. In Wisconsin, the costs of water fouling from Hg could cost $516 million annually and jeopardize 21,459 jobs. Commenters believe the proposed rule will help improve regional haze and sulfate depositi on, lessen acidification of lakes and streams and decrease concentrati ons of lung damage due to air pollution.

Response to Comment 21: The EPA thanks the commenters for the results of these studies, and agrees in general with the commenters’ conclusions on reduced regional haze, sulfate deposition and lake deacidification, and improved human health related to the reduction of HAP and other pollutants related to this rule. For more information on these types of impacts and how the agency’s benefits analysis considered them, refer to the RIA for the rule.621 6K - Impacts/Costs: Health Co-Benefits

Commenters : 12267, 14115, 15002, 16404, 16469, 16630, 16826, 16849, 17157, 17254, 17283, 17381, 17408, 17409, 17620, 17621, 17623, 17637, 17638, 17639, 17648, 17676, 17681, 17689, 17702, 17707, 17709, 17715, 17716, 17718, 17727, 17730, 17731, 17734, 17736, 17751, 17753, 17754, 17755, 17756, 17757, 17761, 17765, 17766, 17775, 17799, 17800, 17805, 17811, 17813, 17816, 17843, 17848, 17852, 17855, 17868, 17871, 17875, 17880, 17882, 17884, 17903, 17912, 17916, 17919, 17921, 17930, 17931, 18018, 18022, 18027, 18029, 18033, 18034, 18037, 18039, 18421, 18425, 18428, 18432, 18435, 18436, 18438, 18477, 18478, 18487, 18488, 18498, 18500, 18501, 18502, 18541, 18759, 18961, 18963, 19114, 19121, 19145, 19580, 19536/19537/19538, 18932, 18023

1. Benefits of the proposed ru le outweigh compliance costs.

Comment 1: Several commenters (15002, 17648, 17921, 18541) ag ree with the EPA that health benefits of the proposed rule far outweigh the co sts incurred by industries to comply. Commenters 15002 and 17468 suggest that the estimates of benef its are underestimated due to the lack of quantification of benefits due to expected reductions in ground-le vel ozone. Commenter 17648 argues that the EPA employed peer-reviewed and conservative methodology in preparing the benefit-cost analysis, and argues that even without the rule, the development of stable and lower-priced natural gas supplies will result in the closure of obsolete coal plants. Commenter 17648 further states that critics of the EPA’s benefit-cost analysis do not understand the principles of economi c impact analysis. The commenter states that despite criticism, the inclusion of PM 2.5 co-benefits as part of the monetized benefits are appropriate becau se 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 standard s insufficient to protect health. Commenter 15002 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 condens ation of oxides of sulfur and nitrogen with other chemicals or particles in the atmo sphere. According to the commenter, these reductions are expected to result in a substantial reduction in several di seases, 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 syne rgistic and additive effect s of the pollutants whose emissions will be reduced; (3) enhanced ecosystem serv ices; (4) reduced acidification of ecosystems; (5) elimination or reduction of a vari ety of unquantified health impacts, including respiratory effects, resulting in increased hospital and emergency room visits, respiratory symptoms, airway hyperresponsiveness, airway inflammation and lung functio n; (6) reduction of impacts of heavy metals; and (7) secondary impacts such as economic bene fits to downwind businesses. Commenter 17921 recommends two studies regarding th e benefits of reducing Hg emissions that could be used to better estimate health benefits of the rule: (1) Rice, G., & Hammitt, J. K. (2005). Economic valuation of human health benefits of controlling mercury em issions from U.S. coal-fired power plants; and(2) Trasande, L., Landrigan, P. J., & Schechter, C. (2005). Public health and economic consequences of methylmercury toxicity to the developing brain. Environmental Health Perspectives . doi: 10.1289/ehp.7743. Commenter 18541 argues that the benef its to wildlife were not fully accounted for, saying that the EPA should formally consult the U.S. Fish and Wildlife Service and the National Mari ne Fisheries Service to set the standards strictly enough to protect wildlife and ecosystem health. Commenter 17648 suggests that the agency overestimated the costs of complian ce, partly due to technologi cal 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 benefits. However, monetization of non-Hg HAP benefits is limited by currently availabl e data and methods. In summary, monetization of the benef its of reductions in can cer incidences requires se veral 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 methodol ogy and data limitations, we did not attempt to monetize the health benefits of reductions in HAP in th is analysis. Instead, we provide a qualitative analysis of the health effects associated with the HAP an ticipated 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 th ese 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, a nd our limited ability to monetize these benefits does not indicate that they are non-existent or less important.

Our treatment of these benefits follows guidanc e 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 pref erable to qualitative descriptions of benefits and costs because they help decision makers unders tand the magnitudes of the effects of alternative actions. However, some important benefits and costs (e.g., privacy protection) may be inherently too difficult to quantify or monetize given current data and me thods. You should carry out a careful evaluation of non-quantified benefits and co sts. Some authoritiesrefer to these non-monetized and non-quantified effects as “intangible.”“

It is also in line with EPA’s Guidelines for Preparing Economic Analyses (p. 11-3, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ).

“Benefits and costs that ca nnot 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 im pacts on relevant variables).”

2. Benefits of the proposed rule do not outweigh compliance costs.

Comment 2: Many commenters (14115, 16469, 17638, 17639, 17681, 17702, 17716, 17730, 17731, 17751, 17753, 17754, 17756, 17757, 17761, 17765, 17799, 17800, 17813, 17855, 17868, 17884, 17919, 17930, 17931, 18033, 18034, 18037, 18428, 18488, 18963, 19121, 19580, 18023) suggest that the benefits of the proposed rule do not outwei gh 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 am ount to $6 million or less, far below the estimated $10.9 billion annual costs. Commenter 18037 states th at regulations focus on incrementally smaller emission reductions and with increas ed costs, and thus regulations ar e 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 approachi ng or are less than 1 in 1 million and fine particulate matter is regulated under the ambient air quality standards of the CAA. Commenter 17799 argues that the analysis of chromium emissions was flawed, inthat hexavalent chromium, a carcinogen, may be converted to less toxic forms by the time it reach es 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 he alth effects study that might be conducted.” Similarly, commenter623 18034 states that the cancer risks fr om nickel and hexavalent chromium emissions are within limits previously considered acceptable by the EPA. Commenter 17799 also poi nts 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 concer n would be 1.0...[the EPA’s definiti on 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 an d would ordinarily be considered acceptable.” Several commenters (17639, 17754, 17757) point out that the proposed rule dup licates existing regulations and will exhaust state and federal government resources.

Response to Comment 2: The EPA disagrees with commenters that the benefits of the rule do not exceed the costs. The benefits of this rule encompa ss 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 bene fits of reducing Hg emissions are not large, those benefits are also not equally distributed ac ross the population. As the sensitivity analysis shows, so me populations, including low-income African Americans and some Native American populations, may receive a disproporti onate benefit, and the distributional aspects of the benefits may help to justify the costs of the ru le. Furthermore the analysis depended on using a less sensitive endpoint (IQ) of neurol ogical impacts of Hg exposure as noted by the SAB which leads to underestimation of the benefits. Additionally many other impacts of Hg emissions were not quantified including impacts on ecosystems and wildlife especially fish, birds both fish and insect eating, and mammals. Other HAP controlled by the MATS rule we re likewise not quantified due to data, resource and methodological limitations. Even if we were able to fully monetize the public health benefits of reducing exposure to Hg and other HAP, it is likely th at the PM benefits would continue to dominate the total monetized benefits due to th e size of the exposed population and the severity of the associated health effects. Despite our inability to provide m onetized benefits of HAP em ission reductions, the total monetized benefits exceed the estimated costs of th e rule by a substantial ma rgin, 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 by OMB Circ ular 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 cost s of your rulemaking and consider any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of the rule that is typically unrelat ed or secondary to the statutory purpose of the rulemaking (e.g., reduced refinery emissions due to more st ringent fuel economy standards for light trucks) while a countervailing risk is an adverse economic, health, safety, or envi ronmental consequence that occurs due to a rule and is not already accounted for in the direct cost of the rule (e.g., a dverse safety impacts from more stringent fuel-economy standards for light trucks).”

It is also directed by the EPA’s Gu idelines for Preparation of Economic Analyses (p. 11-2, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ):

“An economic analysis of regulatory or policy options should present al l identifiable costs and benefits that are incremental to the regulation or policy under consideration. These should include directly intended effects and associated costs, as we ll 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 feasib le. 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 calculate benefits.

Comment 3: Several commenters (17623, 17639, 17799, 18428, 18963) suggest the EPA is overestimating the benefits of Hg emission reducti ons associated with the rule. Commenters 17623 and 18963 state that recent estimates of emissions from co al-fired units show a s ubstantial 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 meas ured 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. Co mmenter 18428 suggests that the improvement of 500 IQ points across the entire U.S. population estimated in the benefits calculations is negligible and should not be considered. Similarl y, commenter 17623 states that for Hg, some of the EPA’s health effects could not be monetized, such as IQ im provements. Commenter 17799 states that the EPA attempts to justify regulation of non-Hg HAP based on environmental benefits, wh ich 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 th at the benefits of Hg emission reductions associated with this ru le were overestimated. In fact, the EPA believes that the estimates presented in the RIA are an underestimate because th e EPA was not able to analyze the impacts using the most sensitive endpoints for human health. Accordi ng to the SAB’s review of the TSD for this rule “The loss of IQ points is likely to underestimate the impact of reduci ng methyl mercury in water bodies. The reason is that IQ score has not been the most se nsitive indicator of methyl mercury’s neurotoxicity in the populations studied. As noted in the TSD, in the Faroe Island study the most sensitive indicators were in the domains of language (Boston Naming), attention (continuous performance) and memory (California Verbal Learning Test), neuropsychological tests that are not subtests of IQ tests and are not highly correlated with global IQ. In the Seychelles study, the Psychomotor Development Index has been most sensitive measure and, while this is a component of the Bailey Scales of In fant Development, it is not highly correlated withcognitive measures.”

The EPA also would point out that the estimates only use self-caught freshwater fish, including saltwater fish consumption would increase th e estimates. In addition many of the benefits of Hg reductions were not quantified including the many significant adve rse impacts to wildlife and ecosystems.

Comment 4: Several commenters (17702, 17751, 18018, 18033, 18500) express concerns that the method the EPA used to monetize benefits produ ces unreasonably 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 major concern. Commenter 18033 points out that the EPA has never set a NAAQS at a level as low as the LML because the EPA believed that it was not required to protect public health; however, the commenter argues that using the LML in this rule drastically overestimates mortality associated with low levels of PM 2.5
. For several commenters (17702, 18018, 18500), the specific concern is that us ing the value of statistical life (VSL) based on the public’s willingness to pay (W TP) results in a VSL of $8 million per person. The VSL is used regardless of the time a death is postponed, while the annual value for GDP per person is around $42,000. Commenters point out that even if the death is postponed for 10 years by 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 remaini ng life, so that a 2-year-old would have a higher VSL than an 80-year-old, since people with shorte r life expectancy may be less willing to devote resources to reduce their risk of premature death. Commenter 17751 st ates that the mortality risk reduction is derived from a meta-ana lysis 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 th at the EPA does not cite studies critical of the meta-analysis or the fact that many labor market studi es 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 wh ether to apply values derived from contexts in which risk is immediate to envir onmental policy context in which risk involves long-term consideration. Commenter 17751 also points out the lack of consider ation of the importance of selection bias in the meta-analysis. Commenter 17751 states that the EPA’ s chosen value for mortality risk reduction is based on an average of findings, but the studies are not a random samp le of studies but rather those selected by the analysis author to satisfy certain crit eria not revealed. The comme nter 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 th at correction for publicati on selection bias yielded a value of $2.74 million (2000 dollars). The commenter requests that the EPA include a discussion of alternative meta-analyses of WTP studies. The commenter recommends the following:

1. Bellavance, F., Dionne, G., Lebeau, M. 2009. The Va lue of a Statistical Life: A meta-analysis with a mixed effects regression model. Journal of Health Economics 28: 444-464. 2. Bowland, B.J., Beghin, J.C. 2001. Robust Estimates of the Value of a Statistical Life for Developing Countries. Journal of Policy Modeling 23: 385-396. 3. De Blaeij, A., Florax, R.J.G.M., Rietveld, P., Ve rhoef, E. 2003. The Value of Statistical Lifein Road Safety: A meta-analysis. Accide nt Analysis andPrevention35: 973-986. 4. Dionne, G., Michaud, P.C. 2002. Statistical analys is 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 Em pirical Bayes Approach to Combining and Comparing Estimates of the Value of a Statistical Life for Environmental PolicyAnalysis

. Environmental and Resource Economics 34:385-406 6. Lindhjem, H., Navrud, S., Braathen, N.A. 2010. Va luing Lives Saved From Environmental, Transport and Health Policies: A meta-analysis of stated preference studies. Working Party on National Environmental Policies, OECD, February. 7. Liu, J.T., Hammitt, J.K., Liu, J.L. 1997. Estimated Hedonic Wage Functions and Value of Statistical Life in a Developing C ountry. Economics Lett ers 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 ha ve statistically assessed the effect of selection bias on metaanalyses of the value of mortal ity risk reduction, and have found th at 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 th ere 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 ar e 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 interagenc y review. Note that NAAQS are set at a level deemed by the EPA626 Administrator to be protective of pub lic health within an adequate marg in of safety, and are not set at a level of zero risk. Further, anal yses conducted for the proposed rule demonstrated that while 30% occur above the LML (10 ug/m3) of the Laden et al. ( 2006) study, 86% of PM2.5 health benefits occurred above the LML (7.5 ug/m3) of the Pope et al. (2002) study. We note that a more recent extended reanalysis of the Pope et al. (2002) study found significant health impacts of PM 2.5 down to a lower LML (5.8 ug/m3; Krewski et al. 2009). Theref ore, we believe estimation of he alth effects below the LMLs in the Laden et al. (2006) and Pope etal. (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 successively lower than the LML of each study our confidence in the results diminish es. Therefore, we conti nue to include statistics in the final RIA (as was done in the RIA for the propos ed rule) showing the percentage of health impacts occurring above these levels for readers to understand th e effect of this me thodological decision.

With respect to the method the EPA uses to monetize benefits, according to standard welfare economics, the economic value of a reduction in mortality risk is the maximum amount an individual would be willing to pay for it. The VSL is a representation of WTP values in that it captures the average rate at which people are willing to pay for very small changes in mortality risks (say, 1 in 10,000 per year). The VSL does not represent the value of avoiding or postponing cer tain death for any particular individual. By convention, estimates of these willingness-to-pay values are typically normalized by the change in risk. For example, if on average workers are willi ng to sacrifice $800 in add itional annual pay for jobs that have a reduced fatality risk of 1 in 10,000 per year, then the estimated VSL would be $800 × 10,000 = $8 million. The estimated annual WTP per exposed indi vidual for the average risk reduction under this rule is well below the annual value for GDP per person of $42,000.

On calculating VSL to estimate the value of remaining life, the EPA has explored the issue of remaining life expectancy and its potential effect on WTP in the past and has, in fact, received guidance from the SAB on the matter. The SAB’s full response is ava ilable in their October 12, 2007 guidance to the EPA on valuing mortality risk reducti ons, pages D-10 and D-11. To summa rize, 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 empiri cal matter. The judgment of the SAB, however, is that the empirical lit erature is not advanced enough to provide clear guidance on how age and health status affect willingness to pay to reduce mortality risks. The recommendation of the SAB is to use an age-independent valuation of mortality risk reductions. .http://yosemite.epa.gov/sab/sabproduc t.nsf/02ad90b136fc21ef85256eba00436459/4128007E7876B8F0 852573760058A978/$File/sab-08-001.pdf

Regarding the limitations of WTP, the 26 studies underlying the EPA’s guidance for WTP for mortality risk reductions come from Viscusi, 1992, which de scribes the selection cr iteria. Viscusi, 1992, is described as the source for these studies when the EP A originally used the set in The Benefits and Costs of the Clean Air Act: 1970 to 1990 (US EP A, 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 rec ognized by the Environmental Economics Advisory Committee of EPA’s SAB (SAB-EEAC) (US EPA SAB 20 00). The difficulties and limitations of these estimates for environmental policy are described in our Guidelines for Prepar ing Economic Analyses (US EPA 2010).

The agency has examined multiple meta-analyse s 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 e xperts in statistical meta-analy sis (USEPA 2006). The agency has627 consulted with the SAB-EEAC on how to evaluate a nd apply meta-analyses, and how the agency should revise its own meta-analysis methodology. Altho ugh the SAB-EEAC did not recommend that the EPA adopt any of the existing meta-analyses, the Committee made several recommendations on how the agency should conduct its own analysis, including de tails on selection criteria , and how to incorporate results from different methods and in different contexts (US EPA SAB 2007, 2011). Based on these advisories the EPA is now reviewing the existing literature and developing methods to inform new guidance on valuing reductions in mortality risks in agency economic analyses. This effort will include considerations of many potential biases in the resulting estimates, including issues such as the publication bias concern describe d in the Giles, et al. study.

Comment 5: Several commenters (16469, 18500, 17621, 17283) suggest that the uncertainty analysis is insufficient. Commenter 17621 argues th at “the only quantitative uncer tainties presented are those for the particular dose-response estimates taken from th e two studies cited by EPA. Other uncertainties are listed in several tables, withno attempt to quantify them.” Several commenters (16469, 17621, 17283, 18500) suggest that the differential to xicity of PM species needs to be considered when calculating potential health benefits of emi ssions reductions to fully assess the impacts, and this issue should be considered in the uncertainty analyses.

Response to Comment 5: The EPA disagrees with these commenters that the uncertainty analysis is insufficient. We conduct several di fferent types of analyses that examine the effects of the most important methodological choices on results. For ex ample, we estimate mortality impacts using health effect estimates garnered from an EPA-sponsored e xpert elicitation (Roman et al. 2008). The experts in the elicitation produced a range of effect estimates that span from smaller than the effect estimate by Pope et al. (2002) and larger than the effect estimate by Laden et al. ( 2006). The expert elicitation is one method of characterizing uncertainty in PM-relate d mortality. Although we are unable to quantify the impact of all sources of uncertainty, we examine the effect of assuming a healtheffect threshold at the lowest measured level in the ep idemiology studies. We also conduct sensitivity analyses examining different income elasticity assumptions. The uncertainti es that are not quantifiable are listed in tables to acknowledge their possible influe nce on estimated benefits.

4. Criteria co-benefits should no t be considered in analysis.

Comment 6: Many commenters (17702, 17716, 17751, 17753, 17754, 17765, 17775, 17799, 17813, 17855, 17912, 17919, 18034, 18428, 18488, 18498, 18963, 19114, 18023) question the use of criteria co-benefits to justify HAP regulation. They suggest that the inclusion of co-benefits is contrary to the original intention of reducing Hg em issions, because the reductions of PM 2.5 emissions can be expected to be achieved through other regulations. Commente r 17765 states that the little incremental health benefits from the proposed rule do not justify its economic impacts. Commenter 17716 estimates that without co-benefits , the “net benefits” of the proposed rule would be negative $42,000,000,000 to negative $130,000,000,000. Commenters 17716 and 17799 question the intent of the CAA or legislative history to have co-benefits from criteria pollutants regulated under a different CAA regulatory scheme serve as the driving force to curb HAP emi ssions through MACT regulat ion. Commenters 17754 and 18034 acknowledge that benefits beyond those from Hg emissions reductions will be up to $130 billion annually, but again, since thes e benefits come from co-benefits from reducing PM 2.5 emissions, consider the cost-benefit analysis supporting regulation of Hg emission to be flawed. Commenter 17775 attached a memo by Dr. Anne Smith providing technical comments on the RIA for the proposed rule and discussing the use of co-benefits . The commenter states that 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 questi on the EPA’s legal justification for the proposed rule that argues non-Hg HAP must be regulate d. Commenter 17719 points out that there is a separate program for the regulation of PM 2.5 , and the EPA does not address whether th ere 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 cost effective solution for regulatory priority.

Multiple commenters (18023, 16469, 17621, 17718, 17751, 17761, 17800, 17816, 17919, 17855, 18033, 18963) find the EPA calculation of PM 2.5 NAAQS benefits to be incorr ect because the commenters say the EPA is either double counting potential benefi ts of the NAAQS program in the calculation of benefits from the proposed rule, or relying on the suppositio n of health benefits from any PM reduction anywhere. Commenter 18023 considers this an un founded supposition that both the EPA and the EPA science advisors have rejected as t oo 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, from CO 2 reductions and HAP reductions. The co mmenter states that this change means the cost of the proposed rule would exceed the monetized HAP be nefits by a factor of at least 1,800.

Comment 7: Numerous commenters (16469, 16849, 17638, 17681, 17702, 17730, 17799, 17848, 17919, 18018, 18033, 18500, 18023) estimate that 90-99% of the benefits the EPA attributes to the proposed rule actually come from 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 beli eve the same benefits would be delivered by 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 co sts without commensurate benef its 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 require ments and the associated public health and environmental benefits from thos e reductions. Commenter 17848 points out that the estimated health benefits from the proposed rule were compared with th e 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 nearly 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 shoul d be lower after Transport Rule implementation, a smaller quantity of SO 2 reductions would be achieved 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 currently considering for a new PM 2.5 NAAQS, and thus should not be considered under this rule. Comm enter 18500 cautions that the EPA’s monetizing benefits estimate due to CO 2 reductions should be considered carefully because a of the questions associated with climate change.

Comment 8: Many commenters (16469, 17621, 17623, 17637, 17681, 17702, 17751, 17761, 17775, 17800, 17855, 17884, 17919, 18033, 18963, 18023) note that the PM 2.5 co-benefits to which many of the proposed rule’s benefits are attributed are main ly based on emission reductions in areas already achieving the annual PM 2.5 NAAQS or are being addressed by other rules. As such, commenters 17623 and 17855 ask that the EPA explain wh at additional PM benefits are derived from the proposed rule. Commenter 17681 considers the costs of the proposed rule to be very low and not outweighed by the “contrived” benefits. Comme nters 17919 and 18023 state that the NAAQS set a level of PM 2.5 that the629 EPA found to be sufficient to public h ealth and welfare with an adequate margin of safety and areas in attainment with this level ar e already safe from health ri sks. Some comme nters (17855, 17621, 17637, 17718, 17761, 18963) state that attain ment of the NAAQS for PM 2.5 is already being addressed on both the local and regional basis through SIPs and CS APR. 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 clearly articulate the indivi dual 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 attribu tion of 90% of the h ealth benefits under this rulemaking to justify the further regulati on of PM is problematic based on recent studies. See, e.g., Koop, Gary, Ross McKitrick and Lise Tole (201 0) “Air Pollution, Economic Activity and Respiratory Illness: Evidence from Canadian Cities 1974-1994” Environmental Modeling and Software 2010, doi: 10.1 016/j.envsoft.201 0.01.01 0; Gary Koop, Lise Tole, “Mea suring the Health Effects of Air Pollution: to what extent can we really say that people ar e dying from bad air?” Journal of Environmental Economics and Management (2004), 30-54.

Comment 10 : Commenter 18023 believes the EPA’s flawed co st-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 commente r believes the EPA is double counting benefits associated with PM 2.5 in its RIA, and therefore has failed to meet its obligations to promulgate a regulation that imposes th e 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 estimati on of benefits expected by MATS. Accounting for ancillary benef its is standard practice in be nefit-cost assessment since these benefits are a consequence of the rule, regardless of the rule’s intended pu rpose (as noted also by commenter 17768). As such, the EPA estimates all of the anticipated costs and bene fits associated with a regulatory action, to the extent feasib le, for the purpose of determining the likely impacts, not to justify an action. This rule is expect ed to achieve substantial PM 2.5 health benefits resu lting from primary PM and SO 2 emission reductions, and these co-benefits ar e thus an important category to quantify.

Consideration of ancillary benefits in benefit-cost analysis is directed by OMB Circular A-4 (p. 26, available at: http://www.whitehous e.gov/omb/circulars_a004_a-4/ ):

“Your analysis should look beyond the direct benefits and direct cost s of your rulemaking and consider any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of the rule that is typically unrelat ed or secondary to the statutory purpose of the rulemaking (e.g., reduced refinery emissions due to more st ringent fuel economy standards for light trucks) while a countervailing risk is an adverse economic, health, safety, or envi ronmental consequence that occurs due to a rule and is not already accounted for in the direct cost of the rule (e.g., a dverse safety impacts from more stringent fuel-economy standards for light trucks).”

It is also directed by the EPA’s Gu idelines for Preparation of Economic Analyses (p. 11-2, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ):

“An economic analysis of regulatory or policy options should present al l identifiable costs and benefits that are incremental to the regulation or policy under consideration. These should include directly intended effects and associated costs, as we ll as ancillary (or co-) benefits and costs.”630 In line with this guidance, the EPA estimates all of the anticipated costs and benefits associated with a regulatory action, to the extent f easible. We further note that we were unable to monetize other important benefits, including health bene fits of ozone reductions, additional PM 2.5 health benefits, and direct health benefits of reducing SO 2 . If we were able to fully mone tize these benefits, the benefits would exceed the costs by an even greater amount than we currently estimate.

Regarding commenters’ assertion that the EPA is double-counting 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 doubl e-counted with the health benefits achieved by other regulations. The EPA’s standard practi ce for its rules is to estimate, to the extent data and time allow, all benefits of the emissions reductions achieved by a rule beyond control require ments 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 consider ed to be part of the baseline. Therefore, the benefits from particle reductions are not double-counting – they are real health benefits from emissions reductions achieved by MATS alone.

Further, the PM 2.5 health benefits expected from this rule are not double-counted withbenefits 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 stra tegies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, th e control strategies that states may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directlyresult 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 cost s 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 th e Administrator to be pr otective of public health within an adequate margin of safety, taking into consideration effects on susceptible populations based on the scientific literature availabl e at the time the standard is set. Although benefits o ccurring 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 scie ntific information and methods in monetizing the climate benefits of this rule and include a careful disc ussion of the associated uncertainties and limitations.

5. Health impacts are minimal and are not thoroughly investigated.

Comment 11: Some commenters (17621, 17689, 17775, 18033, 18963, 18023) argue that utility acid gas emissions (primarily HCl) cause insignifican t harm. Commenter 18023 stat es that the conclusion that HCl could exacerbate ecosystem acidification is speculative and unsubstantiated. Commenters 18033 and 18963 point out that the EPA never provided a finding of public health concern to regulate631 non-Hg HAP, and provides no evidence that “more stringent control of aci d gases would benefit ecosystems other than some vague referencing of the possibility.” Commenters 17775 and 18033 argue that the predominant HAP in the acid gas group, HC l, poses no significant potential for exceeding the chronic RfC value according to the EP A’s own calculations, even though the PM 2.5 benefits in the RIA are solely attributable to the control of HAP aci d 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. assessme nts of acidification.”

Response to Comment 11: Based on recent peer-reviewed resear ch 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, transf erring acidity easily through soils and water, 2) that HCl can transport longer distances than previously thought (given its presen ce in remote ecosystems, and 3) that it can be a larger driver of acidifi cation previously thought. In 2009 the EPA published a comprehensive risk assessment of acidification eff ects of nitrogen and sulfur deposition and in 2011 published a Policy Assessment based on the findings in the Risk Assessment (both documents are available at: http://www.epa.gov/ttn/naaqs/standards/no2so2sec/index.html ). Given the extent and importance of the sensitive ecosystems evaluated in the review of nitrogen a nd sulfur deposition any substance that contributes to further acidification must be considered to be a ffecting the public welfare.

Comment 12: Several commenters (16469, 17621, 17715) take i ssue with the use of the two primary health studies used in the benefits analysis (Pope et al., 2002; Laden et al., 2006). Commenter 17715 argues that the studies take a si mplistic approach to their calcul ations (grouping all PM components together) even though there is evidence that PM components do not all have equal health significance. Commenter 17621 argues that because the dose-response function for PM 2.5 relied on two studies and not a full review of the published lite rature, it is flawed and only refl ects a subset of the literature. Commenter 17621 also takes issue with the EPA’s choice of dose-response function from the Laden study; the commenter argues that the EPA should have used only the most recent mortality risks instead of the risk for a combined time period, because the mo re 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 di sagrees with the EPA’s statement that some studies were excluded from analysis due to having study populations of a “selective nature,” because the commenter argues that this is tr ue of all studies, including the P ope and Laden studies. Commenter 17621 argues that the inclusion of ot her studies would be appropriate and could change the estimated benefits. Commenter 17621 argues further that the me thodology used in these studies appears flawed, particularly in the methods used to estimate mortalitybenefits. They state that this could overestimate the benefits associated with changes in PM concentr ations, and thus these studi es should not be used until the flaws are remedied.

Response to Comment 12: The EPA disagrees that the methodology used to estimate PM 2.5 health impacts is flawed. The EPA methods for quantifying h ealth benefits of emissi on reductions are based on the best available peer-reviewed science and methods that have withstood scrutiny from the EPA’s independent SAB, the National Acad emy of Sciences, and continuous in teragency review. We note that the evidence on differe ntial toxicity of PM 2.5 components and mixtures is currently inconclusive. We therefore follow the advice of the EPA’s Clean Air Science Advisory Committee (Hammitt et al. 2010, available at: http://yosemite.epa.gov/sab/sabproduct.nsf/fedr gstr_activites/2nd%20Pro spective%20812%20Study!Op enDocument&TableRow=2.3#2.), which concluded that “A lthough the possibility of differential 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 concentra tion-response factors from the broa dest time periods available to take advantage of the available data most comprehe nsively. The choice of relati ve risk estimates from Pope et al. (2002) and Laden et al. (2006) is su pported by the EPA Advisory Council on Clean Air Compliance Analysis (Hammitt et al. 2010, available at: http://yosemite.epa.gov/sab/sabproduct.nsf/9288428b8eeea4c885257242006935a3/59e06b6c5ca665978 52575e7006c5d09!OpenDocument&TableRow=2.3#2 .):

“Overall, the HES finds the EPA analyses, data choices, and methodologies to be sound. The EPA bases its estimates of the mortality benefits of reducing fine particulate matter (PM2.5) on data analyzed from two large, long-running landmark studies on the health effects of air pollution, the Harvard Six C ities Study and the American Cancer Society (ACS) Cancer Prevention Study (CPS). The HE S finds the selection of these cohort studies as the underlying basis for PM morta lity benefit estimates to be a good choice” (p. 1).

We further note that we also estimate mortality using functions derived by 12 experts in an EPAsponsored expert elicitati on (Roman et al. 2008). The Pope et al . (2002) and Laden etal. (2006) studies were found to be near the 25 thand 75 th%iles of the mortality effect estimates garnered from the expert elicitation. Our use of the expert e licitation functions provid es one estimate of the range of possible impacts.

Comment 13: Commenters 17707 and 17824 suggest that ther e is little evidence to support a link between air quality and asthma. Co mmenters cite the increased asthmarate from 3.1% of the population to 8.2% of the population between 1980-2009, 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 13: The commenters provide no references to support this argument. The EPA methods for quantifying health benefits of emissi on reductions are based on th e best available peerreviewed science and methods that have withstoo d scrutiny from the EPA’s independent SAB, the National Academy of Sciences, and continuous intera gency review. Note that the EPA estimates the reduction in asthma attacks, not the onset of asthma, for the calculation of health benefits.

Comment 14: Some commenters (17709, 17727, 17731, 17755, 17805, 18018, 18477) question the EPA’s assessment of health benefits resulting fromthe 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 util ities would result in addi tional 0.2 cancer cases per year. Commenter 18477 also states that “EPA ack nowledged 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 nick el and HAP thoroughly enough to de termine health risks, and the commenter suggests that the EPA should re-evaluate th e health risks. This commenter suggests that the EPA must specifically reconsider the nickel speciation data used to calc ulate the nickel health risks in the Utility RTC, and incorporate more data provi ded by the industry to improve the calculations. The commenter also conducted their own risk analysis fo r nickel emissions using an assumption of 5% of nickel emissions as carcinogenic, and calculated risk below the thre shold for delisting a source from regulation under section 112. Seve ral commenters (17731, 17755, 18018) s uggest there is a lack of substantive HAP health risks linke d to current EGU emissions outsi de of Hg-related benefits, and commenter 17805 adds that the mechanism of hu man 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 be nefits of the proposed rule. Commenters 17727 and 17709 point out air quality modeling by the Midwest Oz one Group showing reductions to comply with the Clean Air Interstate Rule will allow nearly all areas of the U.S. to meet fine particulate standards, meaning that the assessment of the proposed rule includes benefits th at 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 ri sks due to non-Hg HAP, by itself, is sufficient to support the determination that it is appropriate and necessary to regulate EGUs under section 112 of the CAA (see preamble for further de tails). The EPA disagrees with the commenters’ assertions that nickel emissions can be assumed to be only 5% as carcin ogenic 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 envi ronmental benefits of th e proposed rule is due to a lack of associated HAP risks in the first place; rather, this is due to the lack of scientifica lly-accepted methodologies for estimating HAP-related benefits.

6. Health impacts are significant.

Comment 15: Numerous commenters (16404, 17254, 17408, 17409, 17766, 17811, 17852, 17871, 18432, 18435, 18436, 18487, 18501, 19536/19537/19538, 18932) explai n that the elderly, young, poor and minority groups as well as those inthe southeast face incr eased 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 pol lution, even in the pren atal stages. The comment ers further state that people with chronic diseases ar e also exceptionally susceptible. Commenter 17811 states that HAP cause damage to eyes, skin, breathing passages, ki dneys, nervous system, part icularly 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 co al-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 pa rticulates into the air annually; a third of asthmatics in Wisc onsin live within a few miles of the plant, and most of those who do are minorities. Several commenters (17766, 19536, 19537, 19538) also point out that power plants tend to be near low income people who lack insurance and do not have paid sick leave, and thus air pollution will cause greater inconveni ences for them. Commenter 17409 refe rs to studies that associate violence, mental retardation, and sc hizophrenia with higher levels of metals in the blood. Commenter 17254 cites several studies showing the susceptibility of sensitiv e populations to poor air quality, including one study that revealed a “clear association between respirat ory emergency department visits in Atlanta and sulfate rich fine PM, the kind of fine particles formed in the atmosphere as a result of gases emitted by coal fired power plants.” Commen ter 17254 also cites a study showing that “children with autism were more vulnerable to environmenta l pollutants because they have lower levels...of the body’s natural defense for excreting environmenta l pollutants.” Commenter 18932 states that the southeast has one of the highest conc entrations of coal-fired power pl ants in the nation, putting an undue health burden on the population.

Response to Comment 15: The EPA agrees that exposure to fine pa rticulates and toxic air pollutants is associated with many adverse health effects and reduci ng exposure to these pollutants is associated with substantial public health benefits.634 Comment 16: Many commenters (16404, 16826, 17157, 17283, 17409, 17620, 17676, 17811, 17843, 17875, 17916, 18022, 18027, 18029, 18039, 18421, 18425, 18432, 18435, 18436, 18477, 18478, 18487, 18501, 18759, 19145, 18932) describe the Hg and non-Hg HA P 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 child bearing age have enough Hg in their bodies to put a baby at risk for Hg poisoning. Commenter 18759 reports that 25 milli on Americans have asthma, of which 7.1 million are children. Commenters 18435 and 18425 state that SO 2 and NO X are dangerous pollutants that will be significantly reduced by th is rule. Commenter 18435 argues further that many of the constituents of PM 2.5 are known to cause cardiovascular effects and respiratory harm. Commenter 18435 also presents the results of their calculation using the CALPUFF atmospheric dispersion m odel to estimate health benefits from the proposed rule; th eir calculations showed that us e of the best av ailable control technology would avert 70 deaths per year in a population of 33 million people. Commenter 18421 points out the toxic effects of lead, particularly to children, and the pot ential carcinogeni city of organic HAP like dioxins and furans. Commenter 18039 describes the accumulation of Hg in the environment, and the resulting exposure th is causes to the population.

Commenter 17916 states that the rule will also re duce emissions of harmful criteria pollutants. Commenter 17843 describes the link between nickel emi ssions with increased risk in daily mortality. Commenter 17620 states that the “most recent EP A assessment of cancer ri sks from ambient HAP concentrations estimates that the entire US populati on at the time of the a ssessment had an increased cancer risk of greater than 10 in 1 million, while 1 3.8 million people have an increased cancer risk of greater than 100 in a million, as a result of breath ing HAP at 2005 ambient levels over the course of their lifetime.” Commenter 18932 cites a study that concluded that meta ls and other toxic substances known to be emitted by coal-fired power plants cr eated elevated risk levels for cancer and noncancerous health effects and are known to seriously in jure human health. Many of the toxic metals from coal combustion are emitted as fine particulates, which bypass the body’s defenses and lodge in the lungs leading to short and long-term health problems. Multiple commenters (17157, 17409, 17620, 17826, 18029, 18487, 18759) state that the 400 coal-fired po wer plants across the country release over 386,000 tons of HAP annually, and clean ing up these power plants can save over 17,000 lives annually. Commenter 17409 cites a study in Penns ylvania that estimates 1359 premat ure deaths are attributed to toxic emissions from power plants in 2010. This co mmenter (17409) also cites a Clean Air Task Force study that estimates the health impact s of the plant BL England at 32 he art attacks, 300 asthma attacks, and 19 deaths. Commenter 18487 states that due to the hi gh toxicity of dioxi ns, these should be regulated in the final rule. Commenters 16404 and 18932 cite estimates of ove r 13,000 deaths, nearly 10,000 hospitalizations and more than 20,000 heart attacks per year nationwide at an economic cost of $100 billion. Some commenters (17283, 18932) do notfully 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 mu st be regulated under stringent MACT standards. Commenter 18932 discusses a study in Alab ama that concluded that the levels of air toxics in the air had “elevated risk levels for cancer and non-cancerous h ealth effects” and are “em itted in harmful quantities by coal-fired power plants in the region.” Commen ter 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 thatHAP cause acidification and degradation to the environment. Commenters point out that toxic metals contaminate and bioaccumulate in waterways and animal life, causing further exposur es to local communities and harming recreational activities. Commenter 17921 points out th at it is difficult to determine he alth 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 eff ects in children. Commenter 18421 stat es 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, especi ally harmful to children. Commente r 18421 also states that acid gas emissions contribute to acidificati on of ecosystems, and this cause s harm to human health and the environment.

Several commenters (19536, 19537, 19538) explain that m eeting 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 nitrate particles.

Response to Comment 16: The EPA agrees that the proposed rule will lead to reducti ons of criteria and HAP responsible for significant adverse health effect s and that such reducti ons will produce substantial public health benefits.

The EPA agrees that Hg exposure in wildlife is responsible for variou s adverse health effects in many species across the U.S. and recognizes that researchis ongoing in this area. As discussed in the Appropriate and Necessary finding, the EPA agrees that there are enviro nmental risks from exposures of ecosystems through Hg and non-Hg HAP deposition. The benefits to ecological health remain unquantified in the assessments for this rule due to data and methodological limitations. The EPA cited relevant articles from the special edition of Ecotoxicology mentioned by the commenter in the ecosystem effects section on Chapter 5 of th e RIA for this rule. Ecotoxicology. 17:83-91, 2008.

The EPA agrees that acidification poses a significan t 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/no2s o2sec/data/NOxSOxREASep2009MainContent.pdf for a comprehensive report on those effect s including increased Hg methyla tion in acidified systems. Based on recent peer-reviewed research including Evans et al . (2011), acid gases can significantly contribute to acidification and the EPA agrees that those acid gases pose a risk for acidification of ecosystems. However due to data and methodolog ical limitations the EPA was not ab le to quantify those risks and benefits.

Regarding health effects of acid emissions, the EP A agrees that the large percentage of acid gas emissions that can be attributed to EGUs may cause or contribute to chronic re spiratory health problems. They are being subjected to emission limits in today’s final rule.

7. The proposed rule will harm public health.

Comment 17: Commenter 17919 suggests that the proposed rule will adversely impact public health by increasing the cost of medical care, by “suppres sing economic growth and the improved health it brings,” and by inefficiently using resources on expe nsive rulemakings instead of other public health measures. The commenter points out that the health sector is the second most energy intensive commercial sector, and increases in energy costs would translate to rapid increases in health care costs.

Response to Comment 17: The commenter’s assertion relies on the th eory that the cost of the rule will result in lost income or employmentthat will, in turn, result in nega tive health effects that offset the636 positive health effects of the rule. (This is referred to as a “health-health tradeoff.”) The EPA disagrees with this point and notes that th ere are a number of conceptual and empirical problems with any attempt to quantify the health-health tradeoffs of regulatory action to control air pollu tion. These analyses rely on questionable applications of cro ss-sectional data and ignore key fact ors that may influence changes in population health risks. Additionally, marginal d ecreases in household income caused by the pass through costs of the regulation are unlikely to cause larg e changes in any single aspect of household spending, such as health care. These analyses also fail to consider that household income may increase if individuals are able to work (or work more) as a resu lt of improved health, offsetting some or all of the pass through costs of the rule. For these reasons, the EPA’s science and economic peer review panels have consistently advised against attempting to quantify any health-health tr adeoffs of regulation.

8. Support for the proposed rule.

Comment 18: Multiple commenters (12267, 17381, 17852, 17871, 17880, 17882, 17903, 17916, 18022, 18432, 18435, 18438, 18478, 18501, 18961) support the proposed ru le and agree withthe regulations designed to address the source of pol lution as strictly as necessary to protect human health. Commenters 17882 and 18501 further add that coal-fir ed power plants are responsible for 99% of Hg emissions from the power sector in the U.S., jus tifying the rule. Commenter 17903 points out that some air toxics exist at high levels near coal-fired f acilities, such as aldehydes and P AHs, that are not regulated by any ambient monitoring requirements. Commenter 17916 poi nts out that much of the Hg deposited in Ontario originates in U.S. coal-fir ed EGUs, that has many potential adverse health effects, thus they strongly support the rule. Comm enters 18432 and 18435 further urge the EPA not to weaken the proposed rule.

Response to Comment 18: The EPA acknowledges generally supportive comments (including commenters 12267, 15002, 17381, 17648, 17852, 17871, 17880, 17882, 17903, 17916, 17921, 18022, 18432, 18435, 18438, 18478, 18501, 18541, 18961, 19536, 19537, 19538, 18932) on the quantification of PM 2.5 health co-benefits. The EPA agrees with these commenters that the larg e 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 benefi ts, enhanced ecosystem services, increased fish consumption by women) were notable to be quantified.

9. Miscellaneous comments.

Comment 19: Commenter 16630 asks how averaging in combination with the credits affect the environment.

Response to Comment 19: In the proposed rule, the EPA planned to allow averaging of existing sources in the same subcategory at a common plant site for a gi ven 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 pr ovisions), to the extent possible, while ensuring public health is protected inaccordance 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 21: Commenter 17736 disagrees with the EPA’s claim that “it is reasonable to only consider emissions reductions achieved from requirements directly imposed on EGUs because EPA cannot predict with any certainty how EG Us would satisfy other required reductions.” The commenter argues that the EPA can use the EGU’s Title V permit to id entify all CAA requirements and make regulations accordingly.

Response to Comment 21: 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 determ inations that it remains necessary to regulate HAP emissions from EGUs. As indicate d therein, we maintain that th e 2000 finding was reasonable at the time it was made based on the available informati on and that our new analyses of wherein we considered whether HAP emissions remaining after imposition are reasonably anticipated to pose a hazard to public health and th e environment far exceeds what is contemplated in CAA section 112(n)(1)(A).

Comment 22: Commenter 17811 argues that the proposed rule is insufficient to reduce levels of HAP to safe concentrations, based on modeli ng and monitoring data in Alabama.

Response to Comment 22: The EPA disagrees that today’ s final rule, which is technology-based, must reduce levels of HAP from EGUs to safe concentra tions. It is the requirem ent 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 protect public health with an ample margin of safety. We have based the final rule on the performan ce of the best performing sources in accordance with the statute.

Comment 23: Commenter 18502 argues that Puerto Rico curren tly is in compliance with all ambient air quality standards and thus furthe r reductions in HAP emissions fromthe proposed rule will have no benefits to air quality on the island.

Response to Comment 23: Compliance with the NAAQS is not re levant to whether there would be benefits associated with this rule. The benefits ar e related to the emission reductions associated with applying controls. Both PM and oz one 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 24: Commenter 17848 states that the numbers regarding monetized benefits in the proposed rule do not match the RIA. The rule states that to tal Hg-related benefits we re calculated to be $450,000 to $890,000 at a 7% discount rate while the RIA states that Hg-related benefits were calculated to be $5,000 to $9,000 at a 7% discount rate. The commenter requests that the EPA review the information and revise accordingly, and also suggests that the EPA use a single base year (2006$ or 2007$) when tabulating benefits.

Response to Comment 24: Any discrepancies in the proposal will be corrected in the final RIA. All costs and benefits are presente d 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, 18487, 18498, 18500, 18541, 19210, 19214, 19506, 6640, 18932, 18023

1. General impacts.

Comment 1: Commenter 17807 states that the EPA should inco rporate the latest Hg toxicological data, reevaluate its conclusions, and determine whethe r the proposed rule is a ppropriate and necessary.

Response to Comment 1: The EPA disagrees that the data and me thods 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 pr ovides an objective, reas onable, 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 consider ed the spatial resolution of the modeling of Hg deposition to watersheds to be appr opriate for the analysis. There was agreement that the approach used to identify watersheds to includ e in the assessment was reasonable. This approach was based upon the availability of fish tissue methyl mercury data and census data on target populations with potential subsistence fishers. The SAB agreed that the EPA’s cal culation of a hazard quotient for each watershed included in the assessment is appropr iate as a principal means of expressing risk.

The EPA Science Advisory Board Report available at: http://yosemite.epa.gov/sab/sabproduct .nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985 2578cb006bcb04!OpenDocument

Comment 2: Commenter 18023 states the if the EPA had re ported 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. A ccording to the commenter, the EPA compounds this mistake by estimating a cost associated with accumulated IQ loss after recognizing that these benefits would be lower if lags were properly considered.

Response to Comment 2: The EPA disagrees with the comment er’s statement that the benefits calculated would be zero. The benefi ts calculated are averaged across the population and hence the small increments yield the benefits report ed. In addition, the EPA recognizes th at 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 poi nts 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 studi ed. As noted in the Mercury Risk TSD, in the Faroe Island study the most sensiti ve indicators were inthe domains of language (Boston Naming), attention (continuous performance) and memory (California Verbal Learning Test), neuropsychological tests that are not subtests of IQ tests and are not highly correlated w ith global IQ. Inthe Seychelles study, the Psychomotor Development Index has been most sensitive measure and, while this is a component of the Bailey Scales of Infant Develo pment, it is not highly correlated with cognitive measures.”639 The EPA acknowledges that MMAPS does not accountfor a time lag in ecosystem response to reductions in Hg emissions. Ecosystems are highly variable in their response to reductions in Hg emissions. Due to limitations in data and methodology, EPA was not able to quantify the effect of lag times on benefits.

Comment 3: Commenter 17621 states that with respect to th e “hypothetical full scale IQ” this relatively small incremental change in IQ (0.18 on a 100-point IQ scale) associated with a 1 ppm Hg increase in hair cannot itself be measured for an individual, but must be estimated for the total population (through a series of analytical and exposure assumptions) to derive estimates at the national level (e.g., 510.8 IQ points saved in RIA, Table 5-7). Th e individual effects estimates for the “average” IQ loss per exposed child were defined out to the fourth or fifth decimal place (see RIA, Tables 5-6 and 5-7) to indicate the potential (and relatively) small effects across the different exposure scenarios.

Response to Comment 3: Although the EPA disagrees that the IQ re sults are too small to be important, the EPA acknowledges that IQ is not the most sensitive neurodevelopmental endpoint affected by methylmercury exposure. The EPA analysis of poten tial IQ loss from methyl mercury exposure is for population effects, as is done for a ny quantitative estimate of risk. For precision, it is appropriate to use a large number of significant figure s in calculation, if this is s upported 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 e ffect estimates from the underlying epidemiological studies and the exposure estimates, th e level of precision is to 2 signifi cant digits to the right of the decimal place.

The EPA independent SAB recommended that the IQ an alyses be retained but de-emphasized in the documentation underlying the final regulation (U.S . EPA-SAB, 2011). SAB concluded, “The Panel does not consider it appropriate for EPA to use IQ loss in the risk assessment and recommended that this aspect of the analysis be de-emphasized, moving it to an appendix where IQ loss is discussed along with other possible endpoints not included in the primary assessment. Although the Panel agreed that the concentration-response function for IQ loss used in the risk assessm ent is appropriate, and no better alternatives are available, IQ loss is not a sens itive response to methylme rcury and its use likely underestimates the impact of re ducing methylmercury in water bodi es.” (U.S. EPA-SAB, 2011) The EPA is following the SAB recommendation by deemphasizi ng 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 healthrisks associated with exposure to Hg emissions from EGUs. Several commenters (19210, 15160, 18421) note that HAP, such as Hg, are linked to many health problems, including cancer, heart disease, ne urological damage, birth defects, asthma, and premature deaths. Commenter12798 states that the hea lth of Americans and the economy will be greatly aided by these new regulations. The commenter quotes a Harvard study that found Hg emissions from coal-fired power plants may cost the country nearly$30 billion per year in health, environmental and economic impacts and suggested a cost of another $100 billion per year from pa rticulate emissions and $200 billion from climate change emissions. The commenter considers these costs outweigh the potentially higher utility bills that could result from the proposed rule, an d states that the utility sector has had adequate time to prepare. Commenter 18421 not es that data from several studies have shown links between methylmercury exposure, adult leukemia , and increased mortality rates (Salonen, J.T., K. Seppänen, T.A. Lakka, R. Salonen and G.A. Kaplan, Mercury accumulation and accelerated progression of carotid atherosclerosis: A population based prospective 4-year fo llow-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 ar eas heavily exposed to methyl mercury , 88Int. Arch. Occup. Environ. Health. 679, 679-88 (2007).

Response to Comment 4: The EPA agrees that exposure to fine part iculates and toxic air pollutants is associated with many adverse health effects and reduci ng 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 thatthe proposed implementation schedule is reasonable.

Comment 5 : Commenter 15002 expresses concern that even low levels of Hg exposure may be harmful because none of the studies of Hg toxicity have shown a threshold effect.

Response to Comment 5: The EPA agrees that there may be no threshold below which PM, Hg and other HAP have no effect and, in fact, the EPA uses a linear relationship in th e concentration-response functions for those pollutants.

Comment 6 : Commenter 19506 questions whether the benefits associated with the rule will actually be achieved. This commenter notes that the Hg emissions within Indiana have decreased by approximately 20% over the past 14 years, but concentrations of Hg from wet deposition sampling have only decreased by 7% with no apparent change in Hg concentrations within fish tissue in Indiana over th e past 22 years.

Response to Comment 6: The EPA disputes the commenter’s belief that this rule wi ll not reduce Hg levels in fish. The data used in support of this RIA do not reflect the comm enter’s assertion. The EPA notes that in some cases, Hg leve ls in fish can decrease quickly fo llowing reductions in Hg deposition. However, the time lag between reduced Hg deposition a nd reduced Hg levels in fish can vary greatly and is not accounted for in the RIA benefits analysis.

Comment 7 : Commenter 18500 states that the EPA descri bes the Hg problems without providing evidence that actual harm in the U.S. can be attr ibuted 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 contin ental United States indicate that total mercury deposition (wet and dry forms) reductions from this sector [EGUs] would be 24,000 μ g/m 2 (1.0% of total mercury deposition from all sources.

Response to Comment 7 : The EPA disagrees with the commenter’s assertion that meaningful benefits would not accrue to the public due to reductions in Hg from U.S. EGUs. Chapter 5 of the RIA presents a detailed analysis of the benefit to IQ in childr en. The SAB has supported the model used in the RIA analysis and states, “The support for the model of the relationship between IQ and methylmercury exposure comes from Axelrad and Bellinger (20 07) and from a whitepaper produced by Bellinger (2005).” (U.S. EPA-SAB, 2011) The analysis in the RIA is not intended as the basis of the rule. It is intended only to estimate the costs and benefits of the proposed rule and theref ore the IQ loss estimates presented in the RIA do not represent an attempt to afford more stringent thannecessary protection in this rule. Furthermore, the EPA does not believe that the benefits of this rule are insignificant. The benefits of reduction of Hg exposur e are underestimated on several counts 1) IQ is not the most sensitive indicator of neurological effects, 2) many health effects are unqua ntified, 3) benefits of reduction of other HAP are unquantified and 4) effects on ecosystems and wildlife are likewise unquantified. In addition, the co-benefits of reduci ng PM exposure are quite substantial and outwe igh 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 sens itive indicator of methylmercury’ s neurotoxicity in the populations studied. As noted in the TSD, in th e Faroe Island study the most sensitive indicators were in the domains of language (Boston Naming), atte ntion (continuous performance) and memory (California Verbal Learning Test), neuropsychological test s that are not subtests of IQ te sts and are not highly correlated with global IQ. In the Seychelles study, the Psyc homotor Development Index has been most sensitive measure and, while this is a component of the BaileyScales of Infant Development, it is not highly correlated with cognitive measures.”

Comment 8: Commenter 18023 states that the EPA’s analys 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 si gnificantly lower if lags in response to decreased Hg depositi on were taken into account. The commenter states that lags are known to occur in many if not most aquatic ecosystem s and that “a portion of the deposition is unlikely to reach the water at all.”

Response to Comment 8: The EPA acknowledges that MMAPS does not account for a time lag in ecosystem response to reductions in Hg emissions. Ecos ystems are highly variable in their response to reductions in Hg emissions. Due to limitations in data and methodology, the EPA was not able to quantify the effect of lag times on benefits.

2. Impacts on pregnant women and children.

Comment 9 : Many commenters (15002, 15160, 16682, 6640, 17676, 17408, 17766, 17844, 17854, 17875, 17922, 18421, 18432, 18435, 18436, 18932) express concern about the Hg levels found in children and women of childbearing age. Seve ral commenters (15002, 18932, 17875) express concern that a large number of wome n of childbearing age are expo sed to Hg at levels that lead to cord blood Hg levels that exceed the EPA reference dose. Co mmenters 15160 and 17408 identify potential health impacts of Hg exposure in childrenand developing fetuses, including sp eech, motor control, reading and writing as well as asthma, neurological damage, cancer, birth defects and other chronic health disorders. Commenter 15160 quotes data from the NC Department of Health and Human Services that estimate at least 11,811 babies are born annually with blood Hg levels that put th em 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 e nough Hg in their blood to pr esent a serious risk to a fetus during pregnancy.

Comment 10: Commenter 16640 explains that Hg accumulates in the environment and causes exposures long after being released from a power plant and bioaccumulates in humans along with arsenic, chromium and lead. The commenter quotes the American Academy of Pediatrics Policy Statement on Mercury which calls for, .”..efforts s hould 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 sta ndard 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 ma y 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 recentlypublished 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 show ing that over 60,000 children are born each year at risk for adverse neurological effects due to in utero exposure to methylmercury (see National Academy of Science and Nation Research Council, Toxicological Effects of Methylmercury , 2000, available on the Web at: http://www .nap.edu/openbook.php?record_id=9899&page=327 , 327).

 Commenter 18421 quotes a 2006 study by Dr. Kathr yn Mahaffey estimating that approximately 410,000 infants are born in the U.S. each year to mothers with blood Hg concentrations in excess of the EPA’s reference dose.

 Commenter 18421 quotes a recent study of women conducted in Durham, North Carolina that found 30% of the women participating in the study had at least 1 ug/L of Hg in their blood, approximately 2% had blood Hg levels above 3.5 ug/ L (level considered to be of concern during pregnancy), and 12.5% of women of Asian/Pacific Islander decent had blood Hg levels above 3.5 ug/L (see Miranda et al., Mercury Levels in an Urban Pregnant Population in Durham County, 8 North Carolina. Int. J. Envi ron. Res. Public Health 698, 698-712 (2011).

 Commenter 17408 quotes research c onducted at the Children’s Envi ronmental Health Sciences Center at the University of Wisconsin that de monstrates developmental exposures to Hg are sufficient to cause alternations to nerve f unction causing permanent damage that has been implicated in development of neurodegenerative diseases, such as Alzheimer’s and Parkinsons. This commenter also notes that recent research has shown that the toxic effects of Hg exposure are passed down from one generation to another resulting in deve lopmental and behavioral issues in the children and grandch ildren 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 s econd study evaluated 274 Korean children found an asso ciation between Hg concentra tions in urine and increased cholesterol, which is a risk factor for various forms of cardiovascular impacts (see Bose-O’Reilly et al, Mercury Exposure and Children’s Health , Curr Probl Pediatr Adolesc Health Care. 2010 September; 40(8): 186–215).

 Commenter 18432 quotes a recent study conducted in the City of Chester and Borough of Eddystone, Pennsylvania located in close proximity to coal- and oil-fired EGUs. This study shows that asthma rates among childre n in these communities exceed 36 %.

Other commenters (18421, 18541, 17408-14) identify instan ces of methylmercury poisoning, such as the outbreaks in Minamata, Japan where the mothers expos ed to elevated levels of methylmercury through consumption of contaminated fish typically did not exhibit any symptoms themse lves, but gave birth to children with severe neurological and birth defect s. 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 thatresearch is ongoing and that new findings are being published that shednew light on these ubiquitous a nd harmful pollutants. The EPA is aware of the poisoning events detailed in the comment s above and included descriptions of these events in the RIA for this rule.643 Comment 12 : Commenter 17681 questions whether this rule making 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 ea t 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 A ssessment 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 concentrations.

3. Impacts on IQ.

Comment 13 : Many commenters (15002, 15160, 17409, 17716, 17766, 18421, 18425, 18435, 19506, and 18932) note that Hg exposure has been associated with cognitive delays, learning disabilities, and lower IQ levels. Commenter 15002 notes that the EPA’s own analysis has shown that a child born to an African-American woman in 2016 who consumed fish at the 90th percentile w ould experience a loss of approximately 7.7 IQ points in the absence of the proposed ru le. Commenters 15160 and 18932 state that the North Carolina Department of Health and Human Services es timates that at more than 11,000 children per year are born in North Carolina with blood Hg levels thatplace them at risk for lifelong learning disabilities, fine motor and attention deficits, and lowered IQ. Commenters 17409 and 18435 identify recent studies such as the 2005 study by Transande that estimated between 300,000 and 600,000 children each year have cord blood Hg levels that are associat ed 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 c ognitive thinking, memory, attention, language, and fine motor and visual spatial skills have been seenin children exposed to methylmercury in the womb. This commenter stated that the EPA’s data show 10,543 children in Wisconsin were prenatally exposed to unsafe levels of Hg in 2005, resulting in a 0.10 point loss in IQ per child (a total IQ loss in Wisconsin of 1,026.2 points). This commenter also notes that the proposed Air Toxics Rule will result in nearly an 8.3% reduction in the average maternal daily Hg i ngestion from the 2005 baseline, which would result in more than 10% reduction in the average IQ loss pe r child and total IQ loss across Wisconsin due to reduced Hg exposure from in-state sources.

Response to Comment 13: The EPA agrees that in utero and early childhood exposure to methylmercury can lead to neurologi cal deficits in children and that the economic consequences of such deficits can be substantial.

Comment 14 : Commenter 15002 believes that the EPA unde restimated the impact of Hg on IQ by restricting the analysis to populations who cons ume self-caught fresh-water fish and omitting Hg exposures from other freshwater and saltwater fish. This commenter also stated there is no evidence to support the hypothesis that some low leve l of Hg exposure is entirely without effect and that if the effect of lead on IQ extrapolates to the Hg, then low le vel 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 th e concentration-response functions for those pollutants. We acknowledge the comm enter’s belief that the analysis 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 ch ildren, 244,000 annually, experiencing only a 2/1000 IQ point gain. Commenter 18498 questions whether the EPA’s IQ impacts are real, while commenters 17716 and 19506 argue that the benefits of the rule are insign ificant. Commenter19506 believes that the benefits to IQ levels would still be insignifi cant even if the EPA included the im pacts of commercially caught fresh and saltwater fish and self-caught saltwater fishin their analysis. Commenter 17681 argues that the aggregated benefit estimate of 0.00 209 IQ points lost is below the leve l that can be measured by an IQ
test.

Commenters 17716 and 17731 state that the EPA’s 0.11/ 0.10 average IQ loss per exposed child and 0.176 point for the most at risk group is much lower th an the EPA’s recent determ ination that a potential health risk occurs at 1-2 point IQ loss (T he NAAQS for Lead, 73 FR 66964 (Nov. 12, 2008)). The commenter states that the EPA declined to set a more stringent NAAQS for l ead because the estimated average IQ loss was lower than the 1-2 point range and argues that the proposed Hg limits are likely more stringent than needed because the current Hg emission levels from EGUs have been shown to result in a 0.176 point IQ loss for the most at risk children, which is well below the EPA-determined 1-2 point IQ loss level.

Commenter 17621 notes that in mone tizing the loss of IQ the EPA relied on the Bureau of Labor Statistics National Longitudi nal Survey of Youth (a national data set used to estimate the relationship between IQ and lifetime earnings). The commenter stat es that this survey does not contain a direct measure of IQ and is instead based on an Armed For ces Qualification Test (AFQ T) that has been scaled to estimate IQ. The commenter states that an earlyanalysis conducted at the request of the military reported a 0.77–0.80 correlation between AFQT scores and scores on a full-scale IQ test, the Wechsler Intelligence Scale for Children (Office Secretary of Defense, 1980) and that the EPA should take into consideration the relative loss of precision in scali ng between the AFQT and a fu ll-scale IQ test in light of the small changes in IQ presented inthe RIA IQ loss/reductions analysis.

Response to Comment 15: The EPA disagrees that the IQ impacts are not real and notes that the average reduction in IQ loss reported in the RIA do not reflect the greater than average impacts that reduced exposure would have at the tails of the distribution. The EPA uses a linear response model to predict IQ loss due to methylmercury exposure becau se there is no literature to date that shows a threshold below which no effect is observed. The SA B has supported the model used in the RIA analysis and states that “The support for the model of th e relationship between IQ and methylmercury exposure comes from Axelrad and Bellinger (2007) and from a whitepaper produced by Bellinger (2005). It was noted that the 1-2 point decrease re flects 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 dist ribution. This can result in a greater impact on those with IQ’s that are much lower or highe r than the mean.” (SAB Report available at: http://yosemite.epa.gov/sab/sabproduct .nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985 2578cb006bcb04!OpenDocument ) The analysis in the RIA is not intended as the basis of the rule. It is intended only to estimate the costs and benefits of the proposed rule and, theref ore, 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 be nefits of this rule are insignifican t. 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 ecosystems and wildlife are likewise unquantified. In addition the co-benefits of reducing PM exposure are quite substantial and outweigh all the benefits estimates for Hg.

The EPA agrees that the differences between th e AFQT and full-scale IQ tests are a source of uncertainty; however, the EPA believes that the effect on the estimates would be very small since the difference between the two tests is small.

Comment 16 : Several commenters (17681, 17769, 17807 and 18034) assert that the 1999 NHANES data is out of date. These commenters state that more recent data (such as Caldwell, et. al. (2009), International Journal of Hygi ene 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 NH ANES survey in the analysis of Hg effects on IQ in the benefits estimates for the RIA. The estimates were generated using data and models reviewed by the SAB as part of its re view of the TSD. (SAB report available at: http://yosemite.epa.gov/sab/sabproduct .nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985 2578cb006bcb04!OpenDocumeny )

Comment 17: Commenter 17621 states that with respect to the “hypothetical full scale IQ” this relatively small incremental change in IQ (0.18 on a 100-point IQ scal e) associated with a 1 ppm Hg increase in hair cannot itself be measured for anindividual, but must be estimated for the total population (through a series of analytical and exposure assumptions) to derive estimates at the national level (e.g., 510.8 IQ points saved in RIA, Table 5-7). The individual e ffects estimates for the “average” IQ loss per exposed child were defined out to the four th or fifth decimal place (see RIA, Tables 5-6 and 5-7) to indicate the potential (a nd relatively) small effects across the different exposure scenarios.

Response to Comment 17: Although the EPA disagrees that th e IQ results are too small to be important, the EPA acknowledges that IQ is not the most sensitive neurodevelopmental endpoint affected by methylmercury exposure. The EPA anal ysis of potential IQ loss from methylmercury exposure is for population effects, as is done for any quantitative estima te of risk. For precision, it is appropriate to use a large number of significant figures in calculation, if this is suppo rted by the data inputs. Upon completion of calculations, the estimat e is rounded to the number of significant figures reflective of the least precise term . In the case of IQ, based on the e ffect estimates from the underlying epidemiological studies and the exposure estimates, the level of precision is to 2 significant digits to the right of the decimal place.

The EPA’s independent SAB recommended that the IQ analyses be retained but de-emphasized in the documentation underlying the final regulation (U.S . EPA-SAB, 2011). The SAB concluded, “The Panel does not consider it appropriate for EPA to use IQ lo ss in the risk assessment and recommended that this aspect of the analysis be de-emphasized, moving it to an appendix where IQ loss is discussed along with other possible endpoints not included in the primary assessment. Although the Panel agreed that the concentration-response function for IQ loss used in the risk assessm ent is appropriate, and no better alternatives are available, IQ loss is not a sens itive response to methylme rcury and its use likely underestimates the impact of re ducing methylmercury in water bodi es.” (U.S. EPA-SAB, 2011) The EPA is following the SAB recommendation by deemphasizi ng 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, resultedin an “aggregated bene fit estimate” of 0.00209 IQ points lost, well below the level that can even be measured by an IQ test.

Response to Comment 18: The commenter is confusing a measur ement based on an IQ test and the response predicted by the linear model the EPA used to calculate IQ decrements caused by methylmercury exposure. The EPA uses a linear response model to predict IQ loss due to methylmercury exposure because there is no literature to date that shows a threshold below which no effect is observed. The EPA notes that the averag e reduction in IQ loss repor ted in the RIA does not reflect the greater than average impa cts that reduced exposure would have at the tails of the distribution. The SAB has supported the model used in the RIA analys is and states that “The support for the model of the relationship between IQ and methylmercury expos ure comes from Axelrad and Bellinger (2007) and from a whitepaper produced by Bellinger (2005).” (SAB Report available at: http://yosemite.epa.gov/sab/sabproduct .nsf/ea5d9a9b55cc319285256cbd005a472e/aaf67ae4dd19940985 2578cb006bcb04!OpenDocument ).

4. Impacts on Food.

Comment 19 : Many commenters (15002, 15160, 16682, 17405, 17408, 17409, 17254, 17683, 17766, 18043, 18421, 18425, 18435, 18932, 17676, 17679, 17922) support this rulemaking because it will reduce the levels of methylmercury in the U.S. di et. These commenters consid er the consumption of methymercury in contaminated fish to be a primar y health concern and they believe that fish and shellfish are the main sources of human methymercury exposure. Commenter 18932 states that, as of 2008, all 50 states had issued some type of fish cons umption advisory for Hg and 27 states had issued statewide Hg advisories for all bodies of water in the state. This comm enter is also co ncerned that the number of fish consumption advisories is incr easing, 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 a nd children not to consume any shark, swordfish, king mackerel, or tilefish, and to limit white albaco re tuna to one meal per week.

Response to Comment 19: The EPA agrees that ingestion of methylme rcury in fish is the main route of exposure in the American diet and that consumpti on of fish by pregnant women and children above the levels suggested by the advisories issued by the EP A and FDA can increase the risk of adverse health effects.

Comment 20 : Commenter 15160 reports that Hg from coal-f ired 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. Geol ogical Survey has shown that one in four fish contain Hg levels that exceed recommended EPA cr iteria and also notes that a recent issue of the Environmental Health Perspectives recreational anglers have been show n to have higher hair mercury levels. Commenter 17405 notes that hu man 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 sti ll in their mother’s womb have neurological and behavior problem s. Commenter 17676 notes that freque nt consumption of high-Hg fish has been associated with a number of harmful ef fects in adults, includi ng effects on neurologic, cardiovascular, and immune systems. Commenter 18932 believes that residents incoastal areas may be exposed to unsafe levels of methylmercury because th eir diets are especially hi gh in fish and shellfish. The commenter notes that a study in Alabama found extr emely high levels of Hg in hair samples from coastal residents who consume seaf ood and fish every week, indicati ng 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 from the Waccamaw River that are under a fish advisory and that bl ood samples taken from this populati on had average Hg blood levels of 7.5 ug/L, with approximately 40% of those tested having blood Hg leve ls greater than the recommended 3.5 ug/L level for women of childbearing age. Comm enter 17683 argues that families should be able to eat safe fish without having to wo rry about Hg in their bloodstreams a nd believes that regulation of Hg emissions from EGUs is overdue. Commenter 16682 states that the proposed rule can achieve reductions in Hg contamination in fish tissues quickly because levels of Hg in fish tissue quickly drop when the source is reduced. The commenter believes the proposed EPA standards will protect the public health and the environment.

Response to Comment 20: The EPA agrees that Hg from coal-fired power plants is a contributor to the levels of methylmercury in fish acr oss the country and that consumption of contaminated fish can lead to increased risk of adverse health effects. The EPA agrees that this rule will redu ce Hg levels in fish. The EPA agrees that, in some cases, Hg levels in fi sh can decrease quickly following reductions in Hg deposition. However, the time lag between reduced Hg deposition and reduced Hg levels in fish can vary greatly and is not accounted for in the RIA benefits analysis.

Comment 21 : Commenters 15002 and 17679 believe the EPA’s an alysis underestimates the impact of Hg emissions because the analysis focuses only onpopulations who consume self-caught fresh-water fish. Commenters argue that the EPA should include the contributi on to Hg exposures from other freshwater and saltwater fish, incl uding those most likely to contain large amounts of Hg (such as king mackerel, swordfish, large tuna, a nd tilefish). Commenter 17620 states th at the EPA’s analysis is of limited usefulness in assessing the health impacts ofthe proposed rules because it is based on selfcaught freshwater fish rather th an on commercially caught freshwater fish and saltwater fish that constitute the vast majority of the fish consumption in the U.S.

Response to Comment 21: The EPA agrees that the analysis presented in the RIA is an underestimate of the benefits of reduced Hg exposure in part due to the exclusion of some fish species especially saltwater fish. The EPA did not include marine fish due to data and methodological limitations.

Comment 22 : Some commenters (17702, 17732, 17620, 17751, 18023) believe that the EPA’s analysis is not based on best available science, and that the analysis is flawed and overestimates the impact of Hg emissions on human health. Commenter 17751 argues that the EPA failed to fully account for the role of dietary selenium’s protective effects against methylmerc ury toxicity. This commenter states that there is extensive literature on the beneficial role of dietary selenium and th at this literature shows that the binding affinity of Hg for selenium is up to a m illion times higher than for sulfur (Hg’s second best binding partner). In support of their argument, this commenter quotes work completed by an EPAfunded study showing that 97.5% of freshwater fish an alyzed for a Western U.S. survey have sufficient selenium to “potentially protect them and their consumers against Hg toxicity.”

Response to Comment 22: The EPA disagrees with the commenters that the best available science was not used to generate the estimates presented in the RIA. There are uncertainties in the analysis; one of which is the role of selenium. The EPA was not able to quantify this relationship within the benefits estimates due to data and methodol ogical limitations. There remains uncertainty with respect to the nature and magnitude of potential confounding between selenium and me thylmercury 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 pr egnancy should be approached as a case of multiple648 exposures to nutrients and to met hylmercury, with a complex and potentially interactive set of risks and benefits related to infant developm ent. The EPA SAB Mercury Review Pane l, 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 quan titative adjustment in h ealth endpoint measures.

Comment 23 : Commenters 17751 and 17681 argue that an anal ysis by Soon (See, Scientific Critique of EPA’s EGU MACT and NSPS Revisions, Willie Soon, PhD, June 2011) identifies a number of material errors in the EPA’s analysis of the health concer ns related to Hg emissi ons from coal-fired EGUs. Commenter 17751 notes that Soon’s anal ysis and various other peer-revie wed scientific studies indicate that regulatory management of Hg is likely impossible, because methylmercury bioaccumulation and methylation are driven by factors others than elemental Hg availabi lity. The commenter believes that Soon’s analysis clearly indicates that Hg emissions and impacts from sources other than those derived from EGUs greatly exceed the EGU emissions and impact and that even total elimination of all industrial emissions, inclusive of those from po wer plants, will not affect trace or even high methylmercury levels that have been found in fish tissue over century-long time periods. The commenter concludes that fish c onsumption advisories as an expos ure prevention strategy make more sense than emissions control strategies.

Response to Comment 23: The EPA disagrees that regul atory management of E GU 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 concentrations. The EPA notes that decisions related to Hg emission controls are distinct from decisions about fish consumption advisories, which are intended to pr ovide information to potential fish consumers. To the extent that regulations on EGU Hg emissions re duce concentrations of Hg in fi sh, specific fish consumption advisory information will reflect those changes in Hg concentrations.

Comment 24 : Commenter 17751 disagrees with the EPA’s st atement that reductions in power plant emissions will likely result in a re duction in Hg concentrations fo r fish in the ocean. Commenter 17751 states that much valid, peer-reviewed scientific re search has demonstrated that methylmercury in the world’s oceans is not controlledby 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 Ha waii have not changed over a pe riod during which anthropogenic Hg inputs in the region have increase d. The study’s authors suggest that these findings “provides prima facie evidence that this concentration is not resp onding to anthropogenic emi ssions irrespective of the mechanisms by which mercury is me thylated 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 ve ry 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 sour ces in 2005 will leave the levels of Hg in the world’s oceans virtually unchanged with a 0.0003 % reduction. Further, the commenter states that the primary source of exposure to methylmercury for most people living in the U.S. is through consumption of ocean fish and that exposure to methylmercury from freshwater consumption is statistically insignificant, as less than 0.05% of total fish and fish products consumed annually in the U.S. are freshwater fish (Food and Agriculture Organization of the United Nations, Trade in Fish and Fish Products, Fish Consumption, Fishers and FleetInformation, Tables CM 1.1 and CM 1.2).649 Response to Comment 24: The EPA disagrees that U.S. Hg emissi ons do not contribute to the global pool of Hg or affect Hg concentrations in ocean-going fish. The NAS in its 2009 report Global Sources of Local Pollution: An Assessment of Long-Range Tr ansport of Key Air Pollutants to and from the United States http://www.nap.edu/catalog/12743.htmlreport, explains that “Hg is truly a global pollutant, as it has the potential, once emitted from any source, to be transformed to different chemical forms, transported through the atmosphere, and depos ited long distances from the point of origin. Reservoirs that accumulate Hg include the atmosphere , the oceans, freshwater systems, soils, biota, and the cryosphere. Hence intercontinental transport is an important process that clearly affects U.S. exposures. Continued emissions will increase the amount of Hg in the global pool available for longrange transport and recycling am ong these reservoirs in the enviro nment.” Thus since the oceans are considered a sink for Hg pollution it is reasonable to c onclude that marine fish would be affected by that
exposure.

Hg accumulation in fish is dependent on many variab les including the age and weight of the fish. Additionally, Hg concentrations are variable across the oceans withmethylated Hg accounting “ for up to 29% of the total Hg in subsurface waters (a verage 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 pr oduction 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-caughtfreshwater fish (recreat ional fishers and their families). Although there are other routes of expos ure, including self-caught saltwater fish and commercially purchased fresh and salt water fish, these exposures are notevaluated because 1) for selfcaught saltwater fish, we are unable to estimate the re duction in fish tissue methylmercury that would be associated with reductions in Hg deposition from U. S. EGUs, and 2) for commercially-purchased ocean fish, it is very difficult to determine the source of th e methylmercury in those fish, and thus we could not attribute Hg levels to U.S. EGUs.

Comment 25 : Commenter17751 disagrees with the EPA asse ssment of a direct one-to-one proportional relationship between reductions inatmospheric Hg and methylmercury concentrations in fish. The commenter believes this to be one of several errors that grossly inflat e the EPA’s estimates of the human health benefits of the proposed controls on Hg emi ssions by EGUs and asserts that any health benefits from the EGU MACT would occur at times far remove d from the time at which reductions in emissions

occur.

Response to Comment 25: The EPA disagrees that the health benefits of Hg control are inflated. In fact the EPA believes that the estimates presented in the RIA are an underestimate because the EPA was not able to analyze the impacts using the most sens itive endpoints for human h ealth. According to the SAB’s review of the TSD for this ru le “The loss of IQ poi nts is likely to undere stimate 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 neurot oxicity 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 Verb al Learning Test), neurops ychological tests that are not subtests of IQ tests and are not highly co rrelated with global IQ. In the Seychelles study, the Psychomotor Development Index has been most sensit ive measure and, while this is a component of the Bailey Scales of Infant Development, it is no t highly correlated with cognitive measures.”

Further, the EPA disagrees that the proportionality assumed in the MMAPS model that relates the reduction in Hg deposition to reductions in fish tissue concentrations is inappr opriate. According to SAB650 “Since the Mercury Maps approach was develope d, several recent publications have supported the finding of a linear relationship between mercury loadi ng and accumulation in aqua tic biota (Orihel et al., 2007; Orihel et al., 2008; Harris et al., 2007). These st udies suggested that that mercury(II) deposited directly to aquatic ecosystems canbecome quickly available to bi ota and accumulated in fish, and reductions in atmospheric mercury deposition should l ead to decreases in methylmercury concentrations in biota. These results substantiate that the assumption of proportiona lity between air deposition changes and fish tissue methylmercury leve l changes is sufficiently robust fo r 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 s hould not have relied on Faroe Islands study because the Faroe Islanders receive Hg exposur e by atypical consumption of pilot whale meat contaminated by PCBs which has little relationship to fish consumption in the U.S. This commenter asserts that the EPA should have used data from th e Seychelles Islands study, because this study is the most relevant to the U.S., where there was no adve rse 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 th e 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 compari ng the seafood diet of Americans to Seychelles islanders. Commenter 17751 believes that the Seychelles Islands study is the right study to use as a basis for making a regulatory decisions and a ssessing 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 Fa roes was largely from consumption of pilot whale meat; exposure to PCBs was found in the portion of the population who also consume whale blubber. The lipophilic PCBs are found in the fat compartment of the pilot whales; methylmercury, by contrast, is bound covalently to protein in the whale meat.

Contemporary publications on data and analyses from the Seychelles Child Development Study of Methylmercury from Fish Consumption (SCDS) have reported methylmercury-related effects from testing of older children in their study cohort (e .g., van Wyngaarden et al. 2006; Strain et al., 2008.)

The EPA’s RfD for methylmercury is based on multiple endpoints from the three extant large studies of childhood effects of in utero exposure: Faroes, New Zealand, and an integrative measure including data from Seychelles. Documentation for the choices unde rlying 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: Methylmercury EPA-823-T-01-001, available at http://water.epa.gov/scitech/swguidance/standards/criteria/aqlife/po llutants/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 di sproportionate impact on low-income and651 subsistence populations, such as Nati ve Americans, Hispanics, and Locat ion subsistence fishers. Several commenters (17409, 18421, 18932) state that AfricanAmericans, Native populations, Latino communities, Asian Americans (e.g., Vietnamese in the gulf area), and other low income communities who fish recreationally are more likely to eat the fish they catch. Commente r 17766 states that African Americans and Hispanics eat more fish that are cont aminated with Hg than are their White counterparts because these groups eat fish to obt ain a source of high quality protein and catch the fish themselves to make up for economic inequities. This commenter quot es 2006 statistics showing that approximately 1.4 million African Americans and 1.3 million Hispanics we re 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 opti ons and therefore, tend to fish inurban areas where fish are most Hg-laden. Commenter 18932 quotes a 2005 survey of a nglers 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 h ealth advisories associated with the fish that they caught, but still ate the fish and shared them with at-ri sk members of their families, e.g., women of childbearing age. In the Tidewater Region of Virginia, the study showed that 91 % of those interviewed stat ed that they ate some of the fish they caught, 50 % of stated that having a fresh fish dinner was a very important motivation for fishing, and 19% stated that reducing the cost of food was a very important motivation for fishing.

Response to Comment 27: The EPA agrees that low-income and subsistence fishers are disproportionately affected by exposur e to methylmercury in fish due to their fish consumption patterns.

Comment 28: Commenter 17254 notes that African American s are disproportionately affected by Hg emissions because this population have a greater prevalence of kidne y disease and are more likely to reside in closer proximity to i ndustries that emit Hg and other ai r pollutants. Commenter 18435 provides maps of the southeastern states showing the proximity between concen trations of low income people, including both white and African-Americans, and the lo cation of coal-fired power plants and notes that the close proximity of these plants to waterways near their homes makes it more likely that fish from those waterways would make part of their diet . Commenter 15002 notes that the EPA’s analysis concluded that a child born to an African-American woman in 2016 who consumed fish at the 90th percentile would experience a loss of approximately 7.7 IQ points in the absence of the proposed rule. This commenter stated that this risk repres ents 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 cons umption 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 ar e subpopulations of Native Americans more susceptible to methylmercury exposure because of subsistence diets base d on fish and notes that the 1997 Mercury Study to Congress c oncludes that exposures among sp ecific subpopulations including anglers, Asian-Americans, and members of some Na tive American Tribes may be more than two-times greater than those experienced by the average U.S. population. However, this commenter believes that fish consumption is limited and occurs primarilyduring recreational activi ties. Commenter 17732 notes that a 2004 U.S. Fish & Wildlife report concluded th at the Navajo “can and should feel comfortable about consuming fish on a recreatio nal basis...” and further argues that the EPA should not assume that exposure to Hg and other HAP on Trib al lands are equal in comparison to exposures in the more densely populated metropolitan and urban areas where population and industrial grow th 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 re gional HAP so as to better understand the true public health and environmental impacts.652 Response to Comment 29: The EPA agrees that the analyses presented in the RIA focused on Native American populations with high-end fish consumption patterns spec ifically 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 ac knowledges that some Native American populations do not fit the criteria for subsistence level fishers.

6. Impacts on tourism and recreational fishing.

Comment 30 : Commenters 16122 and 17732 note that Hg contam ination of streams, rivers, and lakes threaten the economy of states and tribes that rely on fishing touris m. Quoting data published by the U.S. Department of Interior, Fi sh and Wildlife Service, commen ter 16122 notes that the Wisconsin Department of Natural Resources sells approximately1.5 million fishing license s and that the sales of these licenses, as well as of f ood, lodging, gasoline, and sporting equipment related to fishing adds approximately $2.1 billion to the Wisconsin economy a nd another $5 billion to the states of Illinois, Indiana, Michigan, Minnesota, and Ohio.

Response to Comment 30: The EPA agrees that Hg contamination of water bodies across the U.S. has led to fish consumption advisories for those water bodies that may have a nega tive effect on recreational fishing. The EPA also agrees that recreational fishing has a large economic impact in many states. The EPA further agrees that reducing Hg levels in fish should have benefi cial 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 num erous 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 speci es across the U.S. and recognizes th at research is ongoing in this area. The benefits to ecological health remain unquantif ied in the assessments for this rule due to data and methodological limitations. Because these bene fits are unquantified, the benefits assessment presented in the RIA for this rule is underestimated and conservative.

8. Benefits do not justify the rule.

Comment 32 : Multiple commenters (17716, 17682, 18484, 18500, 17904, 18020, 17754) argue that the benefits of the proposed rule do not justify the costs.

Response to Comment 32: The EPA disagrees that the benefits of the MATS rule do not justify the costs. As the analyses presented in the RIA for the rule show the benefits out weigh 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 an alysis shows, some populations including low-income African Americans and so me Native American populations may receive a disproportionate benefit, and the dist ributional 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 quantif ied including impacts on ecosystems and wildlife; especially fish, birds (both fish and insect eatin g), and mammals. Other HAP controlled by the MATS rule were likewise not quantified due to data, resource and methodologi cal limitations. Even if we were able to fully monetize the public h ealth benefits of reducing exposure to Hg and other HAP, it is likely that the PM benefits would conti nue 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 to tal monetized benefits exceed the estimated costs of the rule by a substantial margin, ev en when taking uncer tainty 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 by OMB Circ ular 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 cost s of your rulemaking and consider any important ancillary benefits and countervailing risks. An ancillary benefit is a favorable impact of the rule that is typically unrelat ed or secondary to the statutory purpose of the rulemaking (e.g., reduced refinery emissions due to more st ringent fuel economy standards for light trucks) while a countervailing risk is an adverse economic, health, safety, or envi ronmental consequence that occurs due to a rule and is not already accounted for in the direct cost of the rule (e.g., a dverse safety impacts from more stringent fuel-economy standards for light trucks).”

It is also directed by EPA’s Guidelines for Prepar ation of Economic Analyses (p. 11-2, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ):

“An economic analysis of regulatory or policy options should present al l identifiable costs and benefits that are incremental to the regulation or policy under consideration. These should include directly intended effects and associated costs, as we ll 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 feasib le. 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 th at the benefits of non-Hg HAP are not quantified means that no benef its exist for these reductions.

Response to Comment 33: This rule is expected to achieve im portant non-Hg HAP benefits. However, monetization of non-Hg HAP benefits is limited by currently availabl e data and methods. In summary, monetization of the benef its of reductions in can cer incidences requires se veral 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 methodol ogy and data limitations, we did not attempt to monetize the health benefits of reductions in HAP in th is analysis. Instead, we provide a qualitative analysis of the health effects associated with the HAP anticipated to be reduced by these rules. The EPA disagrees that the health be nefits of non-Hg HAP coul d 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, a nd our limited ability to monetize thes e benefits does not indicate that they are non-existent or less important.

Our treatment of these benefits follows guidanc e 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 pref erable to qualitative descriptions of benefits and costs because they help decision makers unders tand the magnitudes of the effects of alternative actions. However, some important benefits and costs (e.g., privacy protection) may be inherently too difficult to quantify or monetize given current data and me thods. You should carry out a careful evaluation of non-quantified benefits and co sts. Some authorities refer to these non-monetized and non-quantified effects as “intangible.”

It is also in line with EPA’s Guidelines for Preparing Economic Analyses (p. 11-3, available at: http://yosemite.epa.gov/ee/epa/ eed.nsf/pages/Guidelines.html ).

“Benefits and costs that ca nnot 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 im pacts 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 emissi ons 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 emi ssion changes expected as a result of MATS are additional emission reductions beyond those regulations (e.g., CSAPR) that were considered to be part of the baseline.

11. U.S. EGU mercury emissions are a sm all 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 contri bution from U.S. sources is very small.

Response to Comment 35: The EPA disagrees that controlling Hg em issions from U.S. EGUs is not a cost-effective method of reducing Hg emissions. The EPA agrees with NACAA (public comment EPAHQ-OAR-2009-0234-17620-A1) that “while a global merc ury 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 lo cal and regional environm ent shortly after those reductions are implemented. Indee d, ongoing monitoring efforts in a number of states indicate that mercury levels in fish and other biota have fallen as those states have begun to address sources of mercury pollution.”

In November, 2002, an enhanced air m onitoring site was established in St eubenville, Ohio to investigate source-receptor relationships for Hg deposition in eastern Ohio. The site ove rlooking the Ohio River655 was in close proximity to several anthropogenic poi nt sources, including E GUs. 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 por tion of the Hg deposited in the im mediate vicinity of local EGUs was directly attributed to those lo cal sources. The University of Michig an researchers concluded that “it has become evident that near-field impact of coal fired utility boilers on Hg deposition is significant and underestimated by the models that have been utilized in previous po licy decision making.”(Keeler et al, 2006) Similarly, wet deposition data collected throughout the Great Lakes over the past decade have demonstrated distinct regional vari ability that undercuts any suggesti on that local Hg emission efforts are of no value. Precipitation samples collected in southeastern Michigan s howed a 25 to 35% increase in the Hg concentration between urban sites in De troit and a rural site 40 miles to the east. This phenomenon is not limited to the northern part of th e country. Studies in south Florida revealed that the spatial and temporal patterns of wet deposited Hg were also strongly infl uenced by local sources. National data show similar variability in deposition ra tes; Hg deposition rates at tributable 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 acid ification of ecosystems.

Comment 36 : Commenter 18487 points out that reducing emi ssions of acid gases will benefit acid sensitive ecosystems and the fish and w ildlife that depend on those ecosystems.

Response to Comment 36: The EPA agrees that acidification poses a significant risk of adverse effects to fish and wildlife in aquatic and terrestrial ec osystems. Please refer to the EPA’s recent Risk and Exposure Assessment for Review of the Secondary Na tional 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 methylati on in acidified systems. To the extent that acid gases contribute to acidification, the EPA agrees that those gases pose a risk for acidification of ecosystems. Howe ver, due to data and methodologica l limitations, the EPA was not able to quantify those risks and benefits.656 6M - Impacts and Costs: Air quality co-benefits modeling

Commenters: 17627, 17752, 19686

Comment 1: Commenter 17627 states that the 2005 base year di d not include emission reductions that have already occurred as a result of many enforc eable federal and state pr ograms. 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 estima tes 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 fr om 2005. Therefore, to achieve reasonably accurate estimates of benefits, th e most important feature of EPA’s approach is having an accurate projection from 2005 to 2016, so that the emissions reductions and economic downturn referenced by the commenter are included in the future base and therefore not included as part of the benefits of the rule. Th ese impacts are included in both th e 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 a nd 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 update d to reflect the comment process on the CSAPR, for which a number eastern states provided detailed updates to the EPA’s emissions projection assumptions for EGU, non-EGU point, stationaryarea, and nonroad mobile sources . All of these comments were included in the projections used for the final rule . Furthermore, the comment process for this rule provided an opportunity to make the EPA aware of a ny other projection changes that were needed for improving our benefits estimates. In the rare instances where such speci fic comments were made for this rule, the EPA included those reductions in the fina l 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 upda tes to point sources included the incorporation of all known controls in the 2016 baseline, and th e inclusion of non-EGU pl ant closures, federally enforceable emissions reductions, and consen t decrees that have happened since 2005.

Comment 2: Commenter 17752 describes errors found in the IPM file pertaining to two of the commenter’s units which are affected by the proposed rule. The commenter explains that the Big Stone Plant was shown to have an on-line scrubber in 2011, which it does not. The file also showed an ESP, while the plant has only a fabric fi lter 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 th is observation and notes that IPM modeling for the final rule has been updated to reflect these corrections.

Comment 3: Commenter 19686 states that the rule’s technical analysis fails to account for Tribes with respect to monitoring and modeling. The EPA used the Community Multi-scale Air Quality (CMAQ) model to estimate the rule’s reduction in the inciden ce of adverse health effects, as well as the estimated economic value of the reduction in th e incidence of adverse health eff ects. The grid sizes used fail to account for the considerable variation in the land size of individual Tribes, which can be anywhere between one to thousands of acres. The smallest lands, because of their size, may be wholly or partially657 located in areas that heavily influence airflow unlike surrounding jurisdictions ( e.g., valleys, mountains), meaning that CMAQ grid sizes of 12 km and greater may have a hard time modeling the true effects on local air quality for Tribes. To predict the rule’s impact on Tribes more accurately, the commenter recommends that the EPA redo its CMAQ analysis and use modeling grids no greater than 4 km. Further, the EPA should use similar size grids for a ny 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 da ta to rural areas.” Most of Indian Country is located in rural areas, meaning that their lands were unrepresented by the modeling results. Tribal lands located in urban areas are also largely unrepresented since they possess few monitors to discern the presence and amount of pollu tants covered by the rule. Hence, the EPA lacks the data to make any accurate conclusions about the ru le’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 lo wer bound estimate on EGU contributio n as higher impacts using finer grid resolution are possible. The EPA also agrees w ith the commenter that there may be some variation in estimated air quality within a 12 km grid cell, but we believe the air quality estimates at 12 km generally reflect the area within the grid cell. The EPA would like to poi nt out that the application of a photochemical model at 12 km grid resolution for the entire continental U.S. is more robust in terms of grid resolution and scale that anything published inliterature and represen ts the most advanced modeling platform used for a national Hg deposition assessment.658 6N - Impacts/Costs: Other/Miscellaneous

Commenters : 15002, 15160, 17620, 17884, 17973, 19214

Comment 1: Commenter 15002 recommends the EPA implement a 5-year review cycle for Hg and other HAP, similar to what is mandated by the CAA for the NAAQS. The commenter notes that emissions will plateau at current levels due to population increases balanced out by improved emission controls that become more effective and less expens ive. 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 no tes that, while a regular 5-year review schedule is mandated by the CAA for the NAAQS, the schedule prescribed by the CAA for review of emission standards for Hg and other HAP calls for a review every 8 years. S ee 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 in corporated as appropriate.

Comment 2 : Commenter 17620 asks that the final rule reac h a balance between pr otecting public health and avoiding unnecessary costs on the regulated co mmunity. The commenter notes that the EPA has projected substantial reduc tions in the emissions of Hg, HCl, fine PM and SO 2 , all of which are needed to protect public health. The comme nter further notes that industry testing supports emission standards of the stringency proposed and the technology to meet the proposed standards has been in use for 10 to 40 years.

Response to Comment 2: The EPA agrees with the commenter’s assessment that the rule achieves important reductions in the emissions of severa l air pollutants without being unduly burdensome.

Comment 3 : Commenter 15160 sees the proposed rule as animportant step toward ensuring that the living and working environments of all Carolinians are reasonably safe and encourages the EPA to maintain the same level of strictness in the final rule.

Response to Comment 3: The EPA thanks the commenter for their support.

Comment 4: Commenter 17884 sees the proposed rule as ha ving little, if any, health benefit and believes it may endanger public health and welfare by reducing the disposable in come of people for the necessities of life.

Response to Comment 4: The EPA does not agree with the commen ter’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 co mmenter 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 e ffects of the rule. (This is sometim es 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 th e health-health tradeoffs of regulatory action to control air pollution. Claims about health-health trad e-offs rely on questionabl e applications of crosssectional data and ignore key factor s that may influence changes in popul ation health risks. Additionally, marginal decreases in household income caused by the pass-through cost s of the regulation are unlikely to cause large changes in any singl e aspect of household spending, such as health care. These analyses also fail to consider that household income may increa se if individuals are able to work (or work more)659 as a result of improved health, offsetting some or a ll of the pass-through costs of the rule. For these and other reasons, the EPA’s science and economic peer review panels have cons istently advised against incorporating alleged health-health trade-offs in EPA analyses of regulatory effects.

Comment 5: Commenter 17973 states that the fleet of coal-fired EGUs in the U.S. is aged and inefficient, having operated in most cases without modern controls for 35 years or more. The commenter considers the proposed rule to be overdue, as all other major source categories of HAP have implemented controls under MACT requirements already. The commenter believes that a wellcontrolled EGU equipped with a baghouse, 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 reduc tions beyond present levels are needed for the U.S. to fulfill the mission under the National Pa rk 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 quantif ied for this regulation.

Comment 7: Commenter 19686 states that to better assess the impact of the rule and any forthcoming actions by the EPA, they recommend that the EPA provide Tribes with an appropriate number of monitors of various types to es tablish 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 a ppropriate, as monitoring resources are typically supported with state and tribal air grants.

Comment 8: Commenter 16849 states that even under revi sed averaging periods, TRONA and DSI is not a viable option, as is incorrect ly stated by the EPA (“IPM Parsed Results - Policy Case,” Unplanned DSI Installations by 2015 includes Asbury: 2076_B_1).

Response to Comment 8: The EPA believes that DSI has the potenti al 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 applicab le for units burning lower-sulfur content coal (including, potentiall y, 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 propo sed rule. According to the commenter, the proposed rule will have little, if any, health benefit and will endanger the public and welfare by reducing the disposable income people will have for the necessities of life. Because the purpose of th e CAA is to protect public health and welfare, failure to consider the negative hea lth consequences is arbi trary and capricious and otherwise not in ac cordance with law. See AT&T Corp. v. Iowa Utils. Bd. , 525 U.S. 366, 388 (1999) (invalidating agency interpretation not “rationally related to the goals” of the governing statute).

Response to Comment 9: The EPA disagrees with the commenter th at our interpretation of the statute is in error for the reasons set fo rth in the proposed rule and this final action. The EPA also does not agree with the commenter’s assertion that the rule w ill 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 th eory 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-hea lth tradeoff.”) The EPA also disagrees with this claim and notes that there are a number of conceptual and empirica l problems with any attempt to quantify the health-health tradeoffs of regulatory action to control ai r pollution. Claims about healthhealth trade-offs rely on questionable applications of cross-sectional data a nd ignore key factors that may influence changes in population health risks. A dditionally, marginal decreases in household income caused by the pass-through costs of the regulation are unlikely to cause large changes in any single aspect of household spending, such as health care. These analyses al so fail to consider that household income may increase if individuals are able to wo rk (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 consistentlyadvised against incorporating alleged healthhealth trade-offs in EPA analyses of regulatory effects.661 CHAPTER 7: STATUTORY AND EXECUTIVE ORDERS

7A - Executive Order 12866, Regulatory Pla nning and Review and Executive Order 13563, Improving Regulation a nd Regulatory Review

Commenters : 17638, 17648, 17681, 17702, 17713, 17715, 17721, 17734, 17751, 17757, 17758, 17768, 17806, 17842, 17833, 17868, 17884, 17911, 17917, 17919, 18016, 18018, 18446, 18486, 19042, 19114

1. The EPA did not comply with EO 13563.

Numerous commenters (17638, 17681, 17702, 17713, 17715, 17721, 17751, 17757, 17758, 17842, 17868, 17884, 17911, 17917, 17919, 18106, 18018, 18446, 18486, 19042, 19114) state that the EPA failed to comply with th e requirements of EO 13563.

Comment 1: Multiple commenters (17638, 17713, 17884, 18446, 18486, and 19114) state that the EPA failed to consider the cumulative impacts of the proposed rules as required by EO 12866 and EO 13563. Commenter 17638 states the regulation’s benefits do notjustify its costs nor impose the least burden on society taking into the costs of cumulative regul ations. Commenter 17884 believes the EPA is producing a series of rule-by-rule RIAs that narrowly define what impacts the spec ific rule at issue has, which has the result of minimizing the impact of any one rule and avoiding taking respons ibility for the actions utilities are taking in anticipation of the EPA’s en tire regulatory agenda. Co mmenter 18446 cites a report by the National Economic Research Associates (NER A) 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 th e rule until the agency conducts a cumulative impact analysis.

Commenter 17715 suggests the proposed rule does not take into account harmonization with other regulations, such as the effect of this rule coupled with futu re requirements surrounding Coal Combustion Residuals (CCR), re vised NAAQS, regulations surr ounding cooling water intake impingement and entrainment (316(b)) and GHG regulati ons that will also be affecting sources in upcoming years.

Commenter 17734 states that there ar e a large number of related rulemaking efforts coming out in the near term, including revisi ons 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 res ources to allocate in order to cost-effectively achieve compliance. The commenter suggests that if the ag ency can coordinate, reconcile, and harmonize the overlapping regulatory requireme nts, it will help to lessen these difficulties.

Commenter 17757 notes that the EPA analysis failed to take into account the impact of each of the CSAPR and the proposed EGU air toxics rule on the common objective of appropriate and reasonable emissions control.

Commenter 17842 states that while the rule estimates costs of complianc e and anticipated retirements, it is the collective impact of all em ission regulations affecting EGUs th at 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 re sulting uncertainty pla ces utilities in a very disagreeable position in te rms 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 ot hers affected. The commenter beli eves these rules neither promote economic growth, competitiveness nor job creation.

Commenter 17919 states the EPA should address the ti meframe and content of overlapping rules for the power sector, beginning with U tility MACT. The commenter believe s rules should impose the “least burden,” taking into account the multiple and overlapp ing rules facing the power sector. Where the EPA has the capacity for flexibility, such as in the co ntrol of non-Hg HAP, subcategorization, determination of the MACT floor, and other areas, the commen ter believes the EPA should do so. The commenter notes that numerous rules promulgated or expected to be promulgated in 2010-2012, in conjunction with Utility MACT, means that the genera ting units subject to these rules w ould either have to undertake the installation of extensive retrofits on an unrealistic timeframe or else shutdown entirely. The commenter suggests that the EPA extend the co mpliance period in the proposed rule to allow for such retrofits.

Commenters 17806 and 17833 state that the proposed ru le, in addition to the NSPS for GHG emissions, new regulations for handling coal ash, and new re visions to the ozone and PM NAAQS, will have a negative impact on the economies of many regions. Commenters add that th e EPA has not described how the regulations interrelate or whether they have a collective benefit. Commenter requests that the agency withdraw all the pr oposals mentioned and conduct a cumulative impact assessment.

Response to Comment 1: The Agency did not prepare a cumulati ve impact analysis to accompany the rule for the following reasons: 1) the various EO requirements that the Agency must comply with require us to estimate impacts specif ic to this rule; 2) de cision 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 thos e from a cumulative impact analysis. A cumulative impact analysis lumps several regulations together and can potentially mask a high-cost/low benefit regulation among other rules that may have large net benefits. By an alyzing 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 c onsider cumulative impacts of the regulation. The inclusion of CSAPR and other regulat ory actions (including federal, stat e, and local actions) in the IPM base case reflects the level of controls that are likely to be in pl ace 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 require ments for air emissions, while isolating the incremental impacts of MATS. These results are presente d in Chapter 3 of the RIA.

Additionally, the Agency does reflec t 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/su mmaryreport.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 di rect 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 Am endments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by passage of the 1990 Amendments. The wi de margin by which benefits exceed costs combined with extensive uncertainty analysis suggest it is very unlikely this result would be reversed using any reasonable alternative assump tions 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 ar eas and assist other areas with atta ining 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 analytic al objectives of a NAAQS RIA and one for a rule such as MATS. The NAAQS RIAs illustrate the poten tial costs and benefits of attaining a new air quality standard nationwide based on an array of emission control stra tegies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, th e control strategies that states may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directlyresult 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 cost s of control and emission reductions. Some costs and benefits estimated in the fina l 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 cumulative costs and benefits.

Comment 2: Commenter 19042 suggests the EPA failed to follow the guidelines in EO 13563 for assessing the impact of the propos ed regulation on federal agenci es 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 th e federal government’s admi nistrative costs. The commenter believes that if the EPA’s Utility MACT st andards result in higher electricity costs for itself and other federal agencies, there by making it more difficult to admini ster 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 requi res the analysis of government administrative costs or savings when those effects are expected to be significant. The EPA’s analysis of costs does include dir ect costs to government-owned facili ties that are subject to regulation under the rule. The agency does not believe that the indirect administrative co sts are large enough to have a significant impact.

Comment 3: Commenters 17702 and 18018 believe the EPA has an obligation to maintain consistency in its regulations when addressi ng court vacaturs and remands of CAIR and CAMR. The commenters also state the EPA increased the stringency of both the Clean Air Transport Rule (CATR) and the proposed utility air toxic rule beyond what is necessary to address the deficiencies identified by the Courts.

Response to Comment 3: The EPA disagrees with the commenter s’ assertions concerning CAMR and notes that comments on CAIR are outsi de the scope of this action. The D.C. Circuit Court vacated, not remanded, CAMR because the Court determined that the EPA had not properly delisted EGUs from the section 112 list of sources and the EPA did not have the authority to regula te HAP emissions under section 111 for source categor ies listed under section 112. ( New Jersey v. EPA , 517 F.3d 574, 583 (D.C. Cir. 2008).) The EPA is finalizing standards fo r 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 wi th DOE, FERC, the National Electric Reliability Council (NERC), Public Utility Commissions (P UCs), and Regional Transmission Organizations (RTOs).

Response to Comment 4: The EPA is separately working on those responses. Status of the EPA responses to Congressional inquiry does not affect the EPA’s author ity or responsibility under section 112 to issue final emission standards for EGUs.

Comment 5: Several commenters (17868, 17758, 17911, 18106) stat e the EPA has not proposed any of the regulatory options to reduce burdens and mainta in flexibility in order to comply with the EO requirements to consider flexible approaches. Co mmenter 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 contradi ction 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 perm itted by the statute to reduce emissions and achieve compliance in the most cost-effective and efficien t manner possible for the particular EGU, while assuring that significant reductions in emissions and th e 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 dem onstrate compliance, (4) the availability of surrogates to determine compliance, (5) the choice for existing sources to comply with either input-based or output-based emission limitations, (6) the statutory eligibility for a 1-year extension to comply with the rule in the event that the additional time is necessary for instal lation of controls, consis tent with the statutory requirements of section 112(i)(3), and (7) the provis ion of an affirmative de fense to any malfunction.

Comment 6: Commenter 17751 states the EPA has not demonstr ated that it has cons idered the relative costs of achieving the benefits a ssociated with the proposed regulat ion affecting the EGU sector by means of alternative regulatory strategies.

Response to Comment 6: Although the proposed rule did not incl ude a full quantitative analysis of a more and less stringent regul atory alternative, a quantitative analysis of costs was included in the MACT Floor TSD to illustrate the feasibi lity of the beyond-the-floor standard for lignite. The analysis of the floor for all subcategories constitutes a less st ringent alternative than the proposed standard. Additionally, the proposal includes a qua litative discussion of a number of alternative approaches such as a health-based standard and alternative subcategorization.

Comment 7: Commenter 17721 suggests that the proposed ru le would negatively impact innovation if ACI technology remains the only EPA-endorsed Hg control technology. The commenter suggests that the proposed rule include a variety of Hg control systems, including DLPS technology.

Response to Comment 7: The commenter is incorrect – the EPA does not endorse any specific type of pollution control technology, nor doe s it mandate or prohibit technologi es. The MACT standard is an emission-based standard that is established by cons idering the maximum emission reductions currently achieved by existing EGUs. Individual facilities are free to use whatev er technology they wish in order to achieve this standard. Contrary to the commente r’s belief, the MACT standa rd 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 expl ain how the proposed rule utilizes the best techniques to accurately quantify present and future benefits. Commenter 17681 states that the EPA must explain how the proposed rule ensures the objectivity of scientif ic and technological information and processes to support the action.

Response to Comment 8: The EPA recognizes its obligations unde r EO 13563 to use the best available techniques to accurately quantify both present and future costs and benefits as well as to ensure the objectivity of scientific and technol ogical information and processes us ed in its analysis. As such, the EPA relies upon guidance from its independent scientif ic and economic review panels and employs peer reviewed processes and technical literature in co mpleting its analyses. All necessary documentation is provided in the RIA and technical support materials accompanying the final rule.

Comment 9: Commenter 17868 acknowledges that the EPA ha s discretion in developing utility air toxics under section 112, and that EO 13653 provides important guidance as to use of this discretion. The commenter believes the projected cost for the rule is significant while providing only minimal benefits from the direct reduction of HAP. The commenter notes that 99.99% of the benefits from the proposed rule will result from co-benefits associated with estimated reductions of 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 othe r CAA requirements in progress.

Response to Comment 9: The EPA disagrees with the commenter’s assertion that th e benefits achieved from this rule are expected to occur from th e implementation of other CAA requirements. In implementing rules such as the MATS, emission c ontrols may lead to reductions in ambient PM 2.5 and ozone below the NAAQS for PM and ozone in some ar eas and assist other areas with atta ining 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 analytic al objectives of a NAAQS RIA and one for a rule such as MATS. The NAAQS RIAs illustrate the poten tial costs and benefits of attaining a new air quality standard nationwide based on an array of emission control stra tegies for different sources. In short, NAAQS RIAs hypothesize, but do not predict, th e control strategies that States may choose to enact when implementing a NAAQS. The setting of a NAAQS does not directlyresult 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 cost s of control and emission reductions. Some costs and benefits estimated in this RI A account for the same air quality improvements as estimated in the illustrative PM 2.5 and ozone NAAQS RIA, but these e ffects are only counted once when considering cumulative costs and be nefits. The EPA believes that to properly understand the impacts of this rule, it is equally important to identify the co-ben efits from reductions in PM and ozone as it is to identify the direct benefits re sulting 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 N ovember finalization date precludes the EPA from meaningfu lly understanding and responding to co mments that will be provided. The commenter believes if the EPA does not appropriate ly change this schedule, the EPA’s actions are (and will be) arbitrary and capricious, and a violat ion of the Administrative Procedure Act. At a minimum, the commenter suggest the EPA must e xplain how its actions are consistent ·with the ‘‘‘General Principles” and “Public Part icipation” directives of EO 13563.666 Response to Comment 10: The EPA is mindful both of its oblig ation to provide an opportunity for public comment and of its obl igation to proceed with this rule in a timely manner, but disagrees with the commenter’s assertion that it has ac ted arbitrarily or capriciously withregard to these obligations. The agency is obligated to finalize the MATS by Decemb er 16, 2011, consistent with a consent decree. This date reflects a 30-day extension the EPA obtained from the origin al November 16, 2011 deadline. The proposed rule was signed on March 16, 2011 and the public comment period was scheduled to close on July 5, 2011. The EPA extended the comment period an additional 30 days to close August 4, 2011. Agency staff began reviewing comments and identifyi ng key issues prior to th e close of the comment period. Additionally, the EPA held three public information sessions in Chicago, Atlanta and Philadelphia during the month of May where the public was able to provide comment on the rule. The EPA believes that its approach to public comments meets or exceeds both the letter and spirit of the EO’s guidance on publ ic participation.

Comment 11: Commenter 17702 believes the EPA increasedthe stringency of the proposed rule without regard to the lack of additional health benef its that might accrue or a dditional costs that will be incurred by the public. The commenter instead states that the EPA should use its discretion to minimize the cost of the rule while still providing for safety of the public.

Response to Comment 11: The EPA disagrees with the commenter and notes that under the CAA, the agency has limited discretion in setting a MACT floor standard. The MACT floor standard is a technology-based standard based on the performan ce of existing sources in the regulated source category. It provides the minimum le vel of HAP emission control requi red 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 sour ces is the average level of HAP emission control achieved by the top 12% of sources each category or subcat egory 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 onl y consider economic, envi ronmental, and health impacts when setting a standard more stringen t than the MACT floor. Although the EPA explored several alternatives for standards beyond the MACT floor, ultimately, only the low rank virgin coal 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 ec onomic and job growth. The commenter believes the EPA also complied with the other requirements of the EO by involving the public, employing where it can flexible approaches such as averaging, establ ishing performance based st andards, relying on sound objective science, requiring coordi nation 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 lega l authority to reinterpret “appropriate” to allow for the consideration of costs and benefits, as well as the statutory au thority 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 maximi ze net benefits unless a statute requ ires another regulatory approach.667 Comment 14: Commenter 17842 encourages the EPA to cons ider the overall obj ective of section 112(n) to reduce Hg emissions while considering th e call of EO 13563 to “propose or adopt a regulation only upon a reasoned determination that its benefits justify its costs.”

Response to Comments 13 - 14: The Executive Orders supplement but cannot modify or diminish statutory requirements. The EPA believes the agency ’s interpretations of s ection 112(n)(1) and 112(d) constitute reasonable interpretations of the statute. While we agree that the cited executive orders direct the EPA to maximize benefits and minimize costs to re gulated industries, we believe that we have done so within the constraints imposed by the CAA.668 7B - Paperwork Reduction Act

No comments were received sp ecifically on the Paperwork Reducti on 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, 17689, 17712, 17805, 17817, 17868, 17885, 17911, 18032, 19094, 19121, 8443

1. General.

Comment 1: Commenters 16705 and 17400 express concern thatsmaller utilities and those in rural areas will be unable to get vendors to respond to their requests for proposals, since they will be able to make more money servi ng 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 co mpliance times for the proposed rule. The EPA has provided pursuant to section 112( i)(3)(A) the maximum 3-year peri od for sources to come into compliance. Sources may also seek a 1-year exte nsion of the compliance period from their Title V permitting authority if the source needs that time to install controls. CAA sect ion 112(i)(3)(B). If the situation described by commenters (i.e ., where smaller utilities and those in rural ar eas are less able to get vendor responses to requests fo r proposals than larger utilities) results inthe 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. Commenters reference the Report of the SBAR Panel, citing the following text: “SERs stated that they do not believe they were provided the opportunity for effectiv e participation in the Federal regulatory process as required by SBREFA.”

Comment 3: Commenter 17608 believes the EPA’s formal SBAR Panel notification and subsequent information provided by the EPA to the panel did not include information on the potential impacts of the rule as required by section 609(b)(1). The commenter states that such information was not provided until the EPA’s submission to OMB/OIRA under EO 12866, af ter consultation with the SERs was complete.

Comment 4: Several commenters (8443, 17608, 17868) sugges t that the EPA’s rulemaking schedule put pressure on the SBAR Panel through the abbreviated preparati on for the panel. Commenters 8443 and 17868 note that only one panel m eeting was provided and after that meeting, Panel members were given a mere 14 days to prepare written comments on an incredibly complex topic. Commenters note that the lack of a pre-panel consu ltation 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 st ate the EPA did not present a proposed regulatory approach with sufficient detail for SERs to identi fy potential economic effects of suggest specific regulatory alternatives; it had only presented them with broad discussions and raw data upon which the EPA would eventually make disc retionary judgments. Commenters do not believe that the EPA’s670 response to the SBAR Panel concerns regarding the deficiencies in th e process relieves the EPA of its obligations under section 609(b).

Comment 6: Several commenters (8443, 17608, 17911) express c oncerns that the EPA did not provide participants more than cursory background informa tion on which to base their comments. Commenter 17608 states that the EPA did not pr ovide deliberative materials, in cluding draft proposed rules or discussions of regulatory alternatives, to the SB AR Panel members. The commenter believes such materials could have guided the Pane l’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 stat utory obligation to recommend less burdensome alternat ives. The commenter suggests the EPA Panel members declined to make recommendations that went further than co nsideration or investigat ion of broad regulatory alternatives, with the exception of those recomm endations 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 specif ic regulatory decisions an d the impacts of those decisions on particular small entitie s 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 Admi nistration (SBA), or OMB, ignoring concerns expressed by the SER panelists. Commenter 17868 not es specifically that th e EPA did not respond regarding the 3-year compliance deadline and by not acting upon OMB’ s suggestions to meet again before the rule was proposed.

Comment 9: Commenter 19121 believes the EPA failed to convene required meetings and hearings with affected parties as required by law for small business entities.

Comment 10: Commenter 8443 notes that public power account s for about 16% of all kW-hr sales to retail electricity consumers, approximately 46% of the MW-hr of electricity produced by public power systems are generated using coal, an d more than 90% of public power ut ility systems meet the definition and qualify as small businesses under the SBRE FA, giving more importance to the Panel.

Response to Comments 2 - 10: The RFA requires that panels co llect 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 requi rements of the proposed rule;

- duplication, overlap or conflict between the proposed rule and other federal rules; and

- alternatives to the proposed rule that accomplis h the stated statutory objectives and minimize any significant economic impact on small entities.

The RFA does not require a covered agency to creat e or assemble information for SERs or for the government panel members. Although section 609(b )(4) requires that the government panel members review any material the covered agency has prepared in connecti on with the RFA, the law does not prescribe the materials to be review ed. The EPA’s policy, as reflected in its RFA guidance, is to provide671 as much information as possible, given time and res ource constraints, to enable an informed panel discussion. In this rulemaking, because of a court-or dered deadline, the EPA was unable to hold a prepanel meeting but still provided SERs with the inform ation available at the time, held a standard Panel Outreach meeting to collect verbal advice and reco mmendations from SERs, and provided the standard 14-day written comment period to SERs. The EPA r eceived substantial input from the SERs, and the Panel report describes recommenda tions made by the Panel on m easures 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 th e 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 re quirements of the CAA.

Comment 12: Commenter 17868 is concerned about the abil ity of small entities or nonprofit utilities such as those owned and/or operate d 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 ec onomic conditions they have constraints on their ability to raise capital for the cons truction of control projects and to acquire the necessary resources in order to meet a 3-year compliance deadline.

Response to Comment 12: The preamble to the proposed ru le (76 FR 25054, May 3, 2011) provides a detailed discussion of how the EPA determined co mpliance times for the proposed rule. The EPA has provided pursuant to section 112( i)(3)(A) the maximum 3-year peri od for sources to come into compliance. Sources may also seek a 1-year exte nsion of the compliance period from their Title V permitting authority if the source needs that time to install controls. CAA sect ion 112(i)(3)(B). If the situation described by commenters (i.e., where small entities or nonprofit utilities constraints on ability to raise capital for construction of control projects and to acquire ne cessary resources) results in the source needing additional time to inst all controls, they would be in a position to request the 1-year extension.

Comment 13: Commenters 17868 and 18032 believe the EP A did not adequately consider the disproportionately large impact on smaller generating units. The comme nters note the diseconomies in scale for pollution controls for such units. Commen ter 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 standa rds are unachievable by going too far without really considering the impacts on small municipal uni ts, as public powers is critical to communities, jobs, economic viability and electric reliability.

Commenter 17868 believes that the EPA has not fully r ecognized the number of small entitie s that are impacted by the rule and underestimat ed the impacts of the proposed rule on smaller utilities despite the SER panel.672 Comment 14: Commenter 19094 is a generating and transmi ssions electric cooperative which qualifies as a small entity and believes the proposed rule will ul timately result in increased electricity costs to its members and will negatively impact the economies of the primarily rural areas that they serve.

Comment 15: Commenter 17648 believes there is no legal or factual basis for creating subcategories or weaker standards for state, tribal, or municipal governments or small entities that are operating obsolete units, particularly given the curren t market situation and applicable equitable factors. The commenter suggests both the EPA’s and SBA’s analyses focu s exclusively on the eff ects on entities causing HAP emissions and primarily on those operating obsolet e EGUs, and fail to cons ider either impacts on downwind businesses and governments or the positive impacts on small entities and governments owning and operating competing, clean and modern EGUs.

Response to Comments 13 - 15: The EPA disagrees with the comment ers’ belief that the impacts on smaller generating units were not adequately considered when deve loping the proposed rule. The EPA determined the number of potentially impacted sma ll entities and assessed the potential impact of the proposed action on small entities, including munici pal units. A similar assessment was conducted in support of the final action. Specifi cally, the EPA estimated the incr emental net annualized compliance cost, which is a function of the chan ge in capital and operating costs, fu el costs, and change in revenue. The projected compliance cost was c onsidered relative to the projec ted revenue from generation. Thus, the EPA’s analysis accounts not only for the ad ditional 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 larg er units. One commenter ( 17648) believes that there is no legal or factual basis for creating subcategories or weaker standards for st ate, tribal, or municipal governments or small entities that are operating obsolete units. The comm enter points out that relaxation in standards would not only harm downwind governme nts and small businesses who incur higher labor costs due to pollution, but will harm other small bus inesses and state, trib al and local governments developing or operating generation f acilities using modern and less polluting generation technologies. The EPA acknowledges and generally agr ees with the commenter’s assertion.

Comment 16: Commenter 18032 notes that the EPA recognizes LEEs in the rule such that they should receive less onerous monitoring requirements; howe ver, the EPA does not recognize that small and LEEs also need and merit more flexible and achie vable 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 remova l, space constraints for control techno logy retrofits, and the fact that small units have fewer rate base customers upon whic h to spread these costs. The commenter cites the Michigan Department of Environmental Quality report titled “Michigan’s Mercury Electric Utility Workgroup, Final Report on Mercury Emissions from Coal-Fired Power Plants,” (June 2005). The commenter notes that the EPA has addressed such concerns previously, citing the RIA for the 1997 8- hour ozone standard. The commenter also suggests sma ller utility systems generally have less capital to invest in pollution control than larger, investor-owned systems, due to statutory inability to borrow from the private capital markets, statutory debt ceilings, limited bonding capacity, borrowing limitations related to fiscal strain posed by other, non- environmental factors, and other limitations.

Response to Comment 16: The EPA acknowledges its proposal of reduced monitoring requirements for existing units that qualify as low emitting EGUs. Although the EPA does not believe that reduced pollution control requirements are warranted for LEEs , including small entity LEEs, we believe that673 flexible and achievable pollution c ontrol requirements ar e promoted through a lternative standards, alternative compliance options, and emissions averag ing as a means of demons trating compliance with the standards for existing EGUs.

Comment 17: Commenter 8443 believes that the EPA s hould develop more limited monitoring requirements for small EGUs. The commenter not es 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 alternat ives to using PM CEMS, HCl CEMS, and Hg CEMS in its standards. The continuous compliance alternativ es would be available to all affected sources, including small entities. As mon itoring alternatives to use of PM CEMS and HCl CEMS, sources would be allowed to conduct additio nal performance testing. Sorbent trap monitoring would be allowed in lieu of Hg CEMS.

4. The EPA did not comply with the RFA.

Comment 18: Commenter 17608 believes the EPA has not su fficiently complied with the requirements of the RFA or adequately consid ered the impact this rulemaking would have on small entities. The commenter believes the EPA has not given itself the opportunity to e ngage in meaningful outreach and consultation with small entities and therefore recomme nds that the EPA seek to revise the court-agreed deadlines to which this rulemaking is subject, re-convene the SBAR panel, prepare a new initial regulatory flexibility analysis (IRFA), and issue it for additional public comment prior to final rulemaking.

Commenter 17608 believes the IRFA does not sufficien tly 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 beli eves the description of si gnificant alternatives in the IRFA is almost entirely quoted from the SBAR Panel Report, which the commenter does not believe is an adequate substitute for the EPA’s own analysis of alternatives. The comm enter also notes the EPA does not discuss the potential impacts of its deci sions on small entities or the impacts of possible flexibilities. Where the EPA does c onsider regulatory alternatives in principle, the commenter believes it does not provide sufficient support for its decision s 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 not es that the EPA did not evaluate the economic or environmental impacts of significant alternatives to the proposed rule.

Commenter 17608 believes that the EPA’ s stated reasons for declining to specify or analyze an area source standard are inadequate under the RFA. The commenter believes the EPA must give serious consideration to regulatory alternatives that accomplish the stated objectives of the CAA while minimizing any significant economic impacts on small entities and that the EPA has a duty to specify and analyze this option or to more clearly state its policy reasons for excluding serious consideration of a separate standard for area sources.

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 descripti ons 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 IRFAfor additional public comment before making any674 decisions about the EPA’s preferred options for fi nal 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 fu lly consider the s ubcategorization of sources such as boilers designed to burn lignite coals versus other fossi l fuels, especially in regard to non-Hg metal and acid gas emissions. The commente r references the SBAR Panel Report suggestion provided in the preamble of the proposed rule that th e EPA consider developing an area source versus major source distinction for the sour ce category and the EPA’s response.

Comment 20: Commenter 17868 is concerned that the reco mmendations made by the SER participants were ignored and not discussed in the rulemaking. Specifically, the commenter notes the EPA did not discuss subcategorizing by age, type of plant, fuel, physical space constraints or useful anticipated life of the plant. Nor did the EPA provide any opportunity for smaller emitters to use GACT—often used in other EPA MACT regulations to alleviate the regul atory costs and operational difficulties that would have burdened other small businesses including dry cleaners, metal fabrica ting, metal finishing, and others.

Comment 21: Commenter 17817 believes it is likely that different numerical or work practice standards are appropriate for area sources of HAP, just as in other rulemakings such as the RICE rule, and that the EPA would have provided the opportunity for small entities to make such demonstration had they followed their own regulatory requirements.

Response to Comments 18 - 21: The EPA disagrees with one comme nter’s (17608) assertion that the agency has not complied with the requirements of the RFA. The EPA complied with both the letter and spirit of the RFA, even under the court-ordered deadline. For example, the EPA notified the Chief Counsel for Advocacy of the SBA of its intent to c onvene a Panel; compiled a list of SERs for the Panel to consult with; and convened the Panel. The Panel met with SERs to collect their advice and recommendations; reviewed the EPA materials; and dr afted a report of Panel fi ndings. The EPA further disagrees with the commenter’s asse rtion that the EPA’s IRFA does not sufficiently consider impacts on small entities. The EPA’s IRFA, wh ich 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 entitie s is included in chapter 7 of the RIA for the final rule.

Several commenters (17608, 17805, 17868, and 17817) are concerned that recommendations made by the SERs were ignored and not considered or discussed in the proposed rulemaking. Specifically, commenters cite SER recommendations regarding sub categorization 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 whic h subcategories and sources would be regulated (76 FR 25036-25037, May 3, 2011). In that discussion, the EP A explains the rationa le for its proposed subcategories based on five unit design types. In addition, the EPA acknowledge s the subcategorization suggestions from the SERs and explains its reas ons for not subcategorizing on those bases. The preamble to the proposed standards al so includes a discussion of the SE Rs’ suggestion that area source EGUs be distinguished from major-s ource 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 anextension of the timeline for final rulemaking such that the SBAR Panel can be reconvened and a ne w IRFA can be prepared and released for public675 comment prior to the final rulemaking. The EPA ente red into a Consent Decr ee to resolve litigation alleging that the EPA failed to perform a non-discre tionary duty to promulgate CAA section 112(d) standards for EGUs. American Nurses Ass’n v. EPA , 08-2198 (D.D.C.). That C onsent Decree initially required the EPA to sign the final MATS rule by 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 Consen t Decree. If plaintiffs in the American Nurses litigation objected to an additional extension request, which we believe th ey would, the agency would have had to file a motion with the Court seeking an extension of the deadline. Consis tent with governing case law, the agency would have been required to demonstrate in its motion for extension that it was impossible to finalize the rule by the deadline pr ovided in the Consent Decree. See Sierra Club v. Jackson , Civil Action No. 01-1537 (D.D.C.) (Opinion of the Court de nying EPA’s motion to ex tend a consent decree deadline). The EPA was able to complete the ru le by December 16, 2011; accordingly, 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 proposedrule does not appear to have addressed the statement in UMRA section 202(a)(2) directi ng federal agencies to consider direct state administrative costs and to make this information av ailable to the public. The commenter cites concerns that state, local and tribal govern ment officials expressed at a mee ting 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 cost s are not expressly incl uded in UMRA as the type of costs to be included in analyzing cost impacts to the states. Thus, the EPA does not interpret state administrative costs to be among mandated costs, and state administrative costs were not addressed in the proposed rule and also are not addressed in the final rule. The UMRA discussion in the preamble to the final rule addresses this response to the commenter’s concern.

Comment 2: Commenter 17868 suggests the EPA failed to meet the requirements of UMRA as the proposed rule does not consider si gnificant impacts on small municipa lities. These impacts include the increased cost of power being driv en up by the compliance costs of the proposed rule, and the social and economic impacts of the potential shut down of power plants on municipal governments. The commenter was unable to find information in the rulemaking record regarding the qualitative and quantitative assessment of the anticipated costs and benefits of the pr oposed 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 regul atory permitting costs would be incurred by public power utilities, and therefore any comments subm itted by municipal or state governments, including their electric utilities, be considered under SBRE FA and UMRA. The commenter notes that the adverse cost impacts from the EGU MACT would extend di rectly to municipal and local government operating budgets, and that increasing operating costs for such not-for profit power pr oducers would be passed on directly to rate payers. The comm enter also notes that significant increased costs may reduce Payments in Lieu of Taxes to municipal operating budgets, wh ich could in turn result in cuts to essential governmental services including em ergency services and schools.

Comment 3: Commenter 17911 believes the EPA failed to provi de a complete financ ial analysis of the cost to communities in the proposed rule. The comme nter identifies specific items which the EPA did not take into account: (1) The impact of the rule on the Payment in Lieu of Taxes received by the community from the local municipal utility; (2) The addition al 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 incr eases in default rates on utility payments; (4) The cost to the city budget of potential downgrade to municipal bond ra tings caused by the city having to take on higher debt load to pay for the emission upgrades; (5) The di sparate impact of the ru le on smaller cities and smaller generating units; and (6) The social and ec onomic impact of the shut down of municipal power generation in smaller towns and the resulting incr ease in power costs on the competitiveness of local industries and other major employers.

Response to Comments 2 - 3: The EPA assessed the impact of the proposed and final rule on all directly-impacted municipalities (those holding covered EGUs). As required by UMRA, the EPA provided a written statement of the qualitative and quantitative impacts to state, local, and tribal677 governments, and the private sector. This analysis is presented for all municipa lities in section 10.2 of the RIA for the proposed rule and Chapter 7 of the RIA for the final rule, and specifically for small municipalities in section 10.1 of the RIA for the propos ed rule and section 7.5 of the RIA for the final rule. Total compliance costs for all government and pr ivate sector entities are presented in Chapter 8 of the proposal RIA and Chapter 3 of the final RIA. In the EPA’s analysis, a “small” government jurisdiction is defined as the government of a city, county, town, district, or special district with a population of less than 50,000. The EPA estimated th e incremental net annua lized 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 cons idered relative to the projected revenue from generation. Thus, the EPA’s analysis accounts not only for the additional costs these entities face resulting from compliance with the proposal, but also the imp act of higher electricity prices th at government entities should face, and does account for projected early retirements due to the proposal among affected units owned by government entities. All of these re sults are included in Chapter 10 of the RIA for the proposed rule and Chapter 7 of the RIA for the final rule, and detaile d results are found in the docket for the rulemaking.

As previously stated, the EPA’s analysis of costs includes direct compliance costs to units owned by states or municipalities that ar e subject to regulation under the ru le. The EPA does not believe that indirect administrative costs are large enough to have a significant impact. Additionally, while local governments may incur administrative costs as outlined by the commenter, such costs would be nearly impossible to estimate with any degree of accuracy due to the unique characteristics of each affected community and the numerous appro aches local governments could ta ke to minimize or offset administrative costs of the rule.

Comment 4: Commenters 17868 and 17911 express concerns over an apparent l ack of communication from the EPA regarding potential impacts of the proposed rule withstate and local governments as required by UMRA. The commenters disc uss these shortcomings with respect to the EPA meeting with the “Big Ten” on October 7, 2010. Specifically, the comm enters submit that the “Big 10” organizations are unlikely to have stakeholders that will be im pacted by the MACT rule, and the commenters are not aware that any of the state/local governments that the EPA estimates will be impacted by the MACT rule received any meaningful communi cations regarding potential impacts.”
Response to Comment 4: The EPA disagrees with the comme nters 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 establ ished at the time of the October 2010 meeting, the EPA believes that meaningful informa tion was shared with representatives of the state and local organizations early in th e regulatory process. The presentati on that the EPA used to overview the Utility MACT regulatory effort at the October 2010 meeting with the “Big 10” included information indicating that the EPA was early in the process of developing th e proposed action. Specifically, the presentation included a list of central decision points and poten tial issues (e.g., MACT floors and variability, subcategoriza tion, pollutants for which st andards would be establis hed) for which decisions had not yet been made and the EPA was seeking input. That presentation is av ailable in the rulemaking docket. As pointed out above, even though specific in formation regarding costs and other consequences of regulatory alternatives was not available, decisions and issues th at would affect costs and other consequences of regulatory alternatives were presen ted for discussion at the October 2010 meeting with the “Big 10.” Thus, this process enabled meaningf ul and timely input by stat e and local officials.

The EPA also disagrees with the commenters that th e “Big 10” organizations are unlikely to have stakeholders potentially impacted by the MACT rule . As examples, The National Association of Towns and Townships represent smaller communities, towns and townships, and other suburban and rural678 localities; the National A ssociation of Counties represents countygovernments; 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 es timated to be potentiallyimpacted by the MACT rule are also small government entities. Further, ten SERs were representatives of small entity representatives that participated in the SBAR panel process for the proposed rule. Thus, the EPA disagrees that potentially impacted state/local gove rnments did not receive meaningful communications regarding potential impact s either directly or through represen tation in the Federalism consultation and/or the SBAR panel process.

Comment 5: Commenter 17911 notes that the EPA never responded to suggestions by SERs during December 2010 that the 3-year timeline proposed by the EPA was both unrealistic and impossible to
meet.

Response to Comment 5: The preamble to the proposed ru le (76 FR 25054, May 3, 2011) provides a detailed discussion of how the EPA determined comp liance times for the proposed rule. With respect to the final rule, the EPA has provided pursuant to CAA section 112(i)(3)(A) the maximum 3-year period for sources to come into compliance. Sources may al so 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, especially in mid-si zed and smaller communities where a disproportionate share of those over 65 and thos e under the poverty level reside.

Response to Comment 6: The EPA conducted its economic analyses in response to the statutory and executive orders requirements that it must follow fo r economically significant rule s such as this one. The agency’s analysis included estimates of the incr ease in retail electricity price both nationally and regionally, and this analysis shows no increases in retail electricity price above 7% in 2015, and lower price increases thereafter. Such an analysis is informative to meet the requirements of EO 12898 (Environmental Justice). State and local authorities are best equipped to mitigate impacts related to increases in electricity rates.

Comment 7: Commenter 18023 states that the EPA’s RI A must adhere to UMRA and EO 12866 in conducting cost-benefit analysis.

Response to Comment 7: The EPA adhered to the requirement s of UMRA and EO 12866 in preparing the cost-benefit analysis that is presented in th e RIA for the proposed and final rules. The agency presented its analysis of the impact of the rule on fe deral, state, and local government entities in Chapter 10 of the RIA for the proposed rule and Chapter 7 of th e RIA for the final rule. This analysis serves as the written statement that is required under sectio n 202 of the UMRA. Intergovernmental consultations as required under section 204 were c onducted and were placed in the docket for this rulemaking. The agency explained why this standard was proposed, a nd alternatives to it, in the preamble for the proposal. The contents of the RIA are consiste nt 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 re quires that the EPA provide to the OMB a federalism summary impact statement (FSIS) containing a number of elements, including a statement of the extent to which the con cerns of state and local o fficials have been met. Commenter indicates that states co ntinue to remain uncertain of the extent to which the EPA is considering state administrative cost s, including state administrative costs for this proposed utility MACT rule.

Response to Comment 1: As required by section 6(b)(2)(B) of EO 13132, the EPA provided a FSIS in its proposed rule and provides an updated impact stat ement in the preamble to the final rule. The final rule impact statement presents the EPA’s assessme nt of the compliance costs of the regulatory option being promulgated on state and local governments. In addition, the stat ement addresses state and local officials’ uncertainty regarding the extent to which th e 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 ignoredseveral principal tenants of EO 13132. Specifically, the commenter references section 3(b) of EO 13132, which require s agencies to consult with state and local officials to determine whether federal objectives can be attained by other means where there are significant uncertainties as to wh ether national action is au thorized or appropriate.

Response to Comment 2: Commenter implies that there is significant uncertainty about the agency’s authority to issue the final rule and whether it is appropriate to addr ess the hazards to public health and the environment posed by EGUs. The EPA disagrees w ith the commenter. The EPA determined that it was appropriate and necessary to regulate EGUs inDecember 2000 and added such units to the section 112(c) list. Sources listed must be regulated pursuant to secti on 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 substantial and will impact ratepayers dramatically, potentially driving residents and businesses from the city in an effort to seek cheaper electricity el sewhere. The commenter believes its city is more disproportionately impacted by the ru le than utilities with larger and more diverse generation resources.

Response to Comment 3: EO 13132 provides that when a regulat ion imposes substantial direct compliance costs, the agency has the option of either providing the funds necessary to pay those direct costs or consulting with state and lo cal officials. It does not explicitly favor either option. With respect to the air toxics regulation for EGUs, the EPA consulte d with state and local offi cials. As described in the preamble to the proposed rule , the EPA invited 10 national organizat ions representing state and local elected officials to a consultation meeting th at 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 stat e/local governments. As required by the EO, a FSIS was included in the preamble to the proposed rule. An impact statemen t is also included in the preamble to the final rule.

In response to the commenter’s concerns that their co sts of complying with the rule will be substantial and disproportionately high resulting in dramatic impacts on their ratepayers, the EPA believes that flexible and achievable pollution c ontrol requirements ar e promoted through a lternative standards, alternative monitoring and complian ce options, and emissions averaging as a means of demonstrating compliance with the standards for existing EGUs. More over, as discussed elsewhere in this document, the EPA’s analyses indicate that the impacts of co mpliance with the rule w ill not cause a significant increase in electricity costs to rate payers.

2. Federal and state interaction.

Comment 4: Commenters 17791 and 17701 appreciate the EP A’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 ru les such as this proposal are implemented. The commenters note that the EPA officials have made themselves available and have sought input on the rulemaking fr om their organization representing utility commissioners. The commenter encourages continued dialog and interaction between fe deral and state air and energy regulators.

Commenter 17791 points out that continued collaborat ion between the federal agencies, states, and industry will be essential to further promoti ng energy efficiency and reducing emissions. The commenter discusses prior state ener gy efficiency efforts that the EPA was involved with -- the National Action Plan on Energy Efficiency (NAPEE) and the State Energy E fficiency Action Network (SEEAction).

Response to Comment 4: The EPA welcomes these observati ons 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 govern ments to fulfill its mission of pr otecting human health and the environment.681 7F - Executive Order 13175, Consultation and C oordination with Indian Tribal Governments

Commenters : 12462, 15182, 16122, 17674, 17732, 17733, 17846, 18017, 19686

Comment 1: Several commenters (12462, 16122, 17846) support stringent EPA regula tions on toxic air emissions that must eliminate the disproportionate impact on the American Indians and Alaska Natives, and Indigenous Peoples, their lands , waters and natural resources.

Commenter 16122 also notes that the EPA has a respons ibility to not only identify but address the very significant effects that Indian trib es and their members face from their exposure to Hg emissions from EGUs. The commenter notes the impacts of Hg cont amination pose not only disproportionally high and adverse health effects, but unique and distinctive th reat to its members becau se of the enormous and cultural value natural resources have for the Tribe and its members.

Comment 2: Commenter 15182 notes concern within trib al communities that methylmercury in ogaa (walleye) may pose a serious threat to the health of fetuses and young childr en as the practice of harvesting, sharing, and consuming the fish is pa ssed down through generations. The commenter notes that ogaa and other fish represent a significant subsiste nce food source for tribal communities and that tribes are disproportionately impacted by the Hg levels in these fish that regularly exceed the EPA fish consumption guidance values. The commenter sugge sts that limitations on the consumption of ogaa and other species as a result of elevated Hg concentrations threaten the traditional Anisinaabe lifeway and the ability of the Chippewa people to fully exercise their treaty harvest rights.

Response to Comments 1 - 2: The EPA acknowledges the support for stringent federal regulations of EGU air toxics emissions from commenters and understands the concerns expressed by commenters with regard to tribal member exposure to Hg em issions 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 tr aditional diets include hi gh consumption of fish.

Comment 3: Commenter 12462 requests that the EPA fulfill it s mandate to respect the rights of tribes, as sovereign governments, to exercise their right to self-determination with anappropriate consultation process on regulations that affect the health, safety and welfare of Indigenous Peoples. The commenter asserts that the federal government and the EPA must acknowledge its trust responsibility to Tribes to end the disproportionate impact of air toxins from EGUs. The commenter also cites an example in which the Michigan Department of Environmental Quality (MDEQ), was delegated the authority to issue a Permit to Install (PTI) to a coal-fired power plant butdid not consider the diffe rent 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 Re sponsibility to promulgate a MA CT standard that fully and adequately protects its environmental interests and its tribal resources. Commenters note that it is clear that Hg deposition from EGUs have significantly impacted culturally-important lands, waters and natural resources on reservations.

Commenter 19686 recommends that the EPA devote more of its resources to conduct in-depth studies regarding the effects of Hg emissions on Tribal communities, and in fact, the EPA should do such studies for other pollutants. Further, commente r 19686 recommends that the EPA conduct a benefits analysis that fully assesses the rule’s impacts on Tr ibal air quality and healt h, as well as cultural and subsistence practices.682 Comment 5: Commenter 18540 believes that the EPA has a tr ust responsibility to ensure that the Community’s water rights, and othe r guarantees and benefits provided in the Arizona Water Settlements Act (AWSA) are preserved, and that the trust responsib ility prohibits the agencyfrom imposing a Utility MACT that limits the community’s ab ility to receive and use Central Arizona Project (CAP) water. The commenter believes the proposed rule would force th e closure of Navajo Ge nerating Station (NGS), inhibiting and possibly eliminating the Community’s ri ght to receive and utili ze its allocation of CAP water guaranteed by the AWSA. The commenter believ es that the proposed U tility 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 w ith the delivery of CAP water. Even more, the proposed Utility MACT rule would li mit the Community’s ability to fa rm its reservation lands and its future economic development opportunities, and would negatively impact the livelihood and health of Community members.

Comment 6: Commenters 17674 and 17732 have concerns with the consultation with their tribal governments as required by EO 13175. Commenter 17674 is troubled that the EPA has not undertaken any formal consultation with their tribal community, despite a formal request submitted in July. The commenter believes given the nature of the interests at stake, the implications of the proposed rule, and the EPA’s federal trust obligations, consultation must be among senior-level EPA officials and tribal leaders. Commenter 17732 states that the EPA only pr ovided 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 th e three coal-fired power plants identified in the Tribal Outreach memo, and their supporting mines, fo r one third of its general operati ng fund in addition to significant jobs provided by both the plants and their mines. Th erefore the commenter beli eves that the EPA must do better to engage their tribal government in meaningful consu ltation 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, consis tent with the federal government’s trust responsibility to federally reco gnized tribes. The EPA agrees that this rule affect s tribes and as such, we actively encouraged trib es to participate in our rule making. We conducted outreach and information sharing with tribal environmental sta ff through the monthly National Tribal Air Association calls, at the National Tribal Forum, and a webinar targeting tribal environmental professionals on the content of the proposal. In addition, we sent letters to a ll tribal leaders and o ffered 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 by several trib es, and in order to help us better understand their concerns, we also participated ina face-to-face meeting with tribes in Arizona who were concerned about the potential impact of this rule on their income and water righ ts. Following that meeting, we held an additional technical meeting on how IPM is used in the RIA a nd provided one-on-one consultation with the Navajo Nation, Gila Ri ver Indian Community and the Ak-Chin Indian Community. Thus, the EPA disagrees with commenter statements that th e EPA has not undertaken any formal consultation with their tribal community. The EPA also points out that senior-level EPA of ficials were involved in the meetings. The EPA would like to clarify that the generi c letter to tribal governments to which one commenter refers was not intended to be “the co nsultation” but, rather, it offered consultation.

With regard to commenters’ concerns about the imp act of the final rule on NGS and the delivery of water under water settlements in Ar izona, the EPA recognizes the sign ificance of NGS to the Central Arizona Project and has been consu lting with affected Indian tribes and working closely with other federal agencies, including the Department of the Interior, on thes e 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 excl usion or disparate treatmen t of the facility under this CAA regulation. The facility is currently regulated und er other CAA programs, and we believe that the requirements of section 112 also apply. The EP A is, however, mindful of the complex situation relating to NGS and the delivery of water in Ariz ona. The EPA is committed to continuing to work closely with affected tribes and other federal agencies to consider these issues as the rule is implemented, consistent with the federal government’ s trust responsibility to the tribes. The EPA also notes that it is not currently certain what decisi ons will be made with respect to NGS’s operation to address the rule’s requirements. The EPA’s modeling and projections are intended to be a reflection of possible compliance using specific t ools, assumptions, and methodologies that the agency believes to reflect the best and most current information rela ted to the power sector. The inclusion of other regulatory actions (including federa l, state, and local actions) in the modeling reflects the level of controls that are likely to be inplace in response to other require ments 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 act ual compliance decisions, since those will be made individually by the affected indus try based on what makes most sens e using existing technologies or other, more cost-effective strate gies. For that reason, we caution co mmenters not to assume that any statements in EPA’s modeling analyses about possi ble actions by NGS, includi ng closure, reflect the only possible outcome of the final rule. The EPA will wo rk with relevant authorities to ensure a smooth transition with this rule and addre ss specific issues as they arise. Public utility commissions and other authorities, including tribes, will need to develop and implement compliance plan s in order to address harmful emissions.

With regard to one commenter’s concerns about the permits issued by the MDEQ, we note that the agency under its environmental justice (EJ) strategy known as Plan EJ 2014 is actively pursuing tools, resources and guidance to improve the incorporation of EJ considerations in our permitting. However, this rule will not affect the preconstruction permitting New Source Review programs, and this issue cannot be addressed by this rulemaking.

In response to one commenter’s recommendation that additional studies and an alyses be conducted, we agree that additional analysis would be helpfu l to better understand the impacts of air pollution, particularly Hg, on Native American populations. This rule addresses impacts of air pollution on Native American populations in that it regulates Hg air pollution from EG Us. The EPA’s Office of Research and Development has undergone realignment to better address agency priorities, for which disproportionate exposure is of part icular concern. This issue falls within the content areas of the Sustainable and Healthy Communitie s, 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 contam ination of food fish falls within their work on multipollutant emissions, transport and cascading e ffects. 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 pr oposed NESHAP Rule in its goal of addressing reductions of HAP from stationary so urces. The health and well-being of the natural environment and the people of the tribal nation are of utmost importance to the commenter. As a tribal nation and small government landlord of affected EGUs , the commenter states th at the EPA is obligated to consult with the tribal nati on and analyze the economic impacts to the nation in promulgating the proposed rule. The commenter further states that the EP A 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 challe nges of the plants for this and future rulemakings. The commenter explains that compli ance costs to meet BART have th e potential to impact the tribal nation economy significantly. The commenter is concerne d that the rule will creat e a recurring threat of severe reductions in the revenue received from the power plants and their supplying mines. The commenter asks that the EPA analyze the impacts fr om these rulemakings and provide flexibility for compliance scheduling so that EGUs upon whic h the Nation relies can continue operations.

Response to Comment 7: The EPA recognizes the concerns raisedby 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 es timated the potential im pacts associated with complying with the rule on all enti ties that own affected EGUs, incl uding those located on tribal nation land. We offered consultation to all tribal governme nts and conducted one-on-one consultation with the commenter. With respect to the compliance schedule , the EPA has provided the maximum 3-year period for sources to come into compliance as allowed by s ection 112 of the CAA. Sources may also seek a 1- year extension of the compliance period from their Title V permitting authority if the source needs that time to install controls. CAA section 112(i)(3)(B).

Comment 8: Commenter 17674 expresses concern with the EPA’s presumption in the rulemaking that the NGS will close in 2015, citing the RIA where the EPA presumes that two of the three units would retire with or without implementatio n of the Utility MACT and the third would be forced to retire as a result of the economic and regulatory burdens im posed by the proposed rule. The commenter believes these assumptions are in contrast to prior statemen ts by the EPA regarding the facility during the BART rulemaking. The commenter also believes the EPA mustaddress the catastrophic impacts that the Utility MACT will have on Arizona tribes and reconcile these opposed positions.

Response to Comment 8: As mentioned previously, the EPA conducted extensive outreach and consultation on this rule. However, because of concerns raised by several tribes, and in order to help us better understand their concerns, we al so participated in a face-to-face meeting with tribes in Arizona who were concerned about the potential impact of th is rule on their income and water rights. Following that meeting, we held an additional technical mee ting on how IPM is used in the RIA and provided oneon-one consultation with the Nava jo Nation, Gila River Indian Co mmunity 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 us ing specific tools, assumptions, a nd methodologies that the agency believes reflect the best and most cu rrent information related to the pow er sector. It is not intended to reflect actual compliance decisions, since those will be made individually by the affected industry based on what makes most sense using existing technologies or other, more cost-effective strategies. Thus the EPA’s IPM analysis of MATS does not dictate what a given facility must do to comply with MATS. Each facility may determine its own compliance strategy to meet the emission rate limits in MATS. The EPA will work with relevant authorities to ensure a smooth transition with this rule and address specific issues as they arise. Public utility commissions and other authorities, such as tr ibes, will need to develop and implement compliance plans in order to addr ess harmful emissions. We would point out that changes in the final rule are signif icant and will reduce costs, increase flexibility and al leviate industry concerns about achievab ility of standards.

Comment 9: Commenter 17674 discusses numerous consid erations 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 Congressional ly-approved Indian water rights se ttlements, to Native American communities, and provides jobs both directlyand 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 ot her authorities to ensure a smooth tr ansition and address specific issues as they arise. However, we note that section 112 of the CAA imposes specific requirements with respect to the methodology the EPA must use in establ ishing emission standards for HAP, including Hg emissions from EGUs. The commenter suggests tr eating NGS differently from other generating facilities, and we interpret this comment at least in part as a request for a s ubcategory for NGS. Pursuant to CAA section 112(d)(1), the EPA may subcategorize sources based on differences in class, type, or size. In the preamble to the proposed rule, the EPA fu rther explains that any basis for subcategorizing (e.g. class) must be related to an effect on emissions, rather than so me difference which does not affect emissions performance. The EPA does not agree thata subcategory based on lo cation on tribal lands is consistent with the statutory authority to subc ategorize, and the commen ter does not explain why emissions would be different for EGUs located on tr ibal lands. Absent that showing, it would not be appropriate to subcategorize units even if we be lieved 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 relaxati on in standards would not only harm downwind governments and small businesses who incur higher la bor costs due to pollution, but will harm other small businesses and state, tribal and local governments developing or operating generation facilities using modern and less polluting generation technologies. The methodology for determining emission standards under CAA section 112 does not result in requirements that specify the means of complying with standards. Thus, affected sources make thei r own determination regarding how they will comply with the standards. We believe that flexible and ac hievable pollution control re quirements are promoted in the final rule through inclusion of alternative standards, alternat ive compliance options, and emissions averaging as a means of demonstrating comp liance with the standards for existing EGUs.

Comment 10: Commenter 18017 states that if the propos ed rule and other pending rules require installation of new control equipmen t costing hundreds of millions of dollars, the potential result could be early closure of their plant because the owners will be required to comply before they know whether the approvals necessary to operate after 2019 can be obtained. The commenter is concerned that the EPA may establish final emission limits governing NGS PM emissions that are so stringent that a new PM control will be required with compliance dates be fore approvals can realistically be obtained. The commenter asserts that this would lead to hi gh 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 inst alling significant emission controls are likely to experience lower compliance costs as the result of this rule. Many coal facilities have alre ady 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 11: Commenter 19686 states that the EPA needs to integrate the United Nations Declaration on the Rights of Indigenous Peoples (signed in D ecember 2010) into the rule and other EPA actions. A number of federal entities including the Department of the Interior and Department of Justice are taking actions to implement the Declaration in their program s 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 Declar ation through the rule and other EPA actions with potential Tribal implications.

Response to Comment 11: The U.S. announced its support for th e United Nations Declaration on the Rights of Indigenous Peoples in De cember of 2010. US agencies, incl uding EPA, are currently engaged in many initiatives to address the issues in the Declaration. Consiste nt 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 relations hip with tribes thr ough the development and implementation of its May 4, 2011 Policy on Consultation and Coordina tion with Indian Tribes. Consistent with the important provisions of the Declaration that address environmental issues, in the development of this rule EPA encouraged tribal particip ation, by requesting data and informa tion 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 activ ities including c onsultation prior to proposal and post proposal , webinars, and onsite consultation with several tribes at their request. The EPA’s discussion of EO 13175 includes additiona l details regarding EPA’s consultation and coordination with Indian tribes.

Comment 12 : Commenters 17846 and 19686 state that the Trib e and its members are greatly concerned about the environmental, health, a nd economic impacts of Hg depositio n from coal-fired EGUs. Because of this, commenter 17846 commends the EPA for pr oposing a rule that, in accordance with the requirements of CAA section 112, applies the same em ission limits to all EGUs within a subcategory. This is critical to avoid the creation of Hg “hot spots,” which could leave la rge portions of Indian country susceptible to co ntinuing Hg contamination.

Response to Comment 12: The EPA acknowledges commenters’ concerns and appreciates their support of this important rule that will reduce emissions of Hg and other air toxics.

Comment 13: Commenter 19686 states that the EPA has faile d 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 w ith 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 ru le might impact them.

Response to Comment 13 : In the final rule, the EPA establishe d technology-based standards consistent with the requirements of CAA section 112(d). Suchstandards require all sources within a source category or subcategory to reduce HAP emissions to the same level w ithout consideration of risk. To determine whether additional standards are necessary, the EPA will consider whether risk remains from HAP emissions from a source catego ry within 8 years of promulgati ng final section 112(d) standards pursuant to section 112(f)(2). We encourage the commenter’s sugge stions on how to continue to minimize the potential local impact of Hg from thes e sources as the rule is implemented. The EPA will provide any non-privileged available information re levant to Hg deposition in Indian country in response to a request from the tribe. Finally, we encourage tribes to work with the EPA as it considers the risk to public health, including tribal members, in determining the need for further standards as the EPA reviews these standards consistent with the statute.687 Comment 14: Commenter 17846 states that the Tribe and its members are greatly concerned about the environmental, health, and economic impacts of Hg deposition from coal-fired EGUs. Because of this, The Fond du Lac Band of Lake Superior Chippewa commends the EPA for pr oposing a rule that, in accordance with the requirements of section 112, applies the same emi ssion limits to all EGUs within a subcategory. This is critical to a void the creation of Hg “hot spots,” which could leave large portions of lndian country susceptible to c ontinuing mercury contamination.

Response to Comment 14 : The EPA shares the tribes concerns about Hg and its potential impact on tribes. We believe this rule will prevent local hotspots from occurring.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 copy of a jour nal article entitled “Pregnancy Loss and Maternal Methemoglobin Levels: An Indirect Explanat ion of the Association of Environmental Toxics and Their Adverse Effects on the Mother and the Fetu s.” According to the abstract, the aim of this epidemiologic study was to point out a relations hip between the exposure to products of coal combustion, and complications in pregnancy where one third of causes of stil lbirth are still unknown.

Comment 2: Commenter 12462 notes Hg is of special c oncern to Tribal children and women of childbearing age, as Hg is a neurotoxin that cau ses neurological delays and damage. The commenter states in utero exposure to Hg, via contaminated fish eaten by expectant mothers, can impair thinking, memory, attention, language, and fine motor and spatia l skills. Addition ally, 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 pr oposal to reduce Hg and other harmful emissions, stating the American public, especially vulnerable populations such as pregnant women and children, is currently not adequately protected from Hg exposure in the environment. The commenter briefly summarizes Hg issues related to health effects and exposures for these populations.

Response to Comments 1 - 3: The EPA acknowledges the concerns of all three commenters and appreciates their input regarding he alth effects of Hg and other coal combustion emissions. In addition, the EPA thanks commenter 16121 for their general support of the proposal.689 7H – Executive Order 13211, Actions Concerning Re gulations That Significantly Affect Energy Supply, Distribution or Use

Commenters : 18447

Comment 1: Commenter 18447 suggests that, despite the EPA’ s conclusion, the rule is likely to have adverse effect on the supply, dist ribution, or use of energy, and the EPA downplays the impact of the rule with respect to the costs that the taxpaye rs and U.S economy must bear, which the commenter believes are substantial.

Response to Comment 1: As discussed extensively elsewhere inthis document, the preamble to the final rule, the RIA, and other s upporting materials, the EPA disagr ees with commenter and maintains that the EPA’s analysis of the rule is reasonabl e, and does not understate impacts as the commenter suggests.690 7I - National Technology Transfer and Advancement Act

No comments were received sp ecifically on the National Technology Transfer and Advancement Act (NTTAA) or its requirements. To the extent that th e NTTAA is referenced in the context of comments regarding another topic it has been addressed as appropriate.691 7J - Executive Order 12898, Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations

Commenters : 17254, 17681, 17697, 17710, 17713, 17766, 18433, 18934, 19145, 19210, 19536/19537/19538

1. General comments regarding impacts on minority and low-income populations.

Comment 1: Commenter 17254 presents a map showing the close correlation betw een the location of populations below the poverty line e xpected in 2016 and the locations of power plants. The commenter states that while the EPA developed these maps to s how the potential impacts fr om fish consumption in nearby waterways, the evidence also shows that thes e populations face higher risks because of the air they breathe.

Commenter 17254 notes that coal-fired power plants are disproportiona tely 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 plan t, as opposed to 56% of whites. Th e commenter also notes that even though African Americans compromise 13% of the U.S. population, they account for 17% of the population living within 5 miles of power plant waste sites.

Comment 2: Multiple commenters (17524, 19210, 19536, 19537, 19538) note that disadvantaged communities that rely on the extra source of protein from fishing shoulder a disproportionate share of the impact from Hg pollution. Commenter 17524 cite s a study that Sierra Club commissioned from Bendixen and Amandi, a polling firm, in which increased risks to the Hispanic community are identified from fishing in urban communities, where fish caught tend to have the highest concentration of Hg contamination. The commenter notes that the study re ports that Hispanics in California consume almost twice the EPA safe limit of Hg due to subsistence fishing.

Response to Comments 1 - 2: The EPA agrees that minority and low-income populations are overrepresented among those persons who live in close proximity to coal-fired power plants and that certain low income and minority community members (such as subsistence fishers) consume higher levels of fish that may be contaminated by Hg. For these reasons, the EPA expects that minority, lowincome and indigenous population gr oups would benefit disproportionate ly 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 scie ntific evidence of EGU’s impact on Hg blood concentrations in at ri sk populations, such as minorities and the elderly. The commenter notes that they are cautious to endorse a rule which will financially impact such populations to great extent while at the same time it is witnessing unexplained substantial reductio ns in blood Hg concentrations of all population classes accordin g to the EPA’s National Health and Nutrition Examination Survey (NHANES) data.

Response to Comment 3: First, the EPA has developed an analyt ical method to estimate the impact of Hg emissions from U.S. EGUs on Hg fish tissue c oncentrations and the impli cations for human health, as documented in the National-Scale Mercury Risk A ssessment. Second, the EPA disagrees that there is a statistically discernible downwar d trend in the NHANES data on blood Hg. The EPA is unaware that a formal statistical analysis for temporal trends has been completed for NHANES data on blood Hg levels for the period 1999 to 2008. Mahaffey et al. 2009, evaluating NHANES data collected 1999 to 2004 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-year study period.” However, the same publication noted that “there was a decline in th e upper percentiles reflecting the most highly exposure women” having blood Hg concentration greater than established levels of concern. Visu al observations of the data show a slight decrease in Hg blood level concentrations from 1999-2008 at the geomet ric mean. This decrease may not be statistically significant based on overla pping confidence intervals. A decrease in Hg blood level concentrations is also observed at the 95th percentile. Excep t for differences observed between 1999 and 2008, the temporal decrease may not be statis tically significant. Conc lusions cannot be drawn without further and more formal st atistical analysis of the data.

The EPA remains concerned that substantial number s of women of childbearing age in the U.S. may have blood Hg levels that are equivalent to exposures at orabove the RfD. Mean and 95 thpercentiles from recent NHANES data are below 5.8 ug/l (a bl ood Hgy concentration equivalent to the RfD). However, blood levels for some portions of the populat ion (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 thpercentile. Modeled data from Tran et al., 2004 provided estimate s showing high blood Hg levels at the 99 thpercentile for females of child-b earing age (i.e., 24.41 ug/L at the 99 thpercentile). 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 vari ous population groups can have high blood Hg levels (Mahaffey 2005; Miranda et al. 2011; Hightower and More 2003; Hightow er et al. 2006; McKelvey et al. 2007). For example, in Hightower et al. 2006, the authors found that Asian populations had Hg exposures greater than 5.8 ug/L in 83% of the Asian population compared to 12% for the total survey population.) (Butler Walker, J., J. Houseman, et al. (2006). “Maternal and umbilical cord blood levels of mercury, lead, cadmium, and essential trace elements in Arctic Canada.” Environ Res 100(3): 295-318; Hightower, J. M. and D. Moore (2003). “Mercury leve ls in high-end consumers of fish.” Environ Health Perspect 111(4): 604-608; Hightower, J. M., A. O’Hare, et al. (2006). “Blood mercury reporting in NHANES: identifying Asian, Pacific Islander, Nativ e American, and multiracial groups.” Environ Health Perspect 114(2): 173-175.)

Comment 4: Several commenters (17697, 17710, 18433) note that Guam is designated as a “distressed nonmetropolitan middle-income” area due to both high poverty and unemployment rates, yet its utility costs are among the highest in the nation. Given th ese circumstances, commen ter 17710 requests that the EPA consider relief for the Guam Power Authority (GPA) from the final rule.

Commenter 17710 suggests the compliance costs and ri sks associated with th e rule would require significantly increased electricity rates that could cause economic hardsh ip on its customers, such as the unemployed, underemployed and those with limited or fixed incomes.

Response to Comment 4: The EPA disagrees that the rule will re sult 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 s ubstantial benefits to h ealth 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 deta il in the RIA. States and local entities responsible for util ity rate structures are be st positioned to deal with economic impacts on low income customers and with the overall distribution of increased costs.

The EPA expects that the gene ral population, including low inco me persons, would experience significant health benefits as a result of this rulemaking. The standards would prevent as many as 17,000 premature deaths and 11,000 heart attacks a year and would provide particular health benefits for693 children, preventing 120,000 cases of childhood asthma symptoms and about 11,000 fewer cases of acute bronchitis among children each year. The EPA estimates that for every dollar spent to reduce pollution from power plants, the American public and American businesses will see up to $13 in health and economic benefits. It is also likely that household income for some low income families may increase if individuals are able to work (o r work more) as a result of improved health.

Finally, the EPA has acknowledged the unique circumst ances 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 achieve d by the top 12% of plants be required as such technology exists. The commenter offers to work w ith the EPA to further define EJ communities for such a purpose.

Response to Comment 5: CAA section 112(d) standards are tec hnology-based standards. Pursuant to section 112(d)(3), the EPA establishes MACT floorlimits for existing sources based on the best performing 12% of sources. After es tablishing the MACT floors, the st atute requires the agency to determine whether standards more stringent than th e MACT floor are achievabl e after considering the costs of achieving such additional emission reductions and the non-air quality health and environmental impacts of more stringent standards. CAA sec tion 112(d)(2). The EPA has conducted an analysis consistent with section 112(d)(2) for this rule and determined that a more stringent standard is achievable for one pollutant from one existing sour ce subcategory. As the D.C. Circuit recognized in Sierra Club v. EPA, 353 F.3d 976 (D.C. Cir. 2004:

“These [112(d)(2) and (d)(3)] emissi on standards are to be based not on an assessment of the risks posed by HAP, but instead on the maximum achievable c ontrol 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 achieve d by the best-performing sources in a particular category. . . The idea is to set limits that, as an initia l matter, require all sources in a category to at least clean up their emissions to the level that their best performing peers have shown can be achieved.” 353 F.3d at 990.

In Sierra Club , Sierra Club argued that the phrase “non-air qu ality health and environmental impacts” in 112(d)(2) required the EPA to consider the “imp acts of deposition, persistence, toxicity and bioaccumulation of metal HAP emissions on people, w ildlife and the environment.” The Court rejected this argument and upheld the EPA’s interpretation of the phrase, which was that “‘non-air quality ... impacts’ refers to any health and environmental impact s ... that may result direct ly or indirectly from [the control] measures that wi ll achieve the emission reductions.” 353 F.3d at 990-91. The Court further held that “Sierra Club’s interpretation would collaps e the technology-based/risk-b ased distinction at the heart of the Act, undermining the ce ntral purpose of the 1990 Amendments.” Id. The commenter here seeks to infuse risk into setting techno logy-standards, which is not permissible.

Within 8 years after the EPA promul gates section 112(d) standards, sect ion 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 pr otect public health. The EPA will consider risks posed to disadvantaged communities in th at evaluation, but any resulting stan dards must be national in their scope and applicability. To the extent that any gi ven community is seeking greater protection than a694 national rule would provide, we enco urage them to work with the appr opriate State and local authorities to fashion solutions that are specific to their community.

Comment 6: Commenter 19145 provides seve ral statistics on th e disproportionate impacts related to African Americans and power plants. The commenter us es these statistics to show pollution from power plants is an issue of racial disp arity as African American s are most likely to be exposed to the toxins coming from power plants and the impact is apparent through the higher rates of infant mortality, low birth weight, and premature births among the populat ion. The commenter also notes that the African American population has increased rates of asthma, with power pl ant pollution being a contributing factor to asthma and chronic bronchitis.

Response to Comment 6: The EPA agrees that minority populati ons, including African Americans, generally have worse health than whites and th at many minority and low income communities are overburdened by air pollution. The EPA agrees that the African American population has increased rates of asthma compared to other population groups and that pollution from power plants can be a contributing factor to asthma and chronic bronchitis . To that extent, African Americans living in the vicinity of power plants can be expected to receive disproporti onate benefits from the rule’s implementation.

Comment 7: Several commenters (19536, 19537, 19538) believe s information gathering and better understanding of the cumulative he alth impacts in areas where many sources of HAP are located together, such as industrial areas, would be beneficial for addr essing EJ concerns.

Response to Comment 7: The EPA generally agrees with the value of assessing cumulative impacts in such areas, and that additional data would be useful in that process, but collecti on 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 Ju stice Statement included in the proposed rule does not meet the requirements of EO 12898 as it failed to address incr eased 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 dispos able incomes that these consumers would have to spend on health care, food, coo ling and heating, and housing.

Response to Comment 8: The EPA does not agree with the comm enter’s assertion that the agency failed to consider the impacts of increased electric rates to consumer s, including minority, fixed income and low-income populations. The comme nter also makes an assertion wh ich relies on a theory that the cost of a rule will result in lost in come 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 a nd 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 rely on questiona ble 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 th e regulation are unlikely to cause large changes in any single aspect of household sp ending, such as health care. These an alyses also fail to consider that household income may increase if i ndividuals are able to work (or wo rk 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 revi ew panels have consistently advi sed against incorporating alleged health-health tradeoffs in the EPA analyses of regulatory effects.

The agency’s rule requires reductions of HAP such as Hg, arsenic, lead and othe r metals, that are shown to cause serious injury to exposed populations. Th e 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% on average nationally by 2015, with some consumers in certain regions seeing incr eases of less than 10% while other consumers in different regions will see increases of only 1%. These increases in electric rates may not be minimal in some areas of the U.S., but they should be seen inlight 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 Ju stice Statement failed to consider the cumulative impacts of the rule in addition to other pow er sector rules, which di sproportionately impact lower income, elderly and minority populations. The commenter cites an economic analysis prepared by National Economic Research Associates for the Ameri can Coalition for Clean Co al Electricity (ACEE) showing estimated increases in electricity prices, natural gas prices, and loss of jobs from the combined impacts of the proposed rule and th e CSAPR. The commenter also includ es in their comment a copy of a January 2011 publication entitled “Energy Cost Impacts on American Families, 2001-2011” and cites a March 2010 study performed for the Affordable Powe r Alliance by Management Systems, Inc. on the effect of GHG regulations, both of which conclude that there are disproportionate impacts on low income and minority groups from these regulations.

Response to Comment 9: As discussed above, the EPA disagrees with the assertion that the rule will result in disproportionate negative impacts on lo w-income, elderly, and minority populations. The EPA believes this rule will provide sign ificant benefits to all citizens, including minority, low-income and indigenous populations. Furthermore, the EPA ha s recently assessed the cumulative impact of regulations adopted to implement the 1990 CAA Amendments. In March 2011, the EPA issued the Second Clean Air Act Prospective Report which assesse d 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/se ct812/feb11/summaryreport.pdf ). As shown in the repo rt, the direct benefits from the 1990 CAA Amendments reach almost $2 tril lion for the year 2020, a figure that dwarfs the direct costs of implementation ( $65 billion). The full report is at http://www.epa.gov/air/sect812/prospective2.html . The direct benefits of the 1990 CAA Amendments and associated programs significantly exceed their direct costs, which means economic welfare and quality of life for Americans were improved by pa ssage of the 1990 Amendments. The wide margin by which benefits exceed costs combined with extensive unc ertainty analysis suggest it is very unlikely this result would be reversed using any reasonable alternative assumpti ons or methods. The EPA believes the same conclusion applies to this ru lemaking, as discussed in the RIA.

The economy as a whole is also stronger with 1990 CAA Amendment programs as cleaner air leads to better health and productivity for American workers and less money sp ent on health care to treat air pollution-related health problems. Economy-wide m odeling shows that long-term economic growth is greater and American household economic welfare is im proved because benefits such as fewer sick days 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 by laying off workers, with low-wage workers being the groups that will be impacted by such layoffs. The commenter notes that low-wage workers are disproportionately Black and Hispanic.

Response to Comment 10: As discussed elsewhere in this docu ment, the EPA’s analysis shows that high energy prices will not result from this rule, and increases are expected to be 3.7% on average nationally by 2015. The EPA estimates that the overal l impact on short-term employment will be an increase on net of 46,000 jobs associat ed with the rule, with an increas e in long-term jobs annually of 9,000 (with jobs being measured as j ob-years, or 1 year of employmentfor one full-time worker). The range of employment impacts in the long-term is a loss of 15,000 to a gain of 30,000 jobs. Thus, any lay-offs will be smaller than the number of jobs expected to be supported or created from compliance with the rule.

Comment 11: Commenter 17713 believes the EPA’s regulations will significantly impact the cost of all fossil fuels, leading to an increa se in prices of all basic goods, di sproportionately impacting minority populations. The commenter provides statistics showing the percen tage of income spent on food, housing and clothing by minority populat ions in comparison to Whites.

Response to Comment 11: Although there may be increases in pr ice for electricity, natural gas, and coal associated with this rule, it s hould be noted that the increase in electricity price to consumers is less than 4% by 2015, and the increase in natural gas price on averag e from 2015-2030 is less than 1.5%. These estimates are presented in the RIA for the rule. Thus, these in creases are unlikely to significantly affect the prices of basic goods, and are modest when cons idering the substantial benefits from reductions of HAP and other po llutant reductions that this rule is expected to achieve. These benefits will be enjoyed by minoritypopulations, as well as other popula tions, and to a disproportionate extent for those living in th e vicinity of power plants.

Comment 12: Commenter 17713 notes that the combined impacts from increased unemployment, reduced incomes, and increased pric es for housing, basic necessities, en ergy, 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 ru le on energy prices, unemployment, and prices for industries affected by any predicted in creases in energy prices in the RI A for this rule. As stated above, the EPA expects that the impacts of increased electricity prices would be small and would be more than offset by increases in employment and the substan tial benefits from reductions of HAP and other pollutant reductions that this rule is expected to achieve.

3. The EPA met requirements of EO 12898.

Comment 13: Commenter 17766 believes the current rule as written, would si gnificantly protect minority and low-income populations living near co al- 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 Execu tive Orders: Other

Commenters : 15182, 16705, 17295, 17400, 17697, 17710, 17824, 18038, 18433, 18433, 18575, 19042, 19213, 19580

Comment 1: Commenter 15182 requests that the EPA furthe r regulate emissions from power plants to meet the goal of achieving zero emissions of nine critical pollutants (inc luding Hg) by 2020, which the EPA and other signatories established under the Bi national Program to Restore and Protect Lake Superior.

Response to Comment 1: Reductions in Hg and other emissions from this action are modeled for full compliance in 2016. Although this action is neither intended nor required by the CAA to achieve the zero emissions target of the Binational Program to Restor e and Protect Lake Superior , it is a critical step toward significantly reducing overa ll emissions of these pollutants in support of that goal by the year 2020.

Comment 2: Commenter 17751 believes the proposed rule does not adequately comply with EO 13563, EO 12866, the RFA or UMRA. The commenter also be lieves the proposal does no t show the proposed emissions reductions would have substantial benefit, ignores the “dwarfing” pres ence 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 scientif ic knowledge, is duplicative of other regulatory programs, violates the re quirements of the Information Quality Act (IQA), and fails to carry out the requirements of UMRA and EO’s to compare costs and bene fits of altern ative regulatory approaches, includi ng 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 substa ntial benefits (on the order of $50 to over $100 billion). Accounting for ancillary be nefits is standard practice in benefit-cost assessment since these benefits are a consequence of the rule, regardless of the rule’s intended purpose. As such, the EPA estimates all of the anticipated costs and benefits associated with a regulato ry action, to the extent feasible, for the purpose of determini ng the likely impacts, not to justif y 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 be nefits in benefit-cost analysis is directed by OMB Circular A-4.

Comment 3: Multiple commenters (16705, 17295, 17400, 17697, 17710, 18038, 18433, 18575, 19213) request that the EPA evaluate the impact to their utility under the S BREFA, 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 th ese Executive Orders to call fo r reasonable and cost-effective regulations to achieve reduc tions in air pollution in a reasonable timeframe.

Response to Comment 3: The EPA has complied with all applicable statutory and executive order requirements in the preparation of this rulemaking. All utilities that the agency expects will be impacted by this rule have been included in all analyses completed as part of compliance with the applicable statutory and executive orde r requirements. The results of these analyses are contained in the RIA for this rule, in various TSD) prepared for this rule, and the results are summarized in the preamble for this rule. Results of these analyses are available in vari ous 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 an alyses under the cited statutes and executive orders.

Comment 4: Commenter 18575 requests that the EPA revi ew 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 co stly, yet still protective, alte rnatives to the proposed rule.

Comment 5: Commenter 19580 recommends the EPA more cl osely follow the existing requirements for promulgating regulations and actu ally conduct detailed analysis prior to rulemaking. This analysis would include: a review of the EPA’s IQA Guidelines ; a detailed RFA analysis to determine the impact of a regulatory action upon small businesses before certifying that there is no significant economic impact; UMRA analysis to determine the least co stly, most cost-effective, or least burdensome alternative that achieves the objectiv e of the rule; and PRA analysis to determine if OMB approval is needed to meet information collection requirements.

Response to Comments 4 - 5: The EPA is obligated to meet the relevant requirements of the CAA. In doing so, the agency developed control strategies in the proposal that would show how affected EGUs could meet these requirements at least cost to themconsistent with the requirements of the rule. In addition, the agency is mindful of mitigating the cost to society as part of this regulatory effort and completed economic impact analyses for this rule th at examined the impacts not only to the electric power sector but to sectors outside of the power sector. These analyses are in the RIA for the rule. The agency also completed analyses and consultations incompliance with the stated Executive Orders; the OMB and other federal agencies reviewed these analys es and was aware of the consultations. All of the analyses are in the RIA and in ot her 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 limite d transparency and no Congressional and industry scrutiny, promulgated a complex scheme of Executive Orders, reports, scorecards, and associated documents that assert implementation of various environmental regulations will reduce costs to the federal gove rnment and industry without any supporting analytical regulatory documentation. The commenter notes several sustai nability goals identified by EO 13514 and imposed by the CEQ, noting that as a result of the proposed U tility MACT standards, utility costs will increase within the federal budget, obviating any potential savings claimed by the Obama Administration due to implementation of EO 13514.

Response to Comment 6: In adopting today’s final rule, the EPA has complied with the statutes and all relevant executive orders, and has provided extens ive documentation in support of its technical and economic analyses. To the extent that the commente r is questioning other actio ns taken by the Executive Branch, this comment is outside the scope of this rulemaking.

Comment 7: Several commenters (19536, 19537, 19538) maintains that because endangered, threatened and other protected species have been documented with high levels of Hg, and the livelihood and reproductive success of these creatures can be affect ed by this and other hazardous pollutants, the EPA is required to consult with the appropriate agencies to determine the levels at which emissions need to be set not only as required under the Endangered Species Act (ESA) secti on 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 generally agrees that such sp ecies are threatened by high levels of Hg and other HAP and that actions to reduce those le vels is appropriate. However, the commenters are incorrect in their assertion that the EPA must conduct an ESA consulta tion in this acti on. 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 pro cess under CAA section 112(d). Sierra Club V. EPA , 353 F.3d 976, 992 (D.C. Cir. 2004).700 CHAPTER 8: RULE L ANGUAGE CORRECTIONS

8A - Rule: Definitions (existing)

Commenters : 17174, 17316, 17386, 17402, 17620, 17623, 17648, 17681, 17690, 17715, 17716, 17721, 17725, 17728, 17733, 17754, 17756, 17771, 17775, 17796, 17800, 17801, 17804, 17805, 17808, 17812, 17818, 17821, 17838, 17843, 17846, 17855, 17870, 17878, 17880, 17881, 17904, 17914, 18024, 18025, 18031, 18034, 18425, 18427, 18444, 18483, 18498, 18963, 19040, 19114, 18023

Several commenters requested that the EPA review th e proposed definitions fo r consistency and clarity.

1. Definition of natural gas.

Comment 1: Multiple commenters (17174, 17801, 18483, 17878) request that the EPA review and revise the definition of natural gas to be consistent with the NSPS. For natural gas, the third element of the NSPS definition is excluded in the NESHAP de finition (i.e., “A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additiona lly, natural gas must either be composed of at least 70 % methane by volume or have a gross calorif ic 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 ot her generating units will be subject to the same standards as coal-fired boilers despite the fact they burn substitute natural gas (SNG), which is the same chemically as natural gas. Should such IGCC or othe r generating units remain s ubject to the rule, fuel sampling should be allowed as a comp liance demonstration opti on in lieu of a Hg CEMS or sorbent trap methodology due to Hg being removed from the fuel prior to combustion and the absence of postcombustion Hg controls. If the EPA decides that the definitions should have different scopes and limitations, the reasons for the dive rgent definitions should be clar ified. 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 de finition 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 re visions to the 40 CFR su bpart UUUUU definitions in the final rule so as to be consistent with 40 CF R 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 fu el sampling, and, thus, the issue is moot. Owners or operators of IGCCs will need to perform instrumental monitoring (Hg CEMS or sorbent traps) or quarterly emissions testing for mercury.

Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth’s surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionall y, natural gas must either be composed of at least 70 % methane by volume or have a gross calor ific value between 950 and 1100 Btu per standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, bl ast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur conten t or heating value.701 2. Definition of EGU.

Comment 2: Several commenters (17620, 17316, 17805) request that the EPA clar ify in the final regulations what the “25 MW” in EGU definition references. Commenter 17316 questions whether the 25 MW EGU threshold refers to th e power supplied to the grid (i .e., the net MWs) or the power generated by the EGU (i.e., the gross MWs). The commenter indicates that the 40 CFR 60.2 definition of EGU implies that the net MW is of more relevant concern. Similarly, Commenter 17620 recommends that the EPA specify whether the unit can produce mo re than 25 MWe is based on its maximum rated capacity, short-term peak capacity, or if it is based on the unit’s current ability taking into consideration the age of the unit and its thermal efficiency.

Comment 3: Commenter 17805 requests that the EPA clarify that the definition of EGU is assessed by reference to the maximum electrical generating cap acity of the generator th e combustion unit serves. Thermal units, or boilers, are not, from an engine ering standpoint, assigned MW or MWe ratings in design or specification and are onl y known to be assigned to genera tor electric output (i.e., to the generators a boiler serves ). Thus, the thermal capabilities of a co mbustion unit are specified by reference to generator output. The commenter requests that the definition of EG U should therefore be revised as follows:

“Electric utility steam generating unit (EGU) means a fossil fuel-fired combustion unit serving a generator of more than 25 megawa tts (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 poten tial electric output capaci ty and more than 25 MWe output to any utility power distribution sy stem for sale is considered an electric utility steam generating unit.”

Comment 4: Commenter 18425 states that the definiti on 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 act ually producing 25 MWe). The commenter recommends that the definition should be clarified that EGUs will be affected by the proposed rule if they are capable of producing 25 MWe rather than only when they produce 25 MWe during operation.

 It is unclear if cogenerating un its can be classified as EGUs using the first sentence of the definition as it is currently written. The comm enter recommends that the definition specify whether cogenerating units apply.

Comment 5: Commenter 17818 supports the proposed defini tions for fossil fuel, fossil fuel-fired and the specification that an EGU must have fired coal or oil for mo re than 10.0 % of the average annual heat input during the previous thr ee calendar years or for more than 15.0 % of the annual heat input during any one of those calendar years to be consider ed a fossil fuel-fired EGU but indicates that the provision for combusting more than “73 megawatt-elec tric (MWe) (250 million British thermal units per hour, MMBtu/hr) heat input (e quivalent to 25 MWe electrical output) of coal or oil” is confusing. The commenter suggests that it would seem to be more a ppropriate to consistentlyrelate MW thermal as fossil fuel fired heat input rather than MW el ectric (73 MW, or 73 MW thermal, or 73 MWhr/hr).

Comment 6: Alternatively, Commenter 17316 stat es 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 thres hold marker is confusing and 25 Mwalone should be used as the702 applicability threshold in all Sections of the rule for consistency and clarity.

Comment 7: Commenter 17386 states that the definition of “Electric utility steam generating unit” provided in section 63.10042 of the proposed rule seems to include inconsistent designations. The definition suggests the 25 MW thres hold is a gross value for EGUs th at output electricity only (1st sentence) and a net value for EGUs that output steam and electricity (2nd sent ence): “Electric utility steam generating unit means a fossil fuel-fired com bustion 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 po wer distribution system for sale is considered an electric utility steam generating unit.”

Commenter 17386 states that classify ing EGUs based on their gross MW capacity, for EGUs that output electricity also conflicts with th e 40 CFR 60 definition that implies the 25 MW threshold is based on net electrical output, as identified below: “Electric ut ility 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 electri cal output to any utility power distribution system for sale. Any steam supplied to a steam distributi on 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 capacityof the affect ed facility.”

Commenter 17386-A2, therefore, reques ts that the EPA clarif y the rule to identify whether the 25 MW applicability threshold is based on gross electricity generation or net electrical output . The commenter also recommends utilizing the 25 MW net electrical output approach consistent with the 40 CFR 60 definition in all sections of the MACT rule for consistency and clarity.

Comment 8: Commenter 17818 supports the ap plicability cutoff limit of greater than a 25 MWe rating level, but questions the a pplicability of the proposed rule to E GU’s that have an actual “nameplate” rating capacity of 25 MWe or less bu t have actual demonstrated out puts of greater than 25 MWe. Numerous examples of units with nameplate capacity listed as 25 MWe or less have demonstrated summer and/or winter outputs of greater than 25 MWe, as documented in EIA listings. Conversely, the EIA listings also identify EGUs with 25 MWe name plate 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 th e unit from attain ing actual outputs greater than 25 MWe. Units with 25 MWe nameplate rating but have de monstrated generation outputs in excess of 25 MWe may have been under-rated fro m the manufacturer or may have undergone modifications or operating practices that increase the output in ex cess of that anticipated by the generator manufacturer. Commenter believes that th e 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, howe ver clarification is needed to en sure that boilers which provide steam to a generator <25 MW are not consid ered EGU’s under the proposed EGU MACT Rule. Commenter currently owns and operates four units thatburn a combination of biomass, coal, and natural gas. Commenter is in the process of upgrading these facilities in orde r 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 E GU definition in the proposed EGU MACT Rule allows for up to 10 % coal on a 3-year basis, and up to 15 % on a one-year basis, and these units would still qualify as industrial boilers, even though the rated capacity is gr eater than 25 MW per uni t. Two of Commenter’s four biomass units (located at the Hibbard Renewable Energy Cent er) are greater than 25 MW rated capacity of the turbine/generator. Allowance for the us e 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 witha moisture content ranging from 24 % to 65 %. Coal helps to reduce the impact of this variabil ity, resulting in better combustion and increased operational stability.

Commenter 18031 states that because of the sma ll size of these units, the emphasis on renewable biomass generation, and the fact their primary functi on historically has been to provide steam to an industrial process (paper mill), the Hibbard Renewable Energy Center boilers are more properly classified as industrial boilers , not EGUs. Commenter supports re taining the language in the EGU definition that would allow the continued use of coal for start-up and flame stab ilization, and yet classify these boilers as industr ial boilers, not EGUs.

Commenter 18031 states that two of their boilers that burn primarilybiomass 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 industria l boilers, not EGUs. CAA section 112(a)(8) defines an EGU as: “a foss il fuel-fired combustion unit of more than 25 megawatts electric (MWe) that serves a generator that produces electr icity for sale...... “ . ...Since the boilers do not feed turbine/generators greater than 25 MWe, and have a primary purpose of providing steam to a paper mill, they should not be classified as utility boilers. Th ese boilers are more properly defined as industrial boilers, and should fall under the Indu strial Boiler MACT requirements. The definition of an EGU in the final EGU MACT Rule should not require boilers ra ted 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 sectio n 63.9983(c) of the proposed MACT rule references an applicability threshold of 250 MMBtu/hr, with a parenthetical in dicating that this heat input is equivalent to 25 MW. Commenters note th at, 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 thres hold marker is confusing; 25 MW alone should be used as the applicability threshold in all sections of the rule for consistency and clarity.

Comment 12: Commenter 17733 strongly agrees with the prea mble’s statement that units that do not meet the efficiency standards required to be a co generation unit should still qua lify as EGUs if they otherwise meet the definition of an EGU. Otherwis e, owners of coal and oil-fired units would be encouraged to avoid the EGU MACT requirements by reducing their units ’ efficiency. This result would clearly be contrary to the intent of the CAA, and also clearly violat e the EPA’s Trust Responsibility and its obligations under the Environmen tal Justice Doctrine. The commen ter requests that the EPA should make it clear in the final rule that any unit that does not meet the efficiency requirements of a cogeneration unit will still qualify as an EGU if the unit otherwise meets the CAA EGU definition.

Further, Commenter 17733 strongly disagrees with the EPA’s inte rpretation of the CAA section704 112(a)(8) definition “that a non-cogeneration unit must both have a combustion unit of more than 25 MWe and supply more than 25MWe to any utility power distribution system for sale to be considered an EGU pursuant to this proposed rule so as to be consistent with the cogeneration definition in CAA section 112(a)(8).” This inte rpretation is contrary to the plain language of the first sentence of CAA section 112(a)(8). This sentence ma kes clear that an EGU includes “any fossil fuel-fired combustion unit of more than 25 megawatts that serves a generator that produces electricity for sale.” Nowhere does it indicate that a non-cogeneration un it must supply more than 25 MWe to a utility-pow er distribution system for sale to be considered an EGU.

Commenter 17733 states that the EPA’ s narrowing of the definition of an EGU is especially concerning, since it is likely to exclude from the requirements of the EGU MACT Rule many older, less efficient, and dirtier facilities. Owners of these facilities will li kely be incentivized to re duce their electrical output to just below 25 MWe and thereby avoid having to implement more effective Hg controls. This will allow substantially more Hg contamination to occur, and therefore will be inconsistent with the EPA’s Trust Responsibility and the Environmental Justice Doctrine.

Commenter 17733 states that the EPA should make clear that units that fail to qualify as a cogeneration unit will appropriately be considered an EGU if they meet the qualifications in the first sentence of the EGU definition. This would mean that units that do notmeet the efficiency standards for a cogeneration unit are considered an EGU if they are a fossil fu el-fired combustion unit of more than 25 MW, that serves a generator that produces electricity for sale (regardless of whether the generator actually supplies more than 25 MWe to a utility power distribution system). By applying this standard, the EPA can ensure that units that do not meet the cogeneration efficiency require ments are appropriately treated like any other fossil fuel-fired unit. This will allow the EPA to help limit Hg emissions and therefore their impact on Native American communities.

Comment 13: Commenter 17648 states that the EPA has scoped the Toxics Rule properly to apply to EGUs that meet the definition of EGU in CAA section 112(a)(8). The affected sources will all be units with original nameplate rate capacity of more than 25 MW, consistent with the statutory definition of EGUs, thus excluding from the rule relatively small units.

Comment 14: Commenter 17775 supports the EPA’s choice of dates for defining a new EGU.

Response to Comments 2 - 14: The EPA’s interpretation of the st atutory definition of the source category found in CAA section 112(a)(8) (.”..combusti on unit of more than 25 megawatts...”) is that it clearly refers to the size of the combustion unit (i.e., bo iler) rather than to the si ze of the generator. Thus, EPA is not modifying the definition of an EGU such that it relies on the generator size as suggested by some commenters as this would be outside EPA’s authority. We do not interpret the CAA section 112(a)(8) definition to include consideration of the size of the generator for a non-cogeneration combustion unit as long as the combusti on unit itself is greater than 25 MW.

As noted by other commenters, boilers by themselv es do not generate any electricity. The EPA had, therefore, provided for clarity the general heat in put equivalency. However, other commenters indicated that this equivalency would not hold uniformly as a result of differen ces in boiler efficiency. Further, EPA’s stated intent was to use the “nameplate” capaci ty of the boiler (i.e., the design capacity expressed on the “nameplate” affixed to the boiler). Absent su ch a “nameplate,” the boiler size contained in the original permit would serve as the “nameplate capacity.” The EPA has re-evaluat ed its use of the term “MW” and believes the correct interpretation would be “megawatt-thermal,” or MW t (thermal power produced by the combustion unit) as opposed to MW e which is the electric power generated by the705 generator. The EPA has modified the final rule to note only the 25 MW distin ction 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 modi fied) of greater than 25 megawatts regardless of its current operating capac ity. 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 commenterthat we erred in providing the “non-cogeneration” definition and have removed it from the final rule. Further, EP A believes that the statutory definition for noncogeneration units is clear in CAA section 112(a)(8) and in the final ru le, EPA adheres to that definition. However, EPA believes that the commenter has mis understood the provisions of the rule. There are no “efficiency standards required to be a cogeneration unit” included in th e proposed or final rule. There is only the requirement contained in CAA section 112(a)(8) that the c ogeneration unit supply “more than one-third of its potential electric output capacity and more than 25 me gawatts electrical output to any utility power distributio n system for sale...”

The EPA specified in Table 10 of the proposal pream ble that the output-based emission limits (i.e., lb/MWh or lb/GWh) are specified as “gross.” The EP A has made this clarification in the final rule.

4. Definition of cogeneration facility.

Comment 15: Commenter 19040 questions why th e definitions for a cogeneration facility differ in the proposed rule and the Transport rule. The definiti on in the Transport Rule requires the cogeneration system either be a topping-cycle or bottom-cycle unit and the electric sales onto the grid cannot exceed the greater of one-third the name plate capacity or 219,000 MWh per year.

Response to Comment 15: The EPA is operating under different statutory provisions for the CrossState Air Pollution Rule and the Merc ury and Air Toxics Standards. We believe that our definitions in each rule are consistent with th e relevant statutory authority.

5. Definition of “fossil fuel-fired.”

Comment 16: Commenter 17733 supports the EPA’s definiti on 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 firs t sentence of the CAA definition and the EPA’s obligations under the Trust Responsibility and the Environmental Justice Doctrine.

Comment 17: Commenter 17805 recommends thatthe definition of “fossil fuel-fired” should also be revised as follows for consistency:

“Fossil fuel-fired (or cogeneration means a c ogeneration means an electric utility steam generating unit (EGU) that is capable of combusting sufficient fossil fuel more than 73 MWe (250 million Btu/hr, MMBtu/hr) heat input (equivalent to 25 MWe output of fossil fuels to generate 25 MWe from such fuels al one. To be ‘‘capable of combusting’ ‘ fossil fuels, an EGU would need to have these foss il 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 c onveyers, pulverizers, etc.; oil st orage facilities). In addition, fossil fuel-fired means any EGU that fire d fossil fuels for more than 10.0 % of the average annual heat input during the previous 3 calendar years or for more than 15.0 % of706 the annual heat input during any one of those calendar years.”

Commenter 17880 also recommends this propo sed definition of fossil-fuel fired.

Comment 18: Commenter 17796 recommends that the EPA revi se the definitions for “fossil fuel” and “fossil fuel-fired steam generating unit” to be consistent with the defi nitions of subpart D.

Comment 19: Commenter 17818 states that the definition of “fossil fuel-fired” units should be refined to reduce confusion and inconsiste ncies. The commenter provides seve ral 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 appropri ate to relate MW thermal as fossil fuel-fired heat input rather than MW electric.

Response to Comments 16 - 19: As noted in the preamble to the final rule, the EPA has made some changes to the definition of “foss il fuel-fired” in the final rule; we believe the final definition to be consistent with the statutory defi nition in CAA section 112(a)(8). Inaddition, as noted elsewhere, the EPA has clarified its use of the term “MW” a nd has removed the than 73 MWe (250 million Btu/hr, MMBtu/hr) equivalency term.

Comment 20: Several commenters indicated that the definiti on of “fossil fuel-fired ” did not adequately account for fuel switching and would require permit revi sions to eliminate any mention of using coal or oil to produce electricity and th e removal of all coal handling equipment, coal storage areas.

Comment 21: Commenters 17756 and 17775 state that the defi nition of “fossil fu el-fired” EGUs may potentially discourage natural gas and biomass conve rsions which require “bri dging 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 handl ing equipment on site ther efore the unit would be subject to the proposed Toxics Rule. The commenter requests that the EPA revise the definition of “fossil fuel-fired” EGUs.

Comment 22: Commenter 18023 requests that the EPA update the definition of “fo ssil fuel-fired” to adequately account for fuel switchin g as a potential compliance strategy.

Response to Comments 20 - 22: The EPA does not agree with the commenters and we are not revising that aspect of the definition of “fossil-fuel fired.” The EPA does not agree th at sources will have to dismantle all their fossil-fuel handling systems and revise their Title V permits to prohibit fossil-fuel combustion above a certain threshold, though either appr oach may be independently sufficient to make a source incapable of combusting sufficient fossil fuel to meet the definition of “f ossil-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 duri ng any one calendar years after the applicable compliance date. The EPA believe s the definition provides flexibility for sources while simultaneously preventing sources from impr operly avoiding regulation. E GUs that want to use fuel switching as a compliance strategy should include in their Title V permit pr ovisions that preclude being coal- or oil-fired EGUs.

Comment 23: Commenters 18023 and 17775 state that the “l ook-back” period may potentially penalize a unit that retains capability to comb ust 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 define707 an affected unit by whether it actually has heat input exceeding the stated thresholds. A unit that, beginning on the effective date, fires less than 15 % coal or oil on an annual basis (and less than 10 % on a triennial basis) would not be cons idered “fossil fuel-fired” and woul d not be considered an affected facility. Under this scenario, a unit that switches to natural gas and retains its capability to combust coal or oil would not be penalized for burning coal or oil during the time period before the effective date.

Comment 24: Commenter 17775 recommends that the EPA shoul d revise the definition to change the “look-back” period to begin 3 years after the unit’s final compliance date so that it does not penalize a unit for having burned coal or oil in the period befo re compliance or for switching to natural gas but retaining the ability to combust co al or oil (a desirable outcome to provide system reliability). The commenter further states that unit owners would need to convert th e unit to 100 % biomass or natural gas within 3 years and remove all cap ability to burn coal or oil in or der be exempt from the EGU MACT rule. Alternatively, the unit could convert to bioma ss or natural gas by 2012 and ensure that the heat input from coal or oil in 2012, 2013 and 2014 is below the annual 15 % heat input requirement and the 3-year requirement of 10 % heat input. Commenter 17775 also requests that the EPA clarify that a unit that switches to natural gas and later switches back to highly controlled co al use would not be in violation of the 3-year average for the years it was bur ning 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 belie ve will address this comment. Further, a Title V permit modification that prohibits the combustion of coal or oil w ould 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 elec tric steam generating unit.”

Comment 25: Commenter 17805 recommends that the defini tion of “oil fired electric steam generating unit” should be revised as follows for consistency:

“Oil-fired electric utility steam generating un it means an electric utility steam generating unit that either burns o il exclusively, or burns oil alternately with bur ning fuels other than oil at other times. In addition, oil-fired mean s any EGU that fired oil (or more than 10.0 % of the average annual/teat i nput during the previous 3 calend ar years or (or more than 15.0 % of the annual/teat input during any one of those calendar years.”

Comment 26: Commenter18024 submits that the EGU MACT Rule should exclude the fuel input associated with complying with state reliability re quirements from the heat input calculation for the liquid oil-fired unit subcategory. Co mmenter requests that the EPA a dd the following language to the proposed definition of “units” de signed to burn liquid oil fuel:

“Units designed to burn liquid oil fuel s ubcategory includes any EGU that burned any liquid oil for more than 10.0 % of the average annual heat input duri ng 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 combinati on with gaseous fuels, provided, however, that liquid oil burned during the three calendar year period to meet state reliability requirements shall be excluded fr om the heat input calculation.”

Alternatively, Commenter18024 would support changi ng the applicability definition for “units” designed to burn liquid oil fuel from> 10 %/15 % of actual heat input to >30 % of actual heat input (3- year rolling average). Based on hist orical operation, the commenter be lieves that 30 % oil firing at a708 facility would be sufficient to prov ide needed reliability in conformanc e 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 emissi ons averaging. The proposed regulations state that emissions averaging can only be used for units within the same sub category at the same location, and under the common control of th e same person. But, as the fuel use of the dual-fueled units is managed at the site to meet the requirements of averaging, there is the risk that an individual dual-fueled EGU at the site may use more than 85-90 % natural gas, and therefore may no longer meet the definition of “oilfired EGU.” If a unit does not meet the definition of “o il-fired EGU” then, it is ineligible to be used in the averaging strategy.

Response to Comments 25 - 27: As stated in the preamble to the final rule, the EPA is establishing a limited-use liquid oil-fired EGU subcat egory and sources in the subcate gory will be required to comply with work practice standards. See the pream ble for specific responses to the comments.

7. Definition of “coal-fired electr ic utility steam generating unit.”

Comment 28: Commenter 17805 recommends that the definiti ons of “coal-fired el ectric utility steam generating unit” should be revise d as follows for consistency:

“Coal-fired electric utility steam genera ting unit” means an el ectric 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 i nput 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 th e definitions to clearly state that the emissions standards applicable to coal-fired units also apply to any EGU using any amount of coal or coal refuse, whether blended with other fuels or burning both coal and petcoke . The commenter states that although the preamble contains the appropriate language, the defini tions for each subcategory could be interpreted differently if read separate from the preamble. The commenter recommends that the final rule clearly specifies that the standards for coal-fir ed units apply in cases wh ere 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 gene rating unit.” We believe this is appropriate to be consistent with the definition of “fossil-fuel fired. ” We are making a similar ch ange to the definition of “oil-fired” EGU and adding a definition for “natural gas-fired” EGU. We think these definitional changes provide clarity to the approach we propose d. In addition, EPA has revised the definitions to make clear that a unit is not an oil-fired EGU if it meets the definiti on of “coal-fired EGU.”

Comment 30: Commenter 17868 disagrees with the EPA’s deci sion not to include petcoke in the coal subcategory and urges EPA to revi ew UARG’s comments on the subject.

Comment 31: Commenters 17623 and 18034 recommend that th e coal subcategorization definitions should be reviewed and revised for clarity.

Comment 32: Because the EPA chose not to subcategorize ba sed on coal rank or liquid fuel type (i.e.,709 No. 2/ No. 6), Commenter 17881 believ es that fuel type should corres pond to the subcategory definition. As long as the emission limits are being met fo r 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 base d on the subcategory definition, not on fuel types, and the onus is on the facilityto demonstrate compliance.

Response to Comments 30 - 32: The EPA generally agrees with th e 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 provide s 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 subcat egorization definitions be based solely on fuel heat content design criteria. Alternatively, the EPA should provide a definition of height-to-depth ratio to avoid misinterpret ation regarding applicability of coal un its since some investigators not have the necessary information to verify the proper categor ization of a unit. The commenter further suggests that may create an inadvertent loop-hole in the rule if a unit is designed to bur n coal with heat content greater than 8,300 Btu/lb and a he ight-to-depth ration greater than 3.82, and therefore would not be subject to the emission limits.

Comment 34: Commenter 17914 states that it is the fuel properties that impact the potential Hg emissions rate and submits that they have designedand 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 dire ctly from Figure 19 of Chapter 20 in, “Steam/its generation and use,” 40th Edition but st ates that the dimensions are illu strative only and do not reflect a firm design criteria. The commenter respectfully questions the signi ficance of the boiler dimensional criterion as a condition for establishing the Hg emi ssions limit for an existing EGU and states that an arbitrary limit on HID may actually prohibit a designe r 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 de fining 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 simplychanging their fuel source and does not make clear that the 3.82 height to depth ratio applies to the EGU furnace and not the EGU as a whole. The commenter requests that the EPA revise the rule’s definition to limit the subcategory to “any EGU designed to burn only [lignite coal] in an EGU with a hei ght-to-depth ratio of 3.82 or greater.”

Response to Comments 33 - 35: The EPA does not believe it appropriate to base the subcategorization solely on the fuel heat content. However, the EPA ha s revised the definition of the subcategory to more adequately define the subcategory without precludi ng 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 36: Multiple commenters (17754, 17855, 17812, 17838, 18963, 17804) recommend that the definition of coal refuse be reviewed and updated to account for the documented and inherent variability of the fuel source. The commenters note that the defin ition of “coal refuse” in th e proposed rule contains710 additional qualifying language that requires materi al to exhibit “ash content greater than 50 % (by weight) and a heating value less than 13,900 kilojoul es per kilogram (6,000 Btu per pound) on a dry basis to be defined as coal refuse.” Therefore, mu ch of the coal refuse combusted would not meet the applicable definition because it would not satisf y the applicable ash content and heating value criteria. The commenters requests that the EPA revise the definition of “coal refuse” under the proposed rule by eliminating the restrictions on heating value and ash conten t 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 faciliti es, although we believe it is the EPA’s inte nt that these plants be regulated as EGUs under this rule. Similarly, Commenter s 17754, 17838 and 18963 question how a unit combusting coal refuse that does not satisfy the definitions under the proposed rule of either coal refuse or coal would be classified, and whether itwould therefore effectively avoi ding regulation under the proposed rule altogether. The commenters further state that the heating value and ash content within the proposed definition of “coal refuse” are inconsistent with th e EPA’s clear recognition in the preamble to the proposed rule of the environmental benefits a ssociated with the combustion of coal refuse.

Comment 38: Commenter-17812 states that waste- coal plants that are classi fied as Qualifying Facilities either as Independent Power Pr oduction Facilities or Cogeneration Facilities burning waste-coal had their fuel supply certified by FERC. The commenter refers to the preamble and its reference to the NHSM rule that currently-mined coal refuse should not be considered a solid waste under the Resource Conservation and Recovery Act (RCRA), as long as it is not discarded. The NHSM rule further states that the coal refuse would be subj ect to the Utility MACT regulation, if the unit meets the definition of EGU. The commenter indicates that the definition of coal refuse should be revi sed 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 Co mbustion Rule. In February of 2011, the EPA determined that unless processed coal refuse is di scarded, it cannot be consid ered solid waste under the Non-Hazardous Solid Waste Definition Rule.

Response to Comments 36 - 39: The EPA has revised the definition of “coal refuse” to be consistent with the definition found in 40 CFR subpart Da. The EPA believes that the definition of “Coal-fired electric utility steam generating unit” already clearly states that coal refuse is a covered fuel. Units burning coal refuse and not meeting the definition of anEGU in the final rule w ould likely be subject to the Industrial Boiler NESHAP (40 CFR Part 63, subpart DDDDD).

Certification of a fuel by FERC or any other body does not supersede the appropriate definitions applicable to CAA section 112. EGUs burning a coal refuse meeting th e definition of a “solid waste” under the NHSM rule would be subject to standards issued pursuant the CAA section 129 (e.g., the final CISWI rule); however, we did not identify in the propos ed rule any EGUs that are burning coal refuse that is a solid waste. Furthermore, no units indicated in comments that they are burning coal refuse that is a solid waste so all units that meet the definition of EGU and combus t coal refuse are subject to this final rule.

9. Definition of fossil fuel.

Comment 40: Commenter 18427 requests that the EPA revise the definition of “fossil fuel” in the proposed Utility MACT as follows:711 “Fossil fuel means natural gas, oil, coal a nd any form of solid, li quid, or gaseous fuel derived from such material for the purpose of creating useful heat.”

The commenter states that there is no justifiable ba sis to define the term “fossil fuel” meaningfully differently under the two relevant regulatoryprograms, both of which apply to fossil fuel

‐ fired electric utility steam generating units. Further, revising the definition of fo ssil fuel under the proposed Utility MACT in this manner will ensure consistent applicat ion of the applicable regulatory standards to these units.

Further, the commenter requests thatthe EPA clarify within subpart Da and the proposed Utility MACT that the definition of “fossil fuel ” does not include landf ill gas, biogases or other materials such as engineered fuels that are produ ced 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 pres ented by the definitions included in the proposed rules as drafted because both the pr oposed Utility MACT and the proposed revision to subpart Da define and use the term “gaseous fuel” (which is contained within the definition of “fossil fuel”) to encompass a broader category of fuels than fossil fuels.

The commenter also requests:

 EPA clarify in the context of the proposed rules that neither subpart Da nor the proposed Utility MACT would apply to a unit which exclusively or primarily combus ts a “gaseous fuel” that is not otherwise a fossil fuel.

 EPA clarify the circumstances under which a non

‐ fossil gaseous fuel

‐ fired unit may be affected by the proposed rules.

 To the extent that use of a non

‐ fossil gaseous fuel may be c overed under subpart Da or the proposed Utility MACT under certain circumstances , the proposed rules should be clear with respect to the manner in which such non

‐ fossil gaseous fuels may be affected.

Response to Comment 40: Some fossil fuels in current use atEGUs (e.g., petroleum coke) were not derived for the purpose of creating us eful heat. Therefore, including this phrase in the definition as commenter suggests would preclude coverage of anEGU burning pet coke under the final rule unless the unit blended the pet coke with coal such that the unit met the definiti on of “coal-fired electric utility steam generating unit.” The EPA rec ognizes that there may be differenc es in the definition of “fossil fuel” among the different regulato ry actions, but we have determin ed that byproducts of fossil fuels should be regulated for HAP in the same manner as raw fossil fuels because the fuel-borne HAP content is the same as the raw fuel, regardless of whether there was an intent to create the byproduct for the purpose of creating useful heat. For example, pet c oke contains the same fuel borne HAP as the raw fossil fuel from which it is derived (i.e., oil). In ad dition, although pet coke is a byproduct of oil refining, it is also currently recognized as a valuable fuel commodity, which was not the case when the 40 CFR Part 60, subpart Da definition was promulgated. Fo r these reasons, we are retaining the proposed definition.

The EPA believes that the definitions are sufficiently clear that only fossil fuels, or fuels derived from fossil fuels, are covered under the final rule. Materials noted by the commenter (e.g., landfill gas, biogases, materials derived from municipal solid wast e) are, in EPA’s opinion, clearly not derived from “fossil fuel” and, thus, not covered un der the final rule. “Gaseo us fuel” in the definition of “fossil fuel” is clearly linked to fossil fuels through the “derived from” phrase. The EPA does not believe that there is any confusion in the definition.712 10. Definitions of miscellaneous terms.

Comment 41: Several commenters note inconsistent de finitions for operating limits. Commenters 17716 and 18498 state that the PM operating limit is de fined 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 perf ormance test in Table 4. The commenters suggest that the inconsistency should be eliminated by usi ng a filterable PM (FPM) limit as a surrogate for nonHg metal HAP instead of total PM (TPM). However, if a PM operating limit is used, the inconsistency between sections should be reviewed and corrected.

Response to Comment 41: The comment is moot because rule nowallows compliance with filterable, not total, particulate matter (PM).

Comment 42: Commenter 17800 states that the EPA provide s 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 si te-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 flexibility to account for changes in unit ope ration. Furthermore, the commenter requests that the EPA provide data to support achiev ability or enforceability of operating parameters under the final definition.

Response to Comment 42: This comment is moot because rule no longer requires parameter monitoring or operational limits for pollution control devices.

Comment 43: Commenter 18444 supports limiting emissions of total filterable and total condensable PM and therefore recommends that the PM definition in the proposed rules incl ude the sum of the total filterable and total condensables.

Response to Comment 43: As explained elsewhere, the rule now us es 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 revise the definition of an operating day to be consistent with the NSPS. Specifically, the commenter suggests that the definition of an operating day’s worth of data in section 5.2. 1, Sorbent Trap Mon itoring Systems, should include no less than 18 hours of valid data rather than only 15 minutes.

Response to Comment 44: The commenter’s suggestion to establish a minimum data collection period that would constitute a boiler operati ng day is inconsistent with the Agency’s view that data collection, as well as emissions control de vice operation, needs to occur duri ng each period of unit operation,713 regardless of the duration. The rule maintains require ments to operate the monitoring system and collect data at all required intervals at all times that th e affected unit is operatin g, except for periods of monitoring system malfunctions or out-of-control pe riods and periods of mon itoring quality checks, and to use all data collected outside these periods in assessing continuous compliance.

Comment 45: Commenter 17681 requests that the EPA clarif y the definition of a “30 Operating Day Rolling Average” as well as the methods used to cal culate the average. Comme nter requests that the EPA clarify that a 30-operating day is based on the av erage of all applicable hours in the 30-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 a ll the hourly values calculated over 30 previous, consecutive boiler operating days . The equation is as follows:

ൌ ܽ݃݁ݎ݁ݒܽ ݈݈݅݊݃݋ݎ ݕ݀ܽ ݅݊݃ݐܽݎ݁݌݋ ݎ݈݅݁݋ܾ 30 1
30 ܽ݃݁ݎ݁ݒܽ ݕ݈ݎݑ݋݄ ෍
௞ ଷ଴

௞ୀଵ
where k = individual hourly average over prev ious 30 days on which fuel was combusted

. The rule contains a definition of boiler operati ng day in section 63.10042 and the equation in section 63.10021(b)(3).

Comment 46: Commenter 17721 requests that the EPA revi se 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 m easured according to Table 7 to this subpart during the most recent performance test de monstrating compliance with the applicable emission limits.”

Response to Comment 46: This comment is moot because rule no longer requires monitoring of the sorbent injection rate.

Comment 47: Commenters 17801 and 17821 recommend that th e EPA modify the proposed definition (p. 25123) of gross output as follows:

“Gross output means the gross useful work pe rformed by the steam generated and, for an IGCC electric utility steam generating unit, the work performed by the stationary combustion turbines. For a unit generating only electricity (including IGCC), the gross useful work performed is the gross electrical output from the unit’s turbine/generator sets (including steam turbines) . For a cogeneration unit, the gr oss useful work performed is the gross electrical, includi ng any such electricity used in the power production process (which process includes, but is not limite d to, any on-site emission controls), or mechanical output plus 75% of the useful thermal output measured relative to ISO conditions that is not used to generate addi tional electrical or m echanical output or to enhance the performance of the unit (i.e., st eam delivered to an industrial process).”

Response to Comment 47: The EPA has modified the definiti on in the final rule as follows:

Gross outputmeans the gross useful work performed by the steam generated and, for an714 IGCC electric utility steam generating unit, the work performed by the stationary combustion turbines. For a unit generating on ly electricity, the gross useful work performed is the gross electrical output from the unit’s turbine/generator sets. For a cogeneration unit, the gross usef ul work performed is the gr oss electrical, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any onsite emission controls), or mechanical out put plus 75 % of the useful thermal output measured relative to ISO conditions that is no t used to generate a dditional electrical or mechanical output or to enhan ce the performance of the unit (i.e., steam delivered to an industrial process).

Comment 48: Commenters 17801and 17821 recommend modifyi ng the definition of Heat Input (p. 25,123) as follows: “Heat Input means heat derived from combustion of fuel in an EGU (synthetic gas to the combustion turbine for IGCC) and does not include the heat input from...” This will help avoid any confusion or inconsistent applicati on of using coal in lieu of syngas as the basis for any values based on heat input.

Response to Comment 48: The EPA has modified the definiti on in the final rule as follows:

Heat inputmeans heat derived from combustion of fuel in an EGU (synthetic gas for an IGCC) and does not include the heat input fr om preheated combusti on air, recirculated flue gases, or exhaust gases from other sour ces such as gas turbines, internal combustion engines, etc.

Comment 49: Commenter 17821 supports the rule’s proposed definition for fuel type, specifically agreeing that receiving fuel from different suppli ers does not constitute a change in fuel type.

Response to Comment 49: The EPA appreciates the commenter’s support. The EPA has made revisions to certain definitions as discussed elsewhere to provide clarity in the final rule.

Comment 50: Commenter17402 suggests that the EPA’s defi nition of “deviation” is too broad and results in excessive infeasible re porting requirements. The commenter recommends that operating limits and monitoring requirements should not be include d in the definition. Additionally, the commenter recommends that any notification of exceedances s hould be reported in semiannual compliance reports rather than the current propos ed notification schedule.

Response to Comment 50: Even though the agency disagrees with the commenter’s view, a rule change to drop almost all operating limits and control de vice 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 establishe d by unit owners or operators by choice for non-mercury metals monitoring and for fuel oil moisture monitoring for hydrogen halides will remain. The EPA has modified the definition of “deviation” in the final rule as follows:

Deviation. (1) Deviation means any instance in which an affected source subject to this subpart, or an owner or operator of such a source: (i) Fails to meet any requirement or obligati on established by this s ubpart including, but not limited to, any emission limit, operating limit, or work practice standard; or (ii) Fails to meet any term or condition th at is adopted to implement an applicable715 requirement in this subpart and that is in cluded in the operating permit for any affected source required to obtain such a permit. (2) A deviation is not always a violation. The determination of whether a deviation constitutes a violation of the st andard is up to the discretion of the entity responsible for enforcement of the standards.

Comment 51: Commenter 17838 states that the definition of FGD creates confusion because the first sentence of the definition app ears to state that any dry FGD t echnology shall require an “add-on air pollution control system located downstream of the steam generating unit.” In order to avoid the potential inconsistency between th ese two sentences of the definiti on, the Commenter recommends that the EPA revise the definition of FGD to expressly st ate in the second sentence th at the sorbent injection system in a CFB boiler need not be a separate add- on air pollution control system located downstream of the steam generating unit.

Response to Comment 51: We believe that the last sentence of the definition (“Sorbent injection systems in fluidized bed combustors (FBC) or circ ulating fluidized bed (CFB ) boilers are included in this definition.”) clearly indicate th at the Agency considers CFB to be a “dry flue gas desulfurization technology.” However, we have made a minor edit to th e definition to indicate th at 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 co mbustion” to avoid a situation wher e 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 technol ogy. This lengthening of tim e better coincides with routine boiler inspections and shoul d alleviate the commenter’s con cerns 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. S ection 63.10021(a)(16)(iv) includes a subjective requirement to “optimi ze” total emissions of CO and NO X per manufacturer’s specifications, but the commenter argues that the term needs to be defi ned so that it is not interpreted as “minimized” or “balanced” by future facilities seeking compliance. The commente r suggests that an operational definition should aim to yiel d reduced CO levels and comply with applicable NO X limits throughout the normal range of operation and suggests that manufacturer s’ recommendations, if available, could be of considerable assistance in developing the definition.

Response to Comment 53: The EPA recognizes the economic dr ivers behind optimal combustion of fuel to maximize output while minimizing fuel cost s, 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 type affected. We e xpect 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 ha ve also added incentives for units that employ neural net combustion optimiza tion systems during hours of normal operation.

Comment 54: Commenter 17728 indicates that the defini tions for major and area sources are716 inconsistent within section 112(a). The section defines major and area so urces as any “stationary source located within a contiguous ar ea and under common control.” The s ection also declares that the “stationary source” term is defined in CAA section 111(a), stating that “any building, structure, facility, or installation which emits or may emit any air pollutant.”

Response to Comment 54: The EPA did not provide definitions for “major source” or “area source” within the final preamble. Instead, EPA relies on th e 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 commenters (17760, 17718, 17808, 18025) recommend new definitions with regard to oil-fired units to ensure that applic ability is capacity-based. Commenter 17760 and 17718 state that the EPA should adopt the term “oil-affected units” to address oil- fired and oil- a nd gas-fired units that have low capacity factors on oil fuel usage. Inthe proposed rule, the defi nition determines whether a unit that combusts oil is an affected unit ba sed on the percentage of oil combusted by the unit compared to its total heat input. Because the exclus ion is based on a fuel co mbustion ratio, a unit that operates for only two days (one on oil, one on gas) could be subject to the proposed rule, and a unit that combusts the same quantity of oil as the first unit but operates for multiple days on gas to be excluded. Such an arbitrary result is possibl e given the current operating practices for oil and oil/gas units. Since the promulgation of the Acid Rain Program regulati ons in 1993, the operation of oil- and oil/gas-fired units has changed significantly. A large fraction of these units are no longer base load units, and typically operate at capacity fact ors well below 50 %. In many cases, th e 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-aff ected unit (an oil-fired unit that is subject to the EGU MACT rule) as:

“A unit that had a three-year average oil he at input greater than 10 % of the maximum potential annual heat input, calculated by multiplying the maximum design heat input by 8760. This definition would ensure that the E GU MACT rule targets EGUs with greater HAP emissions from the combustion of oil, and address EPA’s concerns regarding limited use oil-fired units, which typically operate at very low capacity factors.”

Response to Comment 1: As noted elsewhere, the EPA has modifi ed the definition of “oil-fired” EGU. A discussion of the limited use issue is pr ovided elsewhere in the final rule record.

Comment 2: Commenters 17808 and 18025 request that the EPA adopt a definition for a limited-use oil-fired EGU, which is any boiler that burns any am ount of liquid oil, has a rated capacity of greater than 25 MW, and has an annual average capacity fact or based on its oil use of 10.0 % or less over the past 3 years (and not more than 20.0 % in each of those 3 years). The commenters recommend this definition it reflects the varying lo ads of an EGU and is precedente d in Part 75. The commenters also suggest that that ”capacity factor” is the ratio of the unit’s actu al 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 meet s its emissions limits but may have individual dualfired units which do not meet the o il-fired EGU definition. Currently, th e source owner may be forced to operate the EGU on oil just to maintain the EGU’s oi l-fired status and eligibil ity for inclusion in the averaging calculation, resulting in additional emissions with no compliance benefits. In fact, based on the amount of oil-firing needed, the site’s emissions average may incr ease 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 averagi ng, the subcategorization for in dividual 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 sha ll be based on the total oil-fired heat input divided by the total heat input from all fuels fr om the affected EGUs An Oil-fired facility shall have an average annual heat input on o il more than 10.0% for the 3 calendar years prior to the effective date of the regulati ons or more than 15.0 % for any single year within the thr ee-year period.”

The commenter states that this definition encourag es the use of lower emitting fuels through emission averaging but does not limit compliance options or require mandatory oil-firing to maintain an EGU’s oil-fired status.

Response to Comment 3: As noted elsewhere, the EPA has modifi ed 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 pr ovides 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 Appe ndix A explicitly states that the certified flow rate, diluent gas, and moisture monitoring systems that are used to convert Hg concentrations to units of the standard must be installed, certified, operate d, maintained, and qualityassured according to 40 CFR Part 75. Th is is reinforced by §§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 agency agrees with the commenter, and, as part of its review to reduce burden and costs, decided to bett er integrate MATS monitoring requi rements with those of the Acid Rain program. As a result, and as mentioned elsewh ere, 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 comme nter believes the steam generati ng unit language is intended to address integrated gasification fuel cells, the wood products industry co mmonly uses the term fuel cells to refer to biomass combustion devices.

Response to Comment 6: Fuel cells as noted by commenter would not be EGUs under the final rule as they are biomass-fired and, thus, not fossil fuel-fired.

Comment 7: Commenter 17721 proposes that the EPA add the following definition of DLPS to section 63.10042 of subpart UUUUU of the proposed rule (page 25121):

“Dual liquid powder sorbent injection (DLPS) is an Hg-control technology where a liquid sorbent is added onto the coal before combus tion and a powder sorbent is mixed with the coal, injected into the furnace, or is duct inj ected. 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 thatthe following language be added to the proposed rule to expressly authorize or at least recognize DLPS systems as available emissions control technology:

 (at the fourth-to-last sentence in section III.D.6.c, which appe ars on page 25014 of the proposed rule) “Hydrogen chloride and HF have also been shown to be effectively removed using DSI where a dry, alkaline sorbent (e.g., hydrated lime, trona, sodium carbonate) is injected upstream of a PM control device, or when powder sorbents such as those used in a dual liquid-powder sorbent system are combined with coal or in jected into the fireba ll of the furnace.”

 (at the second-to-last paragraph in secti on III.D.6.c, which appears on page 25014 of the proposed rule) “The use of halogen additives in combination with powde rs containing calcium and aluminosilicates leads to significant reduction of SO 2 as well as nearly complete control of emitted Hg. A dual liquid-powder sorbent (“DLPS”) system consists of adding an aqueous solution of a halogen, especially a bromine compound, onto the coal upstream of the furnace. Then a powder sorbent containing calcium and al uminosilicates 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 th e Hg and other HAP metals in a microencapsulated non-leaching form in the ceramic matrix of the coal ash remaining from combustion. Such methods are in commercial use and perform well with high sulfur coals, as it provides for sulfur removal as well. An additional advantage is that the Hg an d other HAP metals are bound tightly in the fly ash so that they do not leach from the ash dur ing storage or reuse, including during reuse in concrete.”

 (after the sentence beginning “Ac tivated carbon injection is the most successfully demonstrated Hg-specific control technology,” in section D.8.c, which appear s on page 25017 of the proposed rule) “On the other hand, the effectiveness of the dual liquid-powder so rbent (“DLPS”) system 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 follo wing 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 dissocia tion constant (i.e., HCl is a strong acid) and it, thus, will react easily in an acid-base reacti on with caustic sorbents (e.g., lime, limestone), including the powder sorbent co ntaining calcium and aluminosilicates used in the Chem-Mod DLPS system.”

 (at the first sentence in secti on 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 so rbent 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 sec tion IV.J.1.(3), which appears on page 25031 of the proposed rule) “For units with dry scrubbers, DSI systems, or DLPS systems we are proposing that you continuously monitor the sorbent injection or ad dition rate and maintain it at or above the operating limits established dur ing the performance tests.”

 (following sentence in section V.K., which appe ars 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 scru bbers, DSI systems, and DLPS systems.”720  (following sentence in section V.M., which appears on page 25054 of the proposed rule) “This includes technologies to contro l acid gases (wet and dry scrubber technology and the use of sorbent injection), the Hg requirements (co-benef its from other controls such as scrubbers and FFs and Hg-specific controls such as ACI a nd DLPS), the non-Hg metal requirements (upgrades and or replacements of existing particulate c ontrol devices), and other HAP emissions (GCP).”

 (following sentence in section V.M., which appears on page 25054 of the proposed rule) “For Hg, EPA projects that companies will comply th rough the collateral reduc tions created by other controls (e.g., scrubber/SCR combin ation), ACI, or DLPS technology.”

 (In section 63.10011(b)(6)(iv), which appears on page 25114 of the proposed rule) “For a dry scrubber, dry sorbent injection (DSI) system, or dual liquid-powder sorbent (DLPS) system, you must establish the minimum hourly average sorbent in jection or addition rate for each sorbent, as measured during the three-run performance te st and as defined in §63.10042, as your operating limit.”

 (In section 63.10022(a)(4), which appears on pa ge 25118 of the proposed rule) “For each existing unit participating in the emissions averag ing option that is equipped with dry sorbent injection or dual liquid-powder so rbent injection, maintain the 3-hour averag e parameter values at or below the operating limits established during the most recent performance test;”

Response to Comment 7: The agency reviewed the changes s uggested by the commenter, and, apart from adding “or other sorbent inject ion system” to the description of dry sorbent injection, did not make other changes. The Agency notes that the proces s 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 th at the CEMS must operate at all times that the affected EGU is operating. The commenter recommends that the defi nition should clarify whether operating will include times when the unit is combusting fuel , or only include times when the unit is producing electricity, or if operating includes when the boiler fans are being opera ted (i.e., ID and FD fans), and will it include startup, shutdown, malfunction, mainte nance, and/or offline periods.

Response to Comment 8: The comment is moot because rule’s definition of the term boiler operating dayalready describes operation as being the period when fuel is combusted at any time.

Comment 9: Commenter 17696 requests that the EPA creat e an explicit definition for the ”maximum normal operating load” at which performance te sts would be required to be conducted under 63.10007(c). The commenter suggests that defining the te rm will minimize variations in implementation and recommends that the term be defined as”90-100 % of the unit’s reported maximum load as identified in EPA’s Emissions Collection and Monitoring Plan System (ECMPS) or EIA-767.”

Comment 10: Commenter 17881 notes that the term “normal load” is not defined in either Part 63 subpart UUUUU or its associated appendix A. For purpos es 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 potentia l confusion and provide needed flexibility for infrequently operated units (i.e., peak ing units), in which case the normal operating load may vary widely.

Response to Comments 9 - 10: The agency reviewed the commenters’ concerns, and the rule has been revised so that for purposes of this rule a normal load shall have th e 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, si milar 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 LT CS, provisions in subpart UUUUU to clarify the reporting obligation for such units etc.).

Response to Comment 11: The rule has not been changed because agency finds the comment not relevant, since an inoperable EGU w ould have no emissions to report.

Comment 12: Commenter 17878 recommends that ambiguiti es regarding measurement of “Btus” should be resolved by explicitly defining “British therma l unit” or “Btu” as the gr oss calorific value (i.e., the higher heating value). This will eliminate the po ssibility of confusion withthe 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 va lue, the rule refers.

Response to Comment 12: The agency disagrees with the comme nter’s assertion that the rule is ambiguous, for the Agency and its rules have consisten tly used the higher heati ng 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 th at the EPA look at inconsis tencies within the tables contained in the proposed rule. Most of the comments pertained to specific tables, however Commenter 17677 states that the tables are conf using because they appear to be summarizing too much information in one table and are not pollutant category oriented, e.g., Dioxin/Furans, Non-Hg Metals, Mercury, Acid Gases. The commenter suggests that clarity may be achieved by creating more tables and separating by fuel types as most all facilities will be ≥ 8,300 Btu/lb, then by unit types under each fuel section, then by the pollutant groups. The commenter recommends th at the EPA expand the last column “Using these requirements as appropriate” to include specifics rath er than statements which may be too general to provide clarity. Additionally, listing a reference method for each test and then including the exceptions to that reference method, as done in some rows, is recommended.

Response to Comment 1: The agency reviewed the concerns of this commenter, as well as other commenters, and the rule tables have been revised for clarity.

Specific comments to tables have been organized by Table, below.

1. Table 1:

Comment 2: Commenter17174 recommends that Table 1 sh ould state that total particulate matter (filterable and condensable) is the pollutant being regulated rather th an “particulate matter” in order to clearly agree with the preamble.

Comment 3: Commenters 17801 and 17821 note that Footnote s 1, 2, 3, and 4 from Table 1 (p. 25125- 25126) are missing so the readers cannot confirm or fully assess the intent.

Comment 4: Commenter 17909 questions whether the agency intended to insert OR vs. AND between choices for compliance based on total PM, total non-Hg metals, and individual HAP metals. The commenter recommends that the EPA clarify Table 1 and correct the text of the preamble and the rule accordingly. The commenter further stat es 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 o ngoing testing requirements. If Table 1 is not correct the commenter requests a detailed explanation and guidance as to how to run initial and subsequent stack tests, how to assess compliance of those resu lts, and how to determine th e “operational limit” for continuous compliance should be issued by the EPA. The commenter also request s 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 outgro wth of the proposal and suggested revisions.

2. Table 2:723 Comment 5: Commenter17191 requests that the EPA re vise 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 recons tructed IGCC 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 conf irm or fully assess the intent.

Comment 7: Commenter 17909 questions whether the agency intended to insert OR vs. AND between choices for compliance based on total PM, total non-Hg metals, and individual HAP metals. The commenter states that no indication is given as to how (or even if) re sults of tests to determine total particulate AND total non-Hg HAP meta ls AND individual HAP metals, as discussed in the preamble of the rule (p.25029) and the ru le 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 resu lts are less than 0.030 lb/MMBTU, the source passes init ial certification), and no metals data would be needed at all OR a source could determine total metals and no total part iculate 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 ce rtification testing and in subsequent tests required every 5 years. No indication was given as to how to determine compliance of the results, however the EPA did state that a relationship or correlation between filterable partic ulate 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 request s 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 averag e to determine compliance. The commenter recommends that EPA clarify Table 2.

The commenter further recommends that EPA clarify Table 2 and corr ect the text of the preamble and the rule accordingly. The commenter states that if Tabl e 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 o ngoing testing requirements. If Table 2 is not correct the commenter requests a detailed explanation and guidance as to how to run initial and subsequent stack tests, how to assess compliance of those resu lts and how to determine th e “operational limit” for continuous compliance should be issued by the EPA. The commenter also request s that this portion of the proposed rule should be re-written and re-published for comment.

Response to Comments 5 - 7: The agency reviewed all comments and revised the rule to allow an SO 2 alternative emissions limit for new IGCC EGUs that employ flue gas desulf urization technology, to include all footnotes, and to al low the EGU owner or operator to choose one of a number of nonmercury HAP metals alternative emissions limits a nd demonstrate compliance with the selected limit only. As mentioned elsewhere, the agencyfinds 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, an d a more appropriate ci tation would be 63.10005(f).

Comment 9: Commenters 17174 and 17691 state that th e reference provided in Table 3724 regarding annual performance test s for work practice standards, section 63.10005, does not contain any reference for tune-up work practic e performance tests to be conducted annually. However, section 63.10006(r) contains language regarding meeting app licable tune-up work practice standards. The commenters request that the proper citation and period testing be pr ovided in Table 3. Furthermore, Commenter 17691 adds that section 63.10006(r) states thatsources required to meet an applicable tuneup work practice standard must conduct a perfor mance tune-up according to 63.10007, but that section speaks only of performance testing, not tune-ups. The commenter request s that each section be reviewed for clarity.

Comment 10: Several commenters (17716, 18498, 17725) reco mmend that the phrase “performance test” in Table 3 be replaced with “ boiler tune-up” to avoid confusion a nd be consistent with the language in 63.10005(f).

Response to Comments 8 - 10: The agency reviewed the commenters ’ concerns, and Table 3 in the rule has been revised to better describe the work practice standards. As th e performance test for some units subject to a work practice standa rd is a tune-up, no change to the rule language was made.

4. Table 4:

Comment 11: Commenter 17197 provides the followi ng 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 to tal PM compliance can be demonstrated using CEMS. Section 63.9991 (a) should also be modified to read “ You must meet the require ment in paragraph (a)(1) and or (2) of this section.”

 The commenter recommends that the rule should clearly state that: If continuous compliance is demonstrated with PM CEMS, a fabric filter ba g leak detection system (BLDS) operating limit is not applicable. Table 4 contains both PM CEMS and Fabric F ilter 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 ca rbon 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 operati ng limit requires that the sorbent or carbon injection rate be maintained at or above the lo west 1-hour average sorben t flow rate measured during the most recent performance test dem onstrating compliance with the Hg emissions limitation. However, since the Hg CEMS performan ce test is the initial 30-day rolling average period, the minimum 1-hour injectio n rate could be zero. Furthermor e, the commenter states that if continuous compliance is demonstrated with Hg CEMS or sorbent trap monitoring, section 63.9991 should clearly state that es tablishing 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 contro l: Maintain the sorbent injection or addition rate at or above the lowest 1-hour average sorben t flow rate measured during the most recent performance test demonstrating comp liance with the Hg emissions limitation.”725 Comment 13: Commenters17174and 17775 suggest that the in tended reference provided in Table 4 regarding fuel analysis procedures to demonstr ate compliance with the applicable limits may be 63.10011(c) and not 63.10011(d). No provisi ons for fuel analysis complian ce 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 langua ge 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 op erating rate(s) as require d by the language in the proposed standard will not be attainable over all leve ls of operation without the flexibility to set ranges of parameters that vary with operati ng 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 ga s scrubbers) contains clarity issues and a possible error. Th e paragraph is unclear if the requir ements to “maintain the pH at or above the lowest 1-hour average pres sure drop across the wet scrubber” are intended to apply to pH and liquid flow rate; pressure drop and liquid flow rate; or pH, pressure drop, and liquid flow rate. However, if the EPA intended to regulate pressure drop, regulation/monitori ng 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 ac id gas scrubbing efficiency of a spray absorber.

Comment 15: Commenter 17821 notes that in Table 4, pH is incorrectly referenced “2. Wet acid gas scrubbers... a. Maintain the pH ator above the lowest 1-hour aver age 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; howeve r, Table 7 requires sources to “collect secondary voltage and current... every 15 minutes during the entire ea ch individual test run in the three-run performance test by computing the average of all the 15-minute readings take n during each test run.”

Comment 17: Commenter 17881 states that the requirement that the injection rate shall be maintained at or above the lowest 1-hr averag e 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 shoul d specify that operating load must be monitored and recorded.

Response to Comments 11 - 17: The commenters’ concerns are moot , for with the ex ception 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 operati ng 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 s hould 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 shoul d 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 (tot al, filterable PM)

Commenter states that the table s hould indicate that Method 2 (or equivalent) need only be used if necessary to calculate output-based emissions.

Response to Comment 19: The agency reviewed the commenter’s concerns, and the rule is revised to include Method 2H, 26A, and 320; other Methods did not meet this rule’s criter ia and remain excluded.

Comment 20: Several commenters (17716, 17725, 18498) point out that the refe rence provided for Table 5 (Appendix A) does not address monito ring certification and ongoing monitoring requirements for PM and HCl CEMS.

Response to Comment 20: The agency reviewed the commenter ’s concern, and the table now has appropriate monitoring certificati on 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, duri ng periods of startup or shutdown.

Comment 22: Several commenters (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 agency has reviewed the comments, and the table now references Part 75 requirements and contai ns correct references.

Comment 23: Several commenters (17675, 17718, 17881) stat e that section 63.10010(h) discusses installing CPMS as specified in Table 5 of this su bpart. This section should instead refer to Table 4 which contains operational parameters rather th an Table 5 which contains performance testing requirements. If the section is correctly referencing Table 5, then it is unclear what CPMS are required.

Response to Comment 23 : The comment is moot, as table 6 now contains operational parameter instructions for those EGU owners or operators who choose to use PM CPMS.727 Comment 24: Commenters 18498 and 17725 recommend that the EPA add the text below to Table 5, as applicable:

“Alternatively, for an affected source that is also subject to the 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 procedures in paragraphs b(1) through b(3) of this section.”

Commenter 18498 also recommends Section 60.10010(b) should reference Part 75 in lieu of the alternate requirements specified in Appe ndix A to Subpart UUUUU with regard the O 2 and CO 2 CEMS requirements.

Response to Comment 24: The agency reviewed the commenters’ concerns, and the rule now references Part 75 requirements in both table 5 and in rule text.

Comment 25: Commenter 17881 states that exhaust flow and moisture should only need to be determined if you are complying with the lb/MWh limit. The O 2 /CO 2 levels should only need to be determined if you are complying with the lb/MMB tu standard. The commenter recommends that the EPA clarify the language in Table 5 in order to prev ent the collection of data which is not needed to assess compliance with the chosen emission limit form (i.e., heat input or el ectrical output basis).

Response to Comment 25: The agency has reviewed the commente r’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 do es not apply since it is for systems that measure pollutant emissions in units of mass per unit of time. The EPA has developed no performance specification for non-FTIR based HCI CEMS. The comm enters state that the lack of a performance specification for HCI (coupled with limited utility HCI operating experi ence, particularly for compliance near the detection limits of the systems) make s it difficult to provide meaningful comments.

Response to Comment 26: The agency disagrees with the comme nter, 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 w ith HCl emissions, he or she could use quarterly emissions testing or wait and use non-FTIR HCl CEMS using the separate HCl CEMS performance specifications under development but expected to be promulga ted before the rule’s compliance date.

Comment 27: Commenter 17881 states that bullet c. should read: “Determine oxygen OR carbon dioxide concentrations of the stack.”

Response to Comment 27: This change to the rule has been made.

Comment 28: Commenter 17881 states that the reference to a 30-day rolling average is not appropriate. Per 63.10005(k)(2), a 28-30 day integr ated average value is being es tablished, 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 pr ovides the fuel analysis requirements, does not address gaseous fuels at all even though gaseous fuel may be co-fired (f or purposes other than startup and flame stabilization) with one or more fossil fuels which are regulated in the proposed EGU MACT, particularly liquid oils.

Commenter 17881 states that in the requirements for HF, there is a typo in bullet f.; it should read “measure fluorine concentration in fu el sample” instead of chlorine.

Response to Comment 29: The comment is moot, for the rule no longer requires fuel analysis for pollutants.

7. Table 7:

Comment 30: Several commenters (17174, 17808, 17881) state that the reference provided in the table regarding emission operating limits through fuel an alysis should be 63.10011(b) as opposed to 63.10011(c).

Comment 31: Commenters 17775 and 17808 state that the tabl e only lists the opera ting limits for ESPs for units that operate wet scrubbers, therefore co nflicting with other prov isions, including proposed section 63.10011(b)(6)(iii). The table does not include the operating parameters fo r 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 in jection 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-specifi c operating limit for that sorbent.

(1) Data from the sorbent injection or addi tion rate monitors and Hg performance test.

(a) You must collect sorbent inject ion or addition rate data every 15 minutes during the entire period of the performance tests;

(b) Determine the average hourly so rbent injection or addition rates of the three test run averages measured during the performance test.

Comment 33: Commenter 17721 states that Table 7 should be revised to add operating limits for sources using dry scrubbers, DSI, or DLPS to comply with HCl or HF emission limits as follows:729 2. “Hydrogen Chloride (HCL) or hydrogen fluoride (HF)

(b) Dry scrubber, DSI, or DLPS operating parameters

(1) Establish a site specific minimum sorbent inje ction or addition rate ope rating 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 addi tion rate monitors and Hg performance test.

(a) You must collect sorbent inj ection or addition rate data ev ery 15 minutes during the entire period of the performance tests;

(b) Determine the average hourly so rbent injection or addition rates of the three test run averages measured during the performance test.”

Response to Comments 30 - 33: The comments are moot, for the rule no longer requires establishment of operating parameters for pollutant control devices.

8. Table 8:

Comment 34: Several commenters (17716, 17725, 17775, 18498) poi nt out that Table 8 erroneously refers to “QA Procedure 5” for the PM CEMS QA/Q C requirements and should refer to “Procedure 2” instead.

Comment 35: Commenter 17881 states that the references in the “you must” column should be rechecked, as there are several thatare incorrect. For example, 7.a. should be QA Procedure 2, not 5, and 7.b. should be “30 boiler operating da y average mg/dscm values” rather than the current “30 boiler operating mg/dscm values.”

Comment 36: Commenters 17775 and 17808 state that referen ces to section 63.1011(c) in Table 8 may be intended to referen ce section 63.1011(b) instead.

Comment 37: Several commenters (17800, 17725, 18498) state that the method for calculating 30 rolling averages in Table 8 is not consistent withthe method in section §63.10010( g). Table 8 states that the source should convert “hourly emissions concen trations to 30 boiler operating mg/dscm values,” which suggests that compliance is assess based on th e average of 30 individual daily values. However, section 63.10010(g)(5) states that 30-d ay rolling average is calculated as “the average of all of the hourly particulate emissions data for the pr eceding 30 boiler operating days.” Commenter 17800 recommends that the EPA consider changing this averaging time to a 12-month rolling average consistent with the Illinois MPS rule to help captur e 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 withthe other sections.

Comment 38: Commenters 18498 and 17725 note that Table 8 re quires CPMS data to be reduced to 12- hour block averages; however, this require ment is not specified in section 63.10010(h).730 Comment 39: Commenter 18539 states that Table 8 refers to opacity opera ting 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 lim its 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 in jection rate monitoring system da ta from the dry scrubber, DSI, or DLPS according to §63.10010 and §63.10020; and

b. Reducing the data to 12 -hour block averages; and

c. Maintaining the 12-hour average sorbent or carbon injection rate at or above the operating limit established during the performan ce test according to §63.10011(c).”

Response to Comments 34 - 40: The agency finds the comments are moot, as table 8 has been revised to remove all requirements associated with deve loping and maintaining oper ating limits for pollution control devices.

9. Table 9:

Comment 41: Several commenters (17913, 17915, 17174) requestthat the reference to startup, shutdown, and malfunction (SSM) plans in Table 9 should be removed because it conflicts with the text in Table 10 and the preamble that states SSM plans are not required.

Comment 42: Commenter 17775 indicates that the Table 9 should be evaluated for the following inconsistencies:

 The error, “information requi red in §63.10031(c)(1) through (11) through (11),” should be addressed. In addition, the EPA should review the text and c onsider referencing §63.10031(c) subsection (12) as well. Commenter 17881 notes this inconsistency as well.

 The table specifically requires s ubmission of a startup, shutdown, and malfunction report containing the information in §63.10(d)(5)(i) at 1.d and 2, how ever, Table 10 states that §63.10(d)(5) does not apply. The EPA should address the inconsistenc y and correctly identif y applicable reporting requirements.

Response to Comments 41 - 42: The Agency has reviewed the comm enters’ concerns and revised the table by removing requirements to develop and su bmit a startup, shutdown, or malfunction plan and corrected the text cite language, as suggested by the commenter.

10. Table10:

Comment 43: Commenter 17775 states that section 63.1(a)(4)(i ) requires each standard to “identify explicitly whether each provision in this subpart A is or is not incl uded” and that the EPA proposes to address applicability in Table 10. The commenter provi des the following instances of inconsistencies in Table 10 with respect to applicability:

 EPA identifies §63.6(h)(2)-(9), and §63.9(f), and (g)(2) as applicable. Proposed §63.10030(a)731 also requires compliance with §63.9(f). These pr ovisions pertain solely to compliance with opacity and visible emission standards. Since th e proposed rule does not include any applicable opacity or visible emission standards, these por tions of the general provision do not apply and Table 10 should be revised accordingly.

 EPA fails to identify whether §63.6(e)(1)(iii) applies.

 EPA fails to identify whether §63.8(a)(1), (2), and (4 ), (b), (c)(2), (4)(i), (5), (6), (8), (d)(1), (d)(2), (f), or (g) apply. Sections (c)(1)(ii), (3), (4)(ii), (7)(i), (8), and (d) are referenced in proposed §63.10000(d)(4) and §63.8(e) is referen ced in proposed §63.10030(a), but not in Table 10. Some of these provisions a pply solely to opacity monitori ng, and should not apply, but the EPA must state whether or not they are incl uded. The EPA should provide that CEMS meeting the requirements of Part 75 are exempt from th e “performance evaluation” test plan and notices in §63.8(e). The EPA also should make clear that those requirements do not apply to “calibration error testing,” since “performance evaluation” is defined in §63.2 to include both relative accuracy testing and calibration error testing.

 EPA fails to identify whethe r §63.10(b)(2)(x)-(x iii) apply.

 EPA identifies §63.10(c) as applicable in its en tirely, but later in th e 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 require ments of the site-specific monitoring plan in proposed §63.10000(d)(7). Note also that §63.10(c)(7 ) and (8), which specify recordkeeping for sources with continuous monitori ng requirements, require reporting of “excess emissions” “as defined in the relevant standard(s), that occu r during startups, shutdowns, and malfunctions of the affected source” and those th at occur “during periods other than startups, shutdowns, and malfunctions.” Proposed subpart UUUUU does not de fine “excess emissions” for any standard and does not exempt periods of startup, shutdown, or malfunction.

 In determining whether the recordkeeping re quirements in §63.10(b) and (c) apply, the EPA must ensure its compliance with the PRA. Under 5 C.F.R. §1320.5( d)(2), the EPA cannot require retention of such records for more than 3 year s, unless the agency demonstrates in its OMB submission that that a longer rete ntion period is necessary to “satisfy statutory requirements or other substantial need.”

 EPA fails to identify whether § 63.10(d)(3)-(4) are applicable.

Response to Comment 43: The agency reviewed the commenter’s concerns, and the rule and table have been revised, where appropriate, to remove inconsistencies.

Appendix A:

Comment 44: Commenter 17775 points out the following inconsistencies in Appendix A:

 Appendix A §4.1.1.3 incorrectly refers to Table A-2 instead of Table A-1.

 The conversion factors used in Appendix A §6.2.1.2, Equation A-2 and Equation A-3 should be the consistent. Appendix A §6.2.1.2 include s a factor of 6.24x10-11 to convert Hg concentration from
μ g/scm to lb/scf whereas Equations A-2 and A-3 use a constant of 6.236x10-11.

 Appendix A says that quarterly reports mustinclude 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 ch anges be made regarding Hg Monitoring Provisions in order to harmonize Ap pendix A of the EGU MACT with the requirements of 40 CFR Part 75, as most (if not all) units subject to the EGU MA CT will also be subject to 40 CFR Part 75 emissions monitoring:732  Table A-2, Flow Rate RATA Speci fications: “40 CFR Part 75, App. A, Section 3.3.4 also provides an alternate performance specifi cation of not > 2.0 feet per sec ond (FPS) when the average RM value is ≤ 10.0 FPS.”

 Table A-3, Daily Calibration Error Test: The first bulle t should read “use zero gas and either a midor high- level gas,” as daily cal ibration error tests are generally conducted using a zero and upscale calibration gas.

 Table A-4, Daily Calibration Error Te st for O2 or CO2: The first bullet should read “use zero gas and either a mid- or high- level gas,” as daily ca libration error tests are ge nerally 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, Secti on 2.3.1.2(d) alternate specification for flow monitors of ± 1.5 FPS when the average RM value is ≤ 10 FPS should also be allowed.”

Commenter 17881 also asks if the EPA intends moistu re monitoring systems 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 systems, the commenter states that 40 CFR Part 75 generally requires those same on-going quality assurance te sts as are required for O 2 diluent monitors howe ver Appendix A of the proposed EGU MACT only appears to require a RATA test.

Response to Comments 44 and 45: The reference to Table A-2 in section 4.1.1.3 of Appendix A was a typographical error and has been co rrected. The conversion factors in Equations A-2 and A-3 have been made consistent; both factors are now 6.24 x 10E-11. Th e reference in the quarter ly reporting section of Appendix A to section 7.1.19 was a typogra phical error and has been corrected.

The EPA has not incorporated the commenter’s suggestion to harmonize the information in Tables A-2 and A-4 with Part 75, because Tables 2 and 4 have been deleted from Appendix A. The agency has decided against reproducing part 75 certification and QA specifications in Appendix A for the flow rate, diluent gas, and moisture monitoring systems that are used to convert Hg concentrations to units of the standard. Instead, section 3.2.3 of Ap pendix A simply states that th ese monitoring systems must be certified, operated, maintained, and quality-ass ured according to 40 CFR part 75. The EPA has incorporated the edit to Table A-3 (which has been renumbered as Table A-2) suggested by the commenter, i.e., that the daily calib ration error tests of the Hg CEMS must be done with a zero gas and either a mid-level or high-level calibration gas. Fi nally, moisture monitoring systems consisting of wet and dry O 2 analyzers are not exempted from daily calibration error tests. The O 2 monitors in these systems must meet the daily ca libration 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, 19120, 19536/19537/19538, 18023

1. Clarifications.

Comment 1: Several commenters request that the language of the rule be updated to clearly state the requirements for each category, subcategory, pollut ant and compliance option used at facilities. Commenter 18034 requests that the EP A clarify how to determine em ission rates during a startup, shutdown, or malfunction situation.

Response to Comment 1: We believe that the final rule language is clear.

Comment 2: Multiple commenters (17677, 17730, 17758, 17909, 17912) request that the preamble should be updated and clarified to be consistent with the rule language. For example, Commenter 17912 notes that the preamble to the proposed rule states the EPA’s intent to exclude stationary combustion turbines from this rule. However, the proposed ru le text excludes only those stationary combustion turbines located at major sources. The commenter requ ests that the EPA revise the rule text to confirm its intent to exclude all stationary combustion turbines , including those located atminor source facilities.

Response to Comment 2: We do not believe that the regulator y language distinguishes between major and area source facilities as the te rm “major source” is not used.

Comment 3: Commenter 17656 urges the EPA to make clear pr ecisely what requirements apply to each category/subcategories and the di fferent options for compliance th at are available. Commenters 17677 and 17730 both oppose leaving such clar ification for follow-on guidance.

Response to Comment 3: We believe that the final rule clearly presents the compliance options as requested by commenters.

Comment 4: Commenter 17730 appreciates the variety of opti ons that the EPA has provided for sources to demonstrate ongoing compliance, but states that se veral of the options will require clarification in order for facilities to understa nd the options, applicability, and to demonstrate compliance. The commenter recommends that the EP A revise the proposal to make cl ear exactly what requirements and rationale apply to each complian ce option. The commenter points out that the EPA has the opportunity to electronically publish each of the different subcateg ories and the different options in a clear, direct, and plain language fashion with a limited amount of re ferences to other subsecti ons, or mentions of “as applicable. The EPA has substan tively failed to provide a clear and readily unders tandable set of requirements for sources in this proposed rulemaking.

Response to Comment 4: The agency believes that the final rule provides a clear and readily understandable set of requirement s, and the rule contains clar ifications where appropriate.

2. CEMS comments.

Comment 5: Multiple commenters (17623, 17655, 17716, 17681, 17800, 17821 and several others)734 request that the EPA review and update the la nguage regarding CEMS, pe rformance testing and operating limits.

Response to Comment 5: As mentioned earlier, the agency ha s reviewed the commenters’ concerns and revised the rule where appropriate.

Comment 6: Commenter 17716 states that the proposed rule should be clarified to explicitly exempt sources using a CEMS for compliance for a particular pollutant from all fuel sampling requirements for that pollutant. The commenter states that the fuel sampling requirements apply only to those units that demonstrate compliance through performance (i.e., stack) testing for a particular pollutant, but §63.10005(a) states that “performance testing” may also consist of CEMS operating data, thereby creating ambiguity about whether un its using a CEMS for compliance must also meet the fuel sampling requirements.

Comment 7: Commenters 18498 and 17725 recommend that th e EPA revise §63.10007 to indicate that the fuel sampling and operating parameter limits are not required when the applicable HAP (or surrogates) are monitored using a CEMS.

Response to Comments 6 - 7: The agency agrees with the commenters, and the rule has been revised to not require fuel sampling of pollutants wh ere CEMS are used for compliance purposes.

Comment 8: Commenter 17718 states that it is not clear that installing and operating CEMS for the regulated HAP and surrogates will relieve a source of the burden of also m onitoring compliance with operating limits on control equipment based on a pe rformance stack test. The commenter recommends that the EPA require no proof of compliance beyond a properly calibrate d and installed CEMS, and that the EPA revise both the language and tabl es in the rule to clarify its intent as it relates to CEMS used for demonstrating compliance.

Comment 9: Several commenters (17655, 17696, 17716) state that the language regarding performance testing and compliance is unclear and should be revi sed so that facilities can clearly understand and follow regulations. Commenter 17655 specifically notes that Sections §63.10005(a), §63.10011(a), and §63.10011(b) are difficult to interpret. For example, it is unclear whether faciliti es using CEMS are also required to track performance parameters to show compliance. The commenter requests that the EPA use consistent and clear language to enumerate the requirements for fa cilities 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 wh en 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 th e CEMS on a source. The commenter recommends that the EPA specifically state in the rule that the use of Reference Methods are required to demonstrate initial compliance w ith the emission limitations in this rule.

Response to Comment 10: The methods suitable for conducting perf ormance tests for this rule, or any rule, are defined in large part by sp ecified averaging time. In many cases, this final rule clarifies that the averaging time for initial and periodic compliance tes ting is the result of three relatively short term performance test runs and through the use of manually operated test methods found in Appendix A of 40 CFR part 60 or 63. This approach to conducting initial and periodic pe rformance tests applies to metal HAPs, PM, and HF and HCl, and is consistent withthe 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 av eraging time of the rule is 30 unit operating days. This long averagi ng time precludes the use of manual performance test methods on a practical basis. The final rule specif ies 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 CE MS is employed. In the preamble, the commenter requests that the clause that stat es “and an operating limit would be established” should be removed because it is duplicative of the CEMS requirement.

Response to Comment 11: The agency has reviewed the commenter’s concern, and while the rule has been revised so that neither emissions testing ot her than RATAs (or initial calibration for PM CEMS) nor operating limits are required for EGUs that us e CEMS for compliance purposes, the rule has not been revised to exclude the requirements of perf ormance specifications when CEMS are used for compliance purposes.

Comment 12: Commenter 17696 states that se ctions 63.10000(c),(d), 63.10005, 63.10006, 63.10008, 63.10011, and 63.10021 are complex and confusing and in so me cases inconsistent with the preamble and examples in the rule. The commenter cites la nguage on whether a coal-fi red EGU without an HCl CEMS is required to conduct monthly fuel analysis for chlorine from s ections 63.10005(a), 63.10006(s), and 76 FR 25,051 to illustrate the difficulty and contradictions contained in the rule.

Response to Comment 12: The agency has reviewed this concern, and the rule has been revised for consistency and clarity.

Comment 13: Commenter 17796 suggests that the Hg compliance metric be succ inctly stated in section 63.10010(1). The commenter states that although s ection 63.10010(g)(5) for PM CEMs discusses that compliance is based upon a 30 boiler operating day rol ling average emissions rate on a daily basis, the commenter was unable to find this language for the Hg compliance limit. Sec tion 63.10010(1) refers the reader to Appendix A but Appendix A doe s not state the compliance average.

Response to Comment 13: The agency disagrees with the comment er’s concern, for the rule states the initial Hg CEMS compliance requirement at §63.10005(a)(2) and the ongoing Hg CEMS compliance requirement at §63.10021(a).

Comment 14: Commenter 17718 notes that sections 63.10005(d )(3)-(6) state if CEMS are going to be used for initial compliance determinations then the average hourly concentrations obtained during the first 30-day operating period will be used “after the monitoring system is certified.” The commenter requests that the EPA clarify when the 30-day oper ating period begins if the systems 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. Owners or operators of new EGUs have up until 60 days after the rule appears in the Federal Register or upon startup, whichever is later; or, for existing units , 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 clearly state what the acceptable data capture percentage is for Hg, HCl and PM CEMs. The method of counting hours whena monitor is out of service, as hours of monito r down time and using this value to dete rmine the % of monito r availability is consistent with NSPS requirement. For Hg, secti on 60.490a paragraph (p)(4) discusses the need for 75 % data capture on a monthly basis for a monitor to achieve an acceptable % monitor availability and to be able to demonstrate consistent compliance. However, the commenter states that this whole section will become obsolete and removed from the NSPS if the proposed changes to the NSPS and NESHAP rules go into effect.

Response to Comment 15: The agency considered the commenter’s suggestion but made no change to the rule. The rule contains no minimum acceptable data capture percentage, for the rule at §63.10010(j) requires data to be collected at all times an EGU is combusting fuel except for periods of monitoring system malfunction, out-of-contro l operation, or quality assurance or control activities.

Comment 16: Commenter 17622 requests that the EPA clar ify the statement “continuous compliance would be determined using a PM CEMS with an ope rating limit established based on the filterable PM values measured using Method 5.” (76 FR 25029/ 2). The commenter recommends that the EPA explicitly state if the PM CEMS would be correlate d against the filterable PM fraction of total PM to avoid confusion.

Response to Comment 16: The agency considered this and other comments, and the rule has been revised to include a filterable PM, but not total PM, alternative emissions standard. The rule also allows use of PM CPMS, which would have an operating limit, as well as PM CEMS, which would allow direct measure of compliance, as compliance options.

Comment 17: Commenter 17675 further recommends that the wording in section 63.10010(a) should be updated to clearly state that Hg CE MS and/or sorbent traps can be used for Hg monitoring, rather than implying that both CEMS and sorbent traps are re quired. Similarly, Commenter 17821 recommends that the EPA clarify the term “dem onstrate initial and continuous compliance through the use on a continuous...HCl...[and]...Hg CEMS or a sorbent tra p...system” to indicate that a “certified CEMS” must be used. The term “certified CEMS ” means that all of the required testing outlined in this rule, or in applicable portions of 40 CFR pa rts 60 or 75, have been completed, a nd 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 requir ed before using it for purposes of demonstrating compliance.

Response to Comment 17: Although the agency a ppreciates the commenter’ s concern, no change was made to the rule, for §63.10010(g) requires Hg CEMS or sorbent trap monitoring systems to be certified.

Comment 18: Commenter 17716 requests the following correc tions and clarifications regarding CEMS:

 EPA should evaluate and revise th e 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); 63.1 0010(e)(4); and 63.10010(g)(4) al l state: “Reduce the CEMS data as specified in se ction 63.8(g)(2) and (4).” Howeve r, section 6.1.1 of appendix A relates data reduction from “Hg CEMS and (as app licable) 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 incl ude the option to use the Part 75 certification and ongoing QA/QC requirements as allowed in section 63.10010(e). Commenter 17725 also notes this issue.

 For Hg CEMS, section 63.10021(h)(ii) states the “Quarterly accura cy 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 refere nce section 5 to appendix A. Commenter 17725 also notes this contradiction.

Comment 19: Commenter 17881 requests the following correc tions and clarifications regarding CEMS:

 Section 63.10011(b)(6) should clarify how these requirements apply in cases where CEMs are used for compliance.

 The reference in section 63.10021(a)(10)(i) is in consistent 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 thathourly records of % monitor availability (PMA) be maintained for Hg CEMS and sorbent trap monitoring systems. The PMA concept is employed in 40 CFR Part 75 in the context of determining appropriate missing data substitution procedures. As missing data substi tution will not be allowed in the context of Hg monitoring, the commenter requests that these requirements should be deleted from proposed appendix A.

Response to Comments 18 - 19: The agency has reviewed and considered each of the commenters’ suggestions. The rule now uses Part75 data reduction and quality assurance procedures for those CEMS also used in Part 75; Hg CEMS a nd sorbent traps are subject to the re quirements of appendix A; HCl or HF CEMS are subject to the requ irements of appendix B. The commenter’s concern over simultaneous control device operational paramete r 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 clarified; the rule now allows either type of CEMS. The rule retains the requirement to report Hg CEMS or sorbent trap monitoring data avai lability; although the Agencyagrees that there is no minimum data availability requirement for these types of monitors, the Agency sees no inconsistency between the monitoring operational and data availability reporting requirements.

Comment 20: Commenter 18498 states that as proposed, the EGU MACT Rule does not include provisions to use the Part 75 “conditionally valid da ta procedures.” For exam ple, 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 va lues derived from missing data substitution procedures).

Response to Comment 20: As mentioned elsewhere, the rule now allows use of Part 75 procedures for quality assurance and contro l activities for those monito rs also used in Part 75.

Comment 21: Commenters18498 and 17725 note that section 63.10021(a)(10)(i) requires sources to “continuously monitor oxygen according to §§63.10010(a) and 63.10020” if you are required to install 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 analyzers and CEMS cannot measure O 2 as a diluent.

Comment 22: Commenter 17718 states that section 63.10021(a)(1 0)(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 be submitted elec tronically using the Electronic Reporting Tool. The commenter requests that the EPA clar ify 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 performe d for 40 CFR Part 75 requirements would not to be reported in the ERT even though it may have been performed concurrently.

Response to Comment 23: The agency reviewed the commenter ’s concern and disagrees with the commenter’s assertion. The rule has not been change d, 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 alternative means of demonstrating compliance with acid gas emissions limits would need to submit those data electronically.

3. IGCC comments.

Comment 24: Commenter 17801 recommends that the EPA pr ovide further definition and clarification regarding air pollution control de vices (APCD) to account for upstr eam fuel cleanup (e.g., removal of particulate, Hg, non-Hg metal HAPS, sulfur and/or chloride directly from the fuel stream of IGCC units). For example, for coal-fired units with add-on APCDs, it is unclear in section 63.10006 and/or Table 7 as to the testing program or operating limits to which IGCC would be subject. There is not an applicable combination of CEMS/APCD described that pertains to IGCC which could allow for emissions testing every five years for some coal-f ired EGU sources instead of every other month for those sources without add-on contro ls. The EPA should consider any ups tream gasification/fuel clean-up (e.g., AGR, SRU, PM scrubber) in the same way that coal-fired EGUs are credited for post-combustion or other APCD. IGCC should not be burdened with ad ditional testing requirements if reduced testing programs are allowed for coal-fir ed units with add-on APCDs.

Response to Comment 24: The agency considered the commenter’s concerns, but the rule has not been changed. An IGCC unit can qualify for reduced fre quency 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.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 othe r 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 desulf urization system.” The commenter suggests that the modification is nece ssary because IGCC units do not require “flue gas desulfurization systems” as the sulfur is removed in the gasifi cation phase (i.e., no post-combustion “flue gas” desulfurization is necessary). Instead, re moving the reference to “flue gas” and replacing it with “pre- or post-combustion” accomplishes the object ive of requiring desulfur ization controls as a prerequisite for SO 2 monitoring option without inadvertently preventing ne w and reconstructed IGCC 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 al so clarified the definitions.

Comment 26: Commenter 17821 states that the EPA needs to revise the descripti on and definitions of the IGCC APCD to account for upstream fuel cl eanup and/or pollution prevention measures. For example, the technology used in IGCC units directly removes contaminants (such as particulate, Hg, non-Hg metal HAP, sulfur, chloride) directly from the fuel stream of IGCC un its. In this respect, IGCC is more akin to a natural gas-fired combined cycle un it, since it burns a syngas, which is cleaner than the coal combusted in a pulverized coal unit. The EPA should reflect th at IGCCs use upstream gasification/fuel clean-up (f or example, AGR, SRU, PM scrubber) in the same way that coal-fired EGUs are credited for post-combustion or ot her 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 th at an IGCC unit is a dis tinct type of electric generating unit by proposing a separate subcateg ory for IGCC units. The EPA needs to further acknowledge the process differences between IGCC units and PC units by providing clarification that for purposes of this MACT the aff ected facility is the combustion tu rbines and any emission limitations apply to the heat recovery steam generator HRSG stack. Commenter re commends that the EPA needs to provide further clarification that all upstream fuel clean-up in the IGCC process qualifies as control equipment, thereby not putting any additional testing burdens on IGCC units when reduced testing is allowed for coal-fired units with add-on pollution control equipment.

Response to Comment 26: As mentioned elsewhere, the agency considered the commenters’ concerns, but the rule has not been changed. An IGCC unit canqualify for reduced fre quency emissions testing under the existing rule’s LEE provisions, should anIGCC EGU owner or operator choose to use emissions testing as the means for demonstr ating 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) di fferences between coal-based (gasifier feedstock -based) and syngas-based heat input; and (2) differences between s yngas-based and natural gas-based output during co-firing operations.

Response to Comment 27: The EPA is regulating IGCC units that burn synthetic gas derived from coal and/or solid oil-derived fuel. Natural gas-fired EGUs are not subject to this final rule.

4. Fuel sampling and analysis.

Comment 28: Commenters 17716 and 17725 request that the EPA clarify whether units that fire a740 single type of fuel (e.g., diesel oi l) are exempt from all fuel sampling and analysis requirements. Although section 63.10005(c)(4) ex empts units that fire a single fuel type from conducting fuel analysis as part of the initial compliance requirements, it does not address other fuel sampling requirements. Section 63.1001 states, “you must also conduct fu el analyses according to §63.10008 and establish maximum fuel pollutant input levels” and includ es specifics for handlin g single-fuel units. The commenter questions whether the EPA intended to re quire single-fuel sources to conduct initial and ongoing fuel sampling like the IB MACT approach sin ce other sections appear to only require fuel sampling when burning a new fuel type.

Comment 29: In addition to the fuel sampling clarifica tion, commenter 17716 also recommends that the EPA expand the exemption in section 63.10005(c)(5) to cover units that fire multiple fuel types or blends in the final rule. The sect ion states that, fuel sampling and analysis are not required for singlefuel units using supplemental fuels that are used only for startup, shutdown or for maintaining flame stability.

Comment 30: Commenter 17775 requests that the EPA revi ew and update the language regarding fuel analysis tests in section 63.10008 and Table 6 to ensure clarity a nd consistency. Proposed section 63.10008 requires fuel analysis tests according to the “procedures in paragraphs (b) through (e)” and Table 6. Paragraphs (c) and (d) specify minimum sampling procedure and compositing procedures. However, Table 6 also provides sampling methods that can be used in lieu of those in paragraph (c) and some of those procedures address compositing. The co mmenter requests that th e language clearly state that any procedure identified in Table 6 can be used in lieu of procedures inparagraphs (c) and (d).

Comment 31: Commenter 17796 states that “What Are My General Requirements for Complying with this Subpart,” paragraph (c)(2), cl early states that liqui d oil-fired EGUs can demonstrate initial and continuous compliance using fuel anal ysis for HCl, HF and total HAP me tals but does not indicate that Hg can be used in the fuel analysis to demonstr ate compliance. The commenter states that non-Hg HAP metals and Hg are generally segregated from other parameters for compliance determinations and requests that the EPA address these constituents clearly and cohesively.

Comment 32: Commenter 17386 states that the fuel analys 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 demonstr ation by fuel analysis), “We are proposing that a source be required to recalculate th e fuel pollutant content only if it burns a new fuel type or fuel mixture...”

Comment 33: Commenter 17718 requests that the EPA clarify the frequency of ongoing fuel sampling/analysis required for purposes of comparison with “the maximum fuel input values calculated during the last performance tests (if demonstratin g compliance through performance stack testing).”

Comment 34: Commenter 17718 states that the establishment of fuel limits appear s applicable only to facilities that choose to comply via fuel analysis . If facilities apply CEMS, accurate compliance can be determined at the emission point and, therefore, th e fuel input becomes irrelevant. Additionally, there are numerous inaccurate section/paragraph referen ces within the proposed regulatory language of 40 CFR 63.10011(b). The EPA should carefully review this section to properly link references to the appropriate sections and paragraphs.

Response to Comments 28 -34: The comments are moot because rule no longer requires fuel analysis for pollutants.741 5. Subcategory comments.

Comment 35: Commenter 17843 supports fuel-based testin g 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 secti on 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 sectio ns 63.10006(f) and (g) should refer to Table 6 (Fuel Analysis Requirements), not 5 (Performan ce Stack Testing Requirements), which would have more clearly allowed liquid oil-fired units to use fuel analysis to demonstrate compliance. Commenter 16513 also states that this section is unclear and adds th at it is unclear what the term “continue to meet” in sec tion 63.10006(p) means in the context of section 63.10006(o).

 In section 63.10006(s), the opportunity to demons trate compliance with the Hg, individual or total non-Hg HAP metals, HCl, or HF emissions li mit based on fuel analysis seems broader than the liquid oil-fired limited use subcategory, but the description in the preamble (see (d) above) appears to limit the fuel analysis compliance opti on to liquid oil-fired units that operate a limited amount of time per year on oil and are inoperative the remainder of the year.

 Commenters 17843 and 17796 both note that un der section 63.10006 “When must I conduct subsequent performance tests, fuel analysis or tune-ups?,” it is clear that affected EGUs firing solid oil-derived fuel and coal-f ired must demonstrate continuous compliance with either CEMS, or stack testing based upon the me thodologies in Table 5, stack tes ting. It is not clear in this section what is required for liquid oil-fired E GUs. In subdivisions (f) and (g), based upon EGUs with or without non-Hg HAP meta l controls, continuous complian ce is demonstrated by either every other month or monthly, re spectively, performance testing (s tack testing) based upon Table 5. In the same section 63.10006 subdivision (s), continuous compliance ca n be based upon fuel analysis, which contradicts subdivisions (f) and (g ). The general requirements state fuel analysis is acceptable for liquid oil-fired EGUs for the initial and continuous co mpliance options these issues and request continuous monitoring requirements for li quid oil-fired EGU should be rewritten for parity and clarity.

Response to Comment 35: The comments concerning fuel analysis for pollutants are moot because rule no longer contains this requirement. The rule has been revised to clarify compliance options for liquid oil-fired EGUs, and the rule continues to allow an EGU owner or operato r to choose a compliance option, including quarterly emissions testing, use of CEMS, or, in cert ain circumstances, tune-ups or fuel moisture analysis.

Comment 36: Commenter 17843 requests that the language in sections 63.10006(o), (p) and (s) be updated to clearly state the monitoring requirements for oil-fired EGUs and to i ndicate that stack testing is not intended to be co nducted every two months.

Comment 37: Commenter 17718 recommends that the EPA cl arify whether the fuel analyses and procedures in section 63.10008 are only applicable to liquid oil-fired EGUs that desire to meet their applicable emission limits through fuel sampling.

Comment 38: Commenter 17796 recommends thatthe 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 Anal ysis and Initial Comp liance Requirements, subdivision (b) is clear that aff ected EGUs must demonstrate init ial compliance witheach of the742 applicable emission limits in Tables 1 and Tabl es 2 by conducting performa nce tests according to section 63.10007 and Table 5 and either conduct fu el analysis, set operating limits or conduct Continuous Monitoring System evaluati ons. It is not clear insubdivision (c) that liquid oil-fired EGUs may choose to demonstrate compliance with fuel anal ysis. Subdivision (c) begins with compliance that can be demonstrated by fuel analysis “except for thos e affected EGUs that meet the exemption in (c)(4) and (c)(5) and those affected EGUs that opt to co mply 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 eval uated for consistency and clarity.

The commenter states that sec tion 63.10006(s), the opportunity to de monstrate compliance with the mercury, individual or total non-m ercury HAP metals, HC1, or HF emissions limit based on fuel analysis seems broader than the liquid oil-fired limited use subcategory. The commenter recommends that if it is not the EPA’s intenti on to allow units other than liquid oi l-fired limited use units to utilize a fuel analysis compliance mechanism, the EPA should clarify the language.

Comment 39: Commenter 17718 states that section 63.10011(b) makes reference to conducting fuel analyses and establishing maximu m fuel pollutant input levels .” .as applicable.” The commenter requests that the EPA clarify that the fuel samp ling, analyses, and maximum input levels are only applicable to liquid oil-fired E GUs that choose to meet their em ission limits through fuel sampling methodologies.

Comment 40: Commenter 17881 states that if compliance vi a fuel sampling and analysis is only available to liquid oil-fired units , then section 63.10021(a)(3) only appl ies to liquid oil-fired units, and the rule should clarify this point. Additionally, the commenter requests that the provisions of sections 63.10011(c), 63.10021 (a)(6) and 63.10022(a)(6) should also specify that th e paragraph applies only to liquid oil fired units or possibly LEE.

Response to Comments 36 - 40: As mentioned elsewhere, the commen ts concerning fuel analysis for pollutants are moot because rule no longer contains this requirement. The rule has been revised to clarify compliance options for liquid oil-fired EGUs, and the ru le continues to allow anEGU owner or operator to choose a compliance option, including quarterly emissions testing, use of CEMS, or, in certain circumstances, tune-ups orfuel moisture analysis.

Comment 41: Commenter 17174 states that the language in section 63.9983(b) for the natural gas-fired EGU exemption contradicts the preamble of the rule. The commenter suggests that EPA use the language in the preamble for the natural gas-fire d EGU exemption in section 63.9983(b). Furthermore, the commenter states that the langua ge does not clearly state the type s of fuel-fired EGUs which are subject to this subpart. The commenter recomm ends that should be rewritten for clarity.

Comment 42: Similarly, Commenter 17881 notes that the pr eamble discussion is confusing and sheds no light on the purpose of section 63.9983(b). The pream ble discussion could lead one to the conclusion that the proposed rule applies to al l units other than natural gas-fired units (i.e., those units for which at least 90 % of the annual aver age heat over a 3-year peri od, or more than 85 % of the annual heat input in at least one year, is derived from natural gas).

Comment 43: Commenter 17881 states that the provisions of section 63.9983(b) are confusing because rule only applies to coal- and oil-fired EGUs, and the percentage of heat input supplied by natural gas is743 not relevant if the unit is not cla ssified as a coal- or oi l-fired EGU. The provisi ons 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 heatinput (i.e., > 10 %) are exempt from the rule. In cases wher e coal-fired or oil-fired EGUs co-f ire such fuels with other fuels, section 63.9983(c) already cont ains provisions on the rela tive amount of coal and/ or oil firing (on a heat input basis) which would subject the unit to the requirements of the rule.

Response to Comment 41 - 43: We believe that the definitions in the final rule along with other edits related to situations where source s may “switch” source categories ma ke the clarifications suggested by the commenter.

Comment 44: Commenter 17758 recommends th at the language for coal-b ased compliance should be clarified. The commenter states that the most likely coal-based configur ations able to comply with the EPA’s proposed rule will 1) opt for the total PM limit and utilize PM CEMS for continuous filterable PM measurements; 2) employ some combination of wet or dry scrubbing, and/or DSI, for acid gas control and elect to us e already installed SO 2 CEMS; and 3) directly monitor mercury using either a Hg CEMS or a sorbent trap monitoring system. For the above-described scenario in which either all of the regulated HAP or their surrogates are continuously monitored, the commenter states that no additional burdens (e.g., coal sampling, operating paramete r 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 recommende d that the language be updated for clarity.

Response to Comment 44: Although the agency is appreciative of the commenter’s view that the agency does not intend to create additional burdens, th e rule must be written w ith all EGUs in mind, not just the majority. As mentioned elsewhere, the rule has been revised not to require additional compliance information from those EGU owners or operators who choose to use CEMS or sorbent trap monitoring as the means for compliance determination.

Comment 45: Commenter 17881 recommends that sec tion 63.10006(e) be updated to reduce confusion. The paragraph pertains to those solid oil-fired and coal-f ired 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 c ontrols, so it is assumed that this paragraph must apply exclusively to IGCC units. To eliminate any possible confusion, the commenter suggests that the EPA replace the term “solid oil-fired and coal-fired EGUs” with “I GCC unit” (Note that the definition of IGCC unit at section 63.10042 already incor porates the concept of solid oil or coal being used in the gasification process).

Response to Comment 45: The agency disagrees with the comme nter, noting that the rule must be written to cover all possible control device scenarios, not just the ones believed to exist at the present time. As a result, no change to the rule has been made.

6. Operating limits comments.

Comment 46: Several commenters (17752, 17725, 17800) note that the rule c ontains conflicting language regarding how operating limits are establis hed. Section 63.10011(d) refers to the average of three runs, while Table 4 of the proposed rule refers to the highest hourly average during the performance test. Commenter 17800 states that use of the “highest hour” makes no sense if the EPA is referring to Method 5 data, since runs are not measur ed in hours but in sample volume (and runs will be more than one hour). Both commenters recommend that the EPA provide a rationa le 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 bot h sections, as opposed to allowing for a 30 boiler operating days as done for the other HAP. Commenter 17725 recommends establishing a FPM limit as a surrogate for non-Hg metal HAP instead of TPM, which would do aw ay with the need for a PM “operating limit.”

Comment 47: Commenters 17681 and 17800 state that operat ing limits, including operating load limits and fuel limits, should not be esta blished for units using CEMS for compliance because requirements to measure operating parameters are unnecessary and overl y burdensome. For facilities using stack tests for compliance, the commenter recommends that the EP A allow sources to develop a CAM plan as an alternative to mandating operating limits, includi ng operating load limits and fuel limits.

Comment 48: Commenter 17881 states that the procedures in Table 7 are not c onsistent with the provisions of section 63.10011(b)(6 ) or the definitions in sect ion 63.10042. The commenter requests that, for Table 7, the EPA clarify that operating limits only apply in cases where CEMS are not used and does not apply for HF/HCl/Metals when you are demons trating compliance with the surrogate standards. The commenter requests that considerat ion be given to the form of the DSI or ACI rates as an absolute mass will not work at reduced loads. For ACI, the ra te has often been specified as lb ACI/mmACFM of flue gas.

Comment 49: Several commenters (17881, 17725, 18498) state that the limits for other operating parameters are inconsistent. Section 63.10042 defines the minimum operating parameters limits (minimum scrubber effluent pH, minimum pressure drop, minimum scrubber flow rate, minimum sorbent injection rate and minimum voltage or ampe rage) 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. Comm enter 18498 states that the “onesize-fits all” operating parameter lim it approach should be revised to a llow sources greater flexibility in defining representative operating parameters . Commenter 17881 requests the EPA must provide clarification as to howthe 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 proce ss 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 im provements discovered after initial compliance testing could potentially allow for the same or better cont rol 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 th at the “same process and control device operating conditions” language be removed from these regulatory sectio ns to be similar to language proposed in 40 CFR 63.10006 (e), (f), (g), (j), (k), (l), and (m ) where testing under those “same conditions” is not required.

Comment 51: Commenter 17718 notes that section 63.10022(a)(6) states that existing units with an ESP in an emission averaging option must “maintain the monthly fuel content values at or below the operating limit established during the most recent pe rformance test. The commenter requests that the EPA clarify why the presence of an ESP would re quire monthly fuel content determinations and suggests that the reference should be removed from the proposed regulation.

Response to Comments 46 - 51: As mentioned elsewhere, the co mments concerning control device operating parameters and fuel analysis 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 not conduct other monitoring, that the us e 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 betweenemissions testing, and th at 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 ru le now addresses each of those items.

7. Normal operating load.

Comment 52: Commenter 17174 states that section 63.10009( e) requires performance tests to be conducted at “maximum normal operating load.” However, section 63.10009(g)(2)(vii) requires demonstration of compliance with each of the app licable emission limit(s) to be achieved under “representative operating conditions.” The commenter re quests that the EPA clarif y this discrepancy and clearly define in section 63.10042 what constitutes maximum normal operating load or representative operating conditions.

Comment 53: Commenter 17731 states that the term “m aximum normal operating load,” section 63.10007(c), should be clarified and distinguished from “representative normal operating load.”

Response to Comments 52 and 53: The agency has reviewed the co mmenters’ concerns and revised the rule such that emissions test ing is to occur at normal operati ng conditions. Moreover, if an EGU owner or operator wishes to demonstrate compliance under other than normal operating conditions, the rule requires emissions testi ng at those other conditions.

8. 30-day rolling averages.

Comment 54: Commenter 17821 has the following recomm endations regarding 30-day rolling
averages:

 Section 63-10010(b)(5) contains language that could be inte rpreted to mean that an O 2 monitoring system is required for compliance withthese regulations. The la st sentence of this paragraph references developing 30-day rolling averages from “hourly oxygen emissions data.” Paragraph (b) of this se ction references using CO 2 monitoring. The commenter recommends that paragraph (5) of this section be modi fied 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 refere nces using “all the hourly...emi ssions data” to develop 30-day rolling averages. This language could be constr ued to mean that both valid and invalid data should be used to develop long-term averages. The commenter recommends that paragraph (5) be modified to include language to specify that only valid hourly data s hould be used to develop 30-day rolling averages.

 Section 63.10010(c)(5)indicates that a 30-day ro lling average for HCl should be developed; however the applicable engineering units are not specified. The commente r recommends that the EPA specify the engineering units that apply to the 30-day rolling averag e. Furthermore, this paragraph also references using “all the hourly HCl emissions data” to develop 30-day rolling averages. This language could be construed to me an that both valid and invalid data should be used to develop long-term averages. The comment er recommends that paragraph (5) be modified to include language to specify that only vali d 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 applicab le engineering units. The comme nter recommends that the EPA746 specify the engineering units that apply to th e 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 me an that both valid and invalid data should be used to develop long-term averages. The EPA sh ould modify this paragraph to include language to specify that only valid hourlydata should be used to deve lop 30-day rolling averages.

 Section 63.10010 (g)(5) indicates th at a 30-day rolling average fo r particulate emissions should be developed; however, the applicable engin eering units are not sp ecified. The commenter recommends that the EPA specify the engineer ing units that apply to the 30-day rolling average. Furthermore, this paragraph also refere nces using “all the hourl y particulate emissions data” to develop 30-day rolling av erages. This language could be construed to mean that both valid and invalid data should be used to develop long-term av erages. The EPA should modify this paragraph to specify that only valid hourly data should be used to develop 30-day rolling
averages.

Comment 55: Commenter 17681 notes an inconsistency between section 63.10010(g)(5) and Table 8. Section 63.10010(g)(5) states that 30-d ay rolling average is calculated as “the average of all of the hourly particulate emissions data for the preceding 30 boiler operating days.” In contrast, Table 8 states that the source is to convert “hourly emissions concentrations to 30 boiler operating mg/dscm values,” which suggests that compliance is assessed on the av erage 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 av erage of all applicable hours in the 30-day period.

Response to Comments 54 and 55: As mentioned elsewhere, the rule now allows CO 2 or O 2 CEMS to be used, clarifies that only valid hours are to be in cluded in the 30 boiler operat ing day rolling average, identifies the reporting units as ei ther pounds per heat input or pounds pe r electrical output, and clarifies that the 30 boiler operating day rol ling average is based on the aver age of all valid hours in the preceeding 30 days of boiler operation.

9. Fuel mixtures and switches.

Comment 56: Commenter 17696 recommends that the EPA cl early state that perf ormance testing on a “fuel mixture” does not require performance testing us ing coal of the same cl assification/common name that is provided by different supplie rs, different mines or different seam s. The commenter states that the proposal’s references to “fuel mixture” leave room for confusion even though the definition of “fuel type” (section 63.10042) is clear that individual fuel types received from different suppliers are not considered new fuel types. The EPA should clarify th at, 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 differe nt supplier’s subbituminous coals) and is not required to conduct perfor mance tests using each supplier’s coal or to test using a blend of subbituminous coal from each of its different suppliers.

Response to Comment 56: The agency considered the commenter’s concern and disagrees with the commenter’s suggestion that the rule needs to offer a dditional 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 switchi ng, he or she could use a CEMS option, rather than the emissions testing option, to demonstrate compliance.747 Comment 57: Commenter 18034 requests that the rule shouldarticulate 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 blendi ng and fuel switching are common practices utilized to minimize SO 2 emissions and the commenter recommends th at the EPA take into consideration and encourage environmentally beneficial practices such as fuel blending and fuel switching.

Comment 58: Commenter 17781 recommends that the EP A clarify section 63.9982(d) regarding switching coal rank or fuel type by revising the language as follows:

“An existing electric utility steam generati ng unit that has switched completely to burning a different coal rank or fuel type is considered to be an ex isting affected source under this subpart.”

Response to Comments 57 and 58: The agency considered the commenters’ concerns and disagrees with the commenters’ suggestions. As mentioned elsewhere, the rule maintains that EGU owners or operators are to operate at normal operating conditions using normal fuels; if fu el 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 rete sting based on fuel swit ching, he or she could use a CEMS option, rather than the emissions testi ng option, to demonstrate compliance. Moreover, the Agency sees no need to include the commenter’s s uggested language changes in the rule because such changes could be misconstrued as changi ng the current definition of modification.

Comment 59: Commenters 17808 and 17870 seek clarificat ion 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 mainta in electric system reliability, and could suddenly change from being an unregulated natural gas-fired un it to a regulated fossil fuel -fired generating unit (if the EPA does not adopt the above-proposed defin ition 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 uncl ear with regard to how much time the EPA would allow a newlydesignated fossil fuel-fired unit to schedule and perform its initial performance tests to demonstrate compliance with the applicable standards. Commenter 17870 recommends a period of 180 days from the date that a unit newly meets the de finition of an affected fossil fuel -fired unit subject to the rule.

Response to Comment 59: Although the agency has considered the commenter’s suggestions, the rule remains unchanged. An EGU owner or operator must re main cognizant of the de finitions in the rule, especially, for this instance, the definitions of natu ral gas-fired electric utility steam generating unit and of oil-fired electric utility steam ge nerating unit, along with rule requir ements that trig ger applicability and compliance dates.

10. SO 2 comments.

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 ong oing QA/QC requirements as allowed in section 63.10010(e). Commenter 17705 suggests that secti on 63.10021(a)(13)(ii) shoul d include a crossreference to section 63.10010 allo wing 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 requirement s of 40 CFR Part 75 can be used in lieu of monitors following 40 CFR Part 60.748 Comment 61: Commenter 17716 recommends that the EPA us e the Part 75 text on linear check tests instead of the text section 63.10010(e)(6 )(ii), which states that one “mus t 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 li nearity check “begins to lose its significance” at span values less than or equal to 30 ppm (63 FR 28032/28061 (May 21, 1998)).

Comment 62: Commenter 17714 requests that the EPA cl arify the language placement of the SO 2 monitor at the outlet of the EGU in section 63.10010(e) to definitively state that it refers to placing the monitor in the stack downstream of the SO 2 control device for the EGU.

Comment 63: Commenter 17821 notes an unintended conflict between sections 63.10 010 (e) and (e)(1). In paragraph (e), the EPA clearly states that sources operating an SO 2 monitoring system for purposes of compliance with 40 CFR Part 75 may continue to do so under these proposed rules. However, in paragraph (e)(1), the rule defines and limits the operation and quality assurance to specif ic sections of 40 CFR Part 60 without referencing the prior alternative to operate an SO 2 CEMS under 40 CFR Part 75. The commenter recommends that the EPA modify paragr aph (e)(1) of this secti on to clearly state the EPA’s intended use of 40 CFR Part 75 for applicable sources.

Response to Comments 60 – 63: As mentioned elsewhere, the rule has been clarified to allow use of Part 75 procedures for those CEMS subject to the ru le and used in the Acid Rain Program. Moreover, the rule has been clarified so that CEMS are to be placed at the outlet of an EGU.

Comment 64: Commenter17881 states that none of the definitions for the term Er (regarding rolling emission averages in Equati ons 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 incl uded 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 65: Commenters 18498 and 17725 recommend that the EPA add a subsection to section 63.10010(e), which clarifies that bias adjusted data and Part 75 missing data shall not be used in calculating the 30 boiler operating day average SO 2 emission rate. Although this is discussed in appendix A to subpart UUUUU for Hg CEMS (Refer ence appendix A sections 1.4 and 4.1.2.4), this data exclusion is not cl early stated for SO 2 CEMS.

Response to Comments 64 and 65: The agency agrees with the commenter that SO 2 should be included in all equations with the term E r , and the rule has been revised to correct that omission. The agency disagrees with the commenter that additional langua ge 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 operati ng day rolling average. Moreover, the EGU owner or operator would have to report the period of missing data to the Agency for further review and potential enforcement action.

11. Testing guidelines and timeline comments.

Comment 66: Commenter 17821 recommends that the EPA review the inconsistencies regarding section 63.10030(a) and section 63.1 0030(d). Section 63.10030(a) requires submission of all of the notifications in section 6 3.7(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 6 3.9(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 submissi on of a “Notification of Intent” to conduct a performance test, but “at l east 30 days before the performance test is scheduled to begin.” Requiring submission of two identical notices at different times ma kes no sense. If the EPA intends to allow submission of the notice only 30 days before the te st, the EPA should identif y as “inapplicable” the inconsistent notice requirements. If the EPA intends to require submission 60 days before the test, the EPA must remove the redundant re quirement in section 63.10030(d).

Response to Comment 66: The agency agrees with the commenter’s concerns, and the rule will be revised to have a consistent submi ssion date for the notific ation of intent to c onduct performance testing.

Comment 67: Commenter17758 requests that the EPA speci fy whether the time ranges provided for testing guidelines in section 63.10006( n) refer to calendar or operati ng days to avoid confusion. The commenter recommends that the pr eferred option should be in terms of operating days or operating quarters since these terms are used routinely by ut ilities to manage emissions program schedules and give utilities the flexibility necessary for performing the required tests.

Response to Comment 67: The time ranges in the rule refe r to calendar, not operating, days.

Comment 68: Commenter 17821 requests that the EPA either identify when EGUs are not required to submit a Notice of Compliance Status or revise the section to make clear th at 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).” Ho wever, under proposed sect ion 63.10005(a) all EGUs “must demonstrate initial compliance with each of the applicable emi ssion limits in Tables 1 or 2” Moreover, section 63.9(h) on its face applies to eachaffected source when it becomes subject to a relevant standard.

Response to Comment 68: The agency disagrees with the comment er’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 CE MS or for stack tests. The rule language has not been revised.

Comment 69: Commenter 17821 requests that the EPA issue a rule that clearly articulates the various compliance demonstration options. The commenter also notes that under paragraph (3), the Notification of Compliance Status must include “[i]dentificat ion of whether you plan to demonstrate compliance with each applicable emission limit through performan ce testing and fuel analys is; performance testing with operational limits (e.g., CEMS for surrogates or CPMS); CEMS; or so rbent trap monitoring system.” The listed options do not a ppear to correspond with the rest of the proposed rule. For example, proposed section 63.10011(b) appears to require all EGUs that conduct performance testing to perform fuel analysis and to set operational limits.

Response to Comment 69: As mentioned elsewhere, much of the commenter’s concern is moot because rule no longer requires fuel analysis for pollutants or operational limits for control device parameters. Although the Agency disagr ees with the commenter’s assertion that the rule is unclear with respect to compliance demonstration options, the rule has been revise d 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 ap plicable emission limits under the proposed rule. The commenter questions whether the intent is to simply allow the common st ack to comply with the most stringent emission limit that applies to any of the affected EGUs that exhaust to the common stac k. If so, the commenter recommends that the regulatory language should more clearly re flect this intent.

Response to Comment 70: The agency disagrees with the comme nter’s concern that the language regarding appropriate emissions lim its from differing units sharing a common stack is confusing. The rule retains language requiring an EGU owner or ope rator who chooses to use emissions averaging to shut down units not subject to th e rule during performance testing or to operate all units sharing a common stack at or below the most stringent emissi ons limit to which any i ndividual 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 choos e not to use emissions averaging.

Comment 71: Commenter 17881 requests that section 63.10021( a)(4) be revised for clarity because EGUs without HCl CEMS are required to test monthly or bimonthly. Thus, the tests would already be conducted within the frequency (60 da ys) specified in the paragraph.

Response to Comment 71: The comment is moot, for the rule nowrequires EGU owners or operators who choose to use emissions testing as the complia nce option for acid gas emissions limitations to conduct testing every quarter.

Comment 72: Commenter 17718 requests the following modifi cations to improve the clarity regarding performance testing:

 Section 63.10006(o) states that the ability to de crease the frequency of performance testing from annual (or more frequent) is available if test ing 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 in crease emissions.” The commenter requests that the EPA provide clarification on what constitutes “no change” and what information would be needed to successfully pass these criteria. For example, it is unclear whether the “no change” provision applies to the affected unit and is no t inclusive of the entire facility.

 Section 63.10007(c) requires perfor mance tests to be conducted “whi le burning the type of fuel or mixture of fuels that has the highest cont ent...” The commenter recommends that the EPA clarify whether reference to “type of fuel” simp ly means that if bitumi nous coal is typically burned, then bituminous coal is to be used during th e test. This section does not appear to require a determination that the highest chlorine (or other cons tituent) content bituminous coal be used during the test. The commenter also suggests a clarification that “s pecial fuels” are not required or expected for the performance test.

 Section 63.10007(f) states that “(p)erformance test s 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 sect ions of the regulato ry language. If the specifications are the same the commenter recommends that section 63.10007(f) should be removed.

Response to Comment 72: The agency disagrees with the commente r’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 st atus. Those EGU owners or operato rs are in the best position to understand what changes could cause impacts on emi ssions and remain responsible for EGU emissions;751 should an EGU owner or operator be uncomfortable m eeting the LEE eligibility requirements, he or she need not apply. As mentioned elsewhere, the commen t concerning highest polluta nt content in fuel is moot, as fuel analysis for pollutants is no longer required. Finally, as mentioned elsewhere, the rule now requires emissions testing be perf ormed at normal operating conditions.

Comment 73: Commenter 17718 requests that EPA clarify whether section 63.10009(c) requires that a “pre-test” be conducted so that a comparison can be made between a “30 day afte r” value and the initial compliance test. Section 63.10009(c) states that, “... the emission rate achie ved 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 empl oyed 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 s ubmittal requirements for such a test.

Response to Comment 73: The rule has been revised so that an EGU owner or operator who chooses to use emissions averaging must be able to demons trate compliance on a 30 (o r 90) boiler operating day rolling average basis, which means that those owners oroperators will need to ensure 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 emi ssions testing is used for compliance determination by 180 days after the effective da te of this rule. Should an EGU owner or operator find these requirements to be of concern, he or she should choose not to use the emissions averaging option.

12. Other comments.

Comment 74: Commenter 17711 states that the word “sources” as used in the last clause of sections 112(d)(3)(A) and (B) is ambiguous and, therefore, sus ceptible 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 EP A has emissions information. Notably, the second use of the word “sources” in section 112 (d)(3)(A) also clearly is a reference to sources for which the EPA has emissions information. So, it is reasonable to c onclude that Congress inte nded 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 sec tion 112(d)(3)(A) a nd “fewer than 30 sources” at the end of section 112(d)(3)(B) reasonably should be c onstrued as a reference to sources for which the EPA has emissions information. This interpretation avoids the “absurd results” described above and allows for the EPA to naturally reconcile the application of sections 112(d)(2)(A) and (B) suchthat the number of sources for which the EPA has emissions information in a given category or subcategory dictates whether sections 112(d)(2)(A) or (B) should apply.

Response to Comment 74: The EPA does not agree with the commenter’s interpretation. When Congress qualifies a word in one pl ace but not others in the same s ection, the more reasonable inference is that it intended the qualification to apply only to that one instance.

Comment 75: Commenter 18034 supports the proposed emissi ons 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 auth ority is responsible for review and approval the emissions averaging plans even if the state has no t received delegation from the EPA for the specific NESHAP rule. The commenter states that it is unnecessary for the EPA to use a separate term within the752 emissions averaging section. If a state accepts dele gation of the final version of the proposed new subpart UUUUU, using the term “administrator” w ould apply equally for the emissions averaging provisions as it does to the other provisions of the rule. If a state has not received delegation for the NESHAP rule, not only would the state have no authority to issue an approval under section 63.10009(g), the state is under no obligat ion to review the plans on the EPA’s behalf. The commenter recommends that the EPA should use the standard termof “the administrator” used elsewhere in the proposed rule to avoid confusion.

Response to Comment 75: The agency agrees with the comment er’s suggestion an d has revised the rule.

Comment 76: Commenter 17174 suggests the following areas which would benefit from additional review and clarity.

 Section 63.10009(a) states “you may demonstrat e compliance by emission averaging among the existing EGUs in the same subcategory, if your av eraged emissions for such EGUs are equal to or less than the applicable emission limit” Howe ver, 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 emissions from all existing units participating in the emissions averaging option do not exceed the emission limits in Table 2.” The commenter r ecommends that the same wording be used in both sections in order to avoid confusion.

 Section 63.10009(e)(1) requires a fac ility to use Equation 1 to de monstrate 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 h eat input capacity. The commenter requests that the EPA clarify what c onstitutes 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 un its from nonaffected uni ts vent to the common stack, the units from nonaffected units must be shut down or vent ed 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 phr ase be evaluated and rewritten for clarity.

 Although section 63.10009(g)(1) states that implem entation plan “must” be submitted no later than 180 days before the facili ty intends to implement the plan, section 63.10009(g) indicates that implementation plan submittal is onl y necessary “upon request.” The commenter recommends that the requirement to submit animplementation plan for emission averaging compliance should be evaluated and edited fo r consistency across sections. Commenter 17821 also seeks clarification regarding the discrepancy between sections.

 Section 63.10021(a)(16)(vii) should clarify whethe r performance tune-ups needs to be submitted electronically to the EPA’s Central Data Ex change (CDX) by using the Electronic Reporting Tool (ERT), as required in other parts of this section (63.10021(a)(11) and (17)).

Response to Comment 76: Although the agency notes that the a pplicable 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 subcategory, the limit given in §63.1 009(a)(2)), the rule has been revise d to be consistent. The agency does not agree that additional clarification on maxi mum 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 su ch that the sentence of concern now begins as “If emissions from affected units and from nonaffected units...” The rule has been clarified so that an averaging plan need only be submitted if requested by the Administrator. As a performance tune-up is a performance test, and the rule already requires performance test results to be submitted electronically using the CDX, no753 additional clarificati on language is needed.

Comment 77: Commenter 17716 requests the followi ng corrections and clarifications:

 The rule does not include the equations for cal culating PM or HCl ma ss emissions. Appendix A only includes equations for Hg. Comm enter 17725 also notes this issue.

 Section 63.10009 (j)(3) references opacity requi rements, however no opacity operating limits have been introduced as part of th e rule. Commenters 17725, 17775, 18498-A2, 19120-A1and 18014 also took notice and have requeste d 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 pre ceding 30 boiler ope rating days.”

Response to Comment 77: As mentioned elsewhere, Table 5 de scribes how mass emissions can be calculated. The rule no longer contains opacity require ments, which were included in the proposal in error. As mentioned elsewhere the ru le has been revised to include CO 2 as well as O 2 measurements.

Comment 78: Commenters 17675 and 17718 request that the reference in section 63.10010(a)(4) to “paragraph 2.1 of this secti on” does not specify if it is referring to appendix A or another paragraph 2.1. The commenter s recommends that the rule clearly state the proposed monitoring methods for stacks on units with main and bypass stacks.

Response to Comment 78: The agency agrees with the commenter, and the rule has been revised to clarify installation requirements.

Comment 79: Commenter 17681 requests that the EPA further explain what constitutes sufficient monitoring for control devices in section 63.10009(g)(2)(vi)(B).

Response to Comment 79: As mentioned elsewhere, this comme nt 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 NO X lacks definition and needs explan ation prior to the rule being finalized in order to comment.

Response to Comment 80: Although the agency disagrees with the commenter’s suggestion that the flame optimization requirements need additional explanation, the rule ha s been clarified with respect to these requirements.

Comment 81: Commenter 17756 requests that the EPA clar ify the language regarding “dry flue gas technology.” The commenter states th at the rule does not clearly i ndicate whether “dry flue gas technology” includes both dry scrubber s and dry sorbent injection. The commenter recommends that the EPA revise the language to specify that dry sorb ent injection is an acceptable dry desulfurization technology.

Response to Comment 81: We believe that the definition in the final rule clearly indicates that both “dry scrubbers” and “dry sorbent injection” are included in “Dry fl ue gas desulfuriz ation technology.”

Comment 82: Commenter 18023 states that to provide effi cient application of the proposed rule, 4.1.3 Diluent Gas, Flow Rate, and/or Mo isture Monitoring Systems should stat e that “Monitors that have been754 certified and quality assured to meet the require ments of 40 CFR Part 60 and/or 40 CFR Part 75 are acceptable for the purpose of calculating and reporting emissions without any additional certification or quality assurance.”

Response to 82: In the final rule, section 4.1.3 of Appendix A st ates that the flow rate, diluent gas, and moisture monitoring systems that are used to convert Hg concentrations to units of the standard must be certified according to 40 CFR Part 75. This is nece ssary, since all of the CEMS data will be collected using the ECMPS system. Section 6 3.10005(d) specifies that if a conti nuous monitoring system has been previously certified under another State or Federal program and is continuing to meet the on-going QA requirements of that program, no additional performance evaluations of the monitoring system are required for Subpart UUUUU, provide d that the applicable require ments of §§63.10010(b) through (h)
are met.

Comment 83: Additionally, commenter 18023 states that s ection 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 va lue to the next highest integer multiple of 10. This would essentially re strict the span value to either 2 μ g/m3 or 10 μ g/m3. The rule should allow the user to set the span value anywhere between 2 and 10 μ g/m3 as long as that range falls within acceptable limitations of the NIST traceable calibrator.

Response to Comment 83: The final rule provides sources with gr eater 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 inte ger; (b) the next highest multiple of 5 μg/m 3 or; or (c) the next highest multiple of 10 μg/m 3

.

Comment 84: Commenter 17881 states that section 63.10011(c )(5) should clarify whether compliance can be based on all HAP metals in aggregate or individual metals.

Response to Comment 84: As mentioned elsewhere, this comme nt is moot for the rule no longer requires fuel analysis of pollutants.

Comment 85: Commenter 17718 states that within the pr oposed regulatory language seen in 40 CFR 63.10005(l), it is mentioned that a “default diluents gas con centration value of 10.0 % O 2 or the corresponding fuel-specific CO 2 concentration” are to be used dur ing periods of startup or shutdown when calculating emissions in units of “lb/MMBtu ” or “lb/TBtu.” The EPA should clarify how to calculate the “corresponding fuel-specific CO 2 concentration.”

Response to Comment 85: As mentioned elsewhere, this comme nt is moot for the rule no longer requires emissions limits during pe riods of startup or shutdown.

Comment 86: Commenter 17795 requests that the EP A 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 shutdowndefault 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 refe rence to a fourth level needs755 to be removed because there is no additional be nefit or reason to run four gases during a linearity. This additional calibration level wi ll not make the system 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 st artup or shutdown, the rule allows use of Part 75 quality assurance requirements for those monitors th at are also used in the acid rain program, and the reference to a fourth level was removed from th e rule, even though it was an optional requirement.

Comment 87: Commenter 17714 recommends that the defi nitional language regarding “monitoring system malfunction” be moved into the definition area of the rule identified as s ection 63.10042 since it appears to be more of a de finition than a requirement.

Response to Comment 87: The final rule will include a definition of monitoring system malfunction in the definitions section of the rule. That definiti on will mirror the definition for monitoring system malfunctions found in the proposed rule.

Comment 88: Commenter 17881 requests the followi ng clarifications and revisions:

 Information regarding the unit or stack operating tim e [7.1.2.2] is not needed in order to calculate the Hg emission rate in units of lb/GWh, nor is it needed to calculate the lb/TBtu emission rate. Thus, the commenter requests that the require ment to collect this data be deleted.

 The commenter also requests that the EPA clarify that the hourly gross unit load [7.1.2.3] is only needed for those units which are attempting to demonstrate compliance with a lb/GWh Hg emission limit.

 Information regarding the hourly heat input rate [7.1.2.4] is not needed to support the lb/GWh Hg emission rate calculations. Th e use of fuel factors in conjunction with the Method 19 equations allow the determination of a lb/TBtu em ission 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 dete rmination, the F-factor is not used to calculate the heat input rate. Thus, the commenter re quests 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 s ection 7.1.5 that volumetric flow rate records are required for purposes of determining lb/TBtu em ission rates pursuant to section 6.2.1. None of the referenced Method 19 Equations (i.e., 19-1 – 19-9) rely on volum etric flow rate; rather, these equations rely on pollutant and di luent concentrations, fuel factor s, and in some cases, flue gas moisture content. Thus, the EPA should clarify th at volumetric flow rate measurements are only required for those units relying on sorbent trap monitoring systems and/or conducting lb/GWh mercury emission rate calculations.

 Section 7.1.5.2.5 requires the repor ting of hourly PMA, however the commenter states that the requirement is not appropriat e when missing data substituti on is being prohibited.

 Section 7.1.7 contains provisions related to diluent gas records in cases where compliance is being demonstrated on a lb/TBtu basis. Section 7.1.7.1 currently states that 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 c ited 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 carefully review the two sets of reporting provisions and clearly reconcile any differences between the provisions.

Response to Comment 88: The agency has reviewed the commente r’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 te xt has been revised to remove hour ly 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 in cluded. The language in section 7.1.7.1 has been revised “...to convert Hg concentrations to units of the standard.” Finally, the agency belie ves 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 pr oduction rate for outputbased emissions calculations but doe s not explain what pollutant con centrations should be used. The commenter requests that the pollutantconcentrations be clearly state d. The commenter also requests that the EPA revise the rule to address the cal culation 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 limitatio ns, during periods of startup or shutdown.

Comment 90: Commenter 18034 states that provisions in the affirmative defense rules need clarification or appear to be contradictory:

 Section 63.10001(a)(4) unnecessarily requires add itional conditions to meet an affirmative defense to bypass a control device. In some circumstances, the bypass may be the most appropriate temporary implementation while correct ing or repairing a condition of upset, since the upset may be with the control device itself. All actions required to meet an affirmative defense are sufficiently listed in the other provisi ons of section 63.10001(a) and must be met, including those actions desi gned to minimize emissions.

 Section 63.10001(a)(7) lists a requirement that “All actions in response were properly documented by properly signed contemporaneous operating logs,” but does not define or accurately describe what would fulfill that requirement.

 Section 63.10001(a)(9) requires “a written root cause required to determine, correct, and eliminate the primary cause of the malfunction.” This inevitably leads to an owner or operator attempting to describe a preventative action to an event that (by definition of one of the criteria) was not preventable.

Response to Comment 90: We believe the language is clear, not contradictory in nature, and provides an owner or operator a systematic and thorough approach for establishi ng 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, wh ich several states have adopted into their SIPs. We do not have any indicati on that parties to enforcement proceedings have had any significant difficultie s applying the terms of these SIP affirmative defenses. (See, e.g., State Implementation Plans: Policy Regarding Excessi ve 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 by EPA. ((40 CFR 50.1312). The EPA’s view is that use of consistent terms in establishing affirmative defense regulations and policies across various CAA programs will promote consistent implementation of those rules and policies. The EPA notes that the purpose of the root cause analysis is to determine, correct, and eliminate the primary cause of the malfunction and that the root cause analysis itself does not necessarily require that the cause be determined, corrected or eliminated. However, in most cases, the EPA believes that a properly conduc ted 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) does not include a reference to CO 2 records.

Response to Comments 91 and 92: As mentioned elsewher e, the rule now incl udes carbon dioxide as well as oxygen, where oxygen is referenced.

Comment 93: Several commenters (17730, 17758, 17800) state that several provisions indicate that the requirements apply “as applicable,” but few provisions clearly state to which EGU subcategory or to which option the requirement applies. For example, the overuse of ‘‘as applicable” makes it difficult for the regulated source, or the state agency that will likely implement the program, to fully understand the requirements or demonstrate compliance with th e chosen option. Commenter 17758 recommends that the EPA update the regulatory language to be consis tent 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 inconsistentwith EO 13563, as discussed else where in these comments, which requires agencies to tailor regulat ions to impose the least burden on society, consistent with obtaining regulatory objectives.

Response to Comment 93: The agency disagrees with the comme nters’ suggestions. An EGU owner or operator who does not have applicable requirements is not subject to the provision s 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 demonstra tion method. Apart from some clarification, the rule remains unchanged. As mentioned elsewhere, the rule no longer requires sepa rate operating parameter monitoring from emissions control devices if CEMS are used as the compliance demonstration method. Although the emissions testing frequency has been re duced to quarterly, it remains consistent with supplying the information necessary to show compliance with the emissions standard. Should an EGU owner or operator find the emissions testing comp liance method too burdensome, he or she should choose from among the other options for demons trating compliance with the emissions limits.

Comment 94: Similarly, commenter 17800 states that due to the incorrect references to sections, incorrect citations and many other inconsistencies and misstatements within the proposed rule, it is difficult for the commenter to evaluate what is ne eded to comply and determine the best plan for compliance with this rule. The commenter requests th at remove the many incons istencies noted before sources are expected to justify the expenditures associ ated 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 suggestions.

Comment 95: Commenter 17909 states that the non-Hg me tal HAP rules and compliance provisions portion of the proposed rule are indis cernible. Despite diligent, protract ed study of the ru le, participation in many, many conference calls and discussions with consultants, lawyers and the EPA staff, the commenter is unable to follow the ra tionale in the rule and therefor e cannot apply the requirements to our affected source, plan for compliance oreffectively comment on the proposed rule.

Response to Comment 95: Although the agency remains concerne d that an EGU owner or operator claims difficulty understanding non-Hg metals rule options , the rule’s flexibility in that regard appears to be understood, if not welcomed, by a large majo rity of commenters. Basically, an EGU owner or operator chooses a PM emissions limit, or individual non-Hg metals emis sions 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 emissi ons testing to use of PM CPMS to use of PM CEMS. Notwithstanding a few clarifi cations as discussed elsewhere, th e rule maintains this flexibility. The commenter should contact the Ag ency 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 statis tical 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 notedduring the public comment period as soon as they were brought to our attention and believe that commenter s had sufficient review time with the corrected values to provide meaningful comm ent. 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 unam biguous: “requirements of the act” cannot be read to include only acid rain control.

Response to Comment 97: To the extent that EGUs are subj ect to other cont rol requirements established by states and tribes as part of their strategies to attain the NAAQS, these are not “requirements of the act.” Similarly, requirements established as a result of specific new source permitting are in compliance with CAA-mandated programs but are not requirements of the act. The EPA did not state that the only re quirement of the CAA contemplated in section 112(n)(1)(A) was the Title IV Acid Rain Program.

13. Reference and numerical corrections.

Comment 98: Commenter17796 notes that the Hg limit inthe preamble is a typo and should read 0.0007 lb/GWh.

Response to Comment 98: The limits in the final rule have been reanalyzed and corrected.

Comment 99: Commenter17848 notes that the preamble contai ns an error in the output-based limit for Hg. The rule text indicates that the emission limitshould be 0.008 lb/GWh, [how ever Table 1 indicates that it is 0.0008lb/GWh].759 Response to Comment 99: The limits in the final rule have been reanalyzed and corrected.

Comment 100: Commenter 17881 agrees with the intent of section 63.10005(l) but notes that the proposed rule erroneously identi fies this paragraph as 63.10005(1).

Response to Comment 100: The comment is moot because the rule now requires work practice standards, not emissions limitations.

Comment 101: Commenter17655 recommends that the paragr aphs (p) and (q) in section 63.10006 be renumbered as (o)(1) and (o)(2) because they are not free-standing but instead with in the context of (o). The commenter also recommends thatif these changes are made, the re ferences to paragraphs (p) and (q), such as section 63.10006(n) be updated for consistency.

Response to Comment 101: The rule has been revised to consolidate the LEE requirements.

Comment 102: Several commenters (17696, 17718, 18037, 17821) not e incorrect cross references in the text of the proposed rule. For example, sect ion 63.10006(r) states “If you are required to meet an applicable tune-up work practice standard, you must conduct a performance tune-up according to §63.10007. Each performance tune-up specified in § 63.10007 must be no more than 18 months after the previous performance tune-up.” Section 63.10007 a ddresses only performan ce testing. Commenter 17718 states that if “performance tune-ups” is the correct term, it appears th at section 63.10021(a)(16) would be the more accurate section reference.

Response to Comment 102: Although the agency believes a tune-up serves as the performance test for certain EGUs for certain pollutants, the rule has been revised to describe the tune-up as a performance tune-up.

Comment 103: Commenter17174 notes the fo llowing 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 th e 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). Co mmenter 17881 also notes this inconsistency.

Response to Comment 103: As mentioned elsewhere, the commen ts are moot because rule no longer requires emissions limitations during periods of st artup or shutdown, monitoring of control device operational parameters, or fu el analysis for pollutants.

Comment 104: Commenter17718 states that the reference in section 63.10010(b) to appendix A .”..in lieu of procedures in paragraphs (a)(1) through (a)(3 ) below....” is inaccurate because they do not pertain to O 2 and CO 2 monitors. The EPA likely needs to correctthis reference to (b)(1) thro ugh (b)(5).

Response to Comment 104: The cross-reference to paragraphs (a)(1) through (a)(3) was clearly incorrect, and should have been (b)(1 ) through (b)(5), as noted by the co mmenter. Note, however, that in the final rule, the Agency has removed the Part 60 certification and QA alternative for diluent gas monitors, since all of the CEMS data will be collected using the ECMPS system. Section 63.10010(b) of760 the final rule specifies that the CO 2 or O 2 monitors must be certified and quality-assured according to Part 75.

Comment 105: Commenters 17705 and 17775 note the foll owing reference inconsistencies:

 Section 63.10021 (a)(10) references compliance w ith paragraphs (a)(10)(i) through (iii), but subsection (iii) is missing. Commenters 17821 and 17881 also note th is inconsistency.

 Section 63.10021 (a)(11) references compliance with paragraphs (a)(11)(i) through (iv), yet the rule text includes additiona l paragraphs (v) and (vi).

 Section 63.10021 (a)(12) references compliance w ith paragraphs (a)(12)(i) through (iii), but subsection (iii) is missing. Commente r 17881 also notes this inconsistency.

 Section 63.10021 (a)(13) references compliance w ith paragraphs (a)(13)(i) through (iii), but subsection (iii) is missing.

 Section 63.10021 (a)(14) references compliance w ith paragraphs (a)(14)(i) through (iii), but subsection (iii) is missing.

Response to Comment 105: The agency appreciates the comments, and the rule has been revised to remove these inconsistencies.

Comment 106: Several commenters (19536, 19537, 19538) state that although the de fault 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 with in the proposed regulato ry 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 “par agraph (l)” seems to point to “63.10005(l)” which discusses default diluents gas con centrations to be used for calcul ating 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 cl arify or provide guidance on how these two sections are to be used to aid qualification of LEE status.

Response to Comment 106: As mentioned earlier, these comment s are moot, for the rule no longer requires emissions limitations duri ng periods of startup or shutdown.

Comment 107: Commenter-17775 notes the following incorrect or missing references:

 Section 63.10005(k)(3) refers to section 63.10010(k )(3) however, there is no such provision. Commenter 17696 also notes this inconsistency.

 Section 63.10010(e) refers to pr ocedures 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.” Ta ble 5 addresses “Performance Stack Testing Requirements.” Commenters 17752 and 17718 also note this incorrect reference. Commenter 17718 states that it appe ars that the EPA should have re ferenced Table 4 or Table 7 instead.

 The reference in section 63.10011(b) to paragr aph (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. Ther e is no section (b)(5) between (b)(4) and (b)(6). Commenter 17881 also notes this inconsistency.

 Section 63.10021(a)(8) refers to “maximum Hg input using Equation 9 of § 63.10011.” The761 section and Equation 9 address non-Hg metals . Commenter 17752 also notes this incorrect reference.

 Table 4 states “If you demonstrat e compliance using ... Fuel Analys is, you must “[m]aintain the fuel type or fuel mixture such that the a pplicable emission rate calculated according to §63.10011(d)(3), (4) and/or (5).

Response to Comment 107: The comments are moot, as descri bed elsewhere the rule no longer requires operating parameter monitoring along with so rbent tube monitoring sy stem monitoring, requires the use of Part 75 monitoring for those sources that al so use monitors for the acid rain program, requires the establishment or monitoring of control device ope rating parameters, or requires fuel analysis of pollutants.

Comment 108: Commenter 17752 notes an incorrect reference in section 63.10031 (c).

Response to Comment 108: Although the comment lacks specifici ty, the agency has reviewed the section and revised the rule to correct references.

Comment 109: Commenter 17821 notes that appendix A, se ction 7.2.5.3.3 refers to paragraphs 7.1.2 through 7.1.19. Section 7.1 ends with paragraph 7.1.10.8. The EPA should modify this paragraph to correct the misidentified range of paragraph numbers.

Response to Comment 109: The reference to section 7.1.19 was a typographical error, which has been corrected in the final rule.

Comment 110: Commenters 17881 and 17718 note that paragra ph (a)(4) of section 63.10010 references “systems described in paragraph 2.1 of this sec tion,” but there is no paragraph 2.1. The commenter suggests that it is likely that th e EPA meant to reference section 2.1 in appendix A of proposed 40 CFR Part 63, subpart UUUUU instead.

Response to Comment 110: The reference in §63.10010(a)(4) to “p aragraph 2.1 of this section” was clearly an error and has been removed from the rule.

Comment 111: Commenter 17881 notes that in paragraph 63.10021(a)(14)(ii), the reference should likely be “Appendix A of this part.”

Response to Comment 111: The reference in §63.10021(a)(14)(ii) to “procedure 5 in Appendix F of 40 CFR Part 60” was incorrect and should have been “Appendix A to this subpart”, as suggested by the commenter. However, note that in th e final rule, all CEMS certifica tion and QA requirements have been removed from §63.10021 and have been c onsolidated in §§63.10010 (b) through (h).

Comment 112: Commenter17821 recommends that the EPA revise the reference in section 63.10021(a)(16)(vi) to reflect the language in secti on 63.10006(r) which states that each performance tune-up must be no more than 18 mo nths after the pr evious tune-up.

Response to Comment 112: The agency has revised the rule so that the performance tune-up testing frequency is consistent.

Comment 113: Commenter 18498 suggests that section 63.10021 (h)(ii) should be revised to reference appendix A or more specifically, se ction 5 to appendix A. The commen ter states that for Hg CEMS,762 section 63.10021 (h)(ii) states the “Quarterly accuracy determinati ons and daily calibration drift tests shall be performed in accordance with procedure 5 in Appendix F of 40 CFR Part 60.” and contradicts section 63.10010(f) which references appendix A of this subpart.

Response to Comment 113: Section 63.10021 does not have a paragr aph (h)(ii). The commenter is probably referring to §63.10021(a)(14)(i i), which references Procedure 5 in Appendix F of Part 60. See the response to Comment 113, above.

Comment 114: Commenter 17881 notes that the following references and sections are wrong:

 reference to section 63.10021(a )(10) in section 63.10031(g)(1)

 reference to section 63.10032(b) and (c) in section 63.10032(d)(5)

Response to Comment 114: The rule has been revised to correct the cross references.

Comment 115: Commenter 17718 states that that the refe rence in section 63.10021( a)(2) to section 63.10031(c) for keeping records of fu els should be section 63.10032(d) which outlines what fuel records are to be kept.

Response to Comment 115: The comment is moot, for the rule no longer requires fuel analysis of pollutants.

Comment 116: Commenter 17881 notes typographical erro rs 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 ventto 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 m eet the most stringent emissions limit”

Response to Comment 116: As mentioned elsewhere, the rule has been revised to cl arify the language.

Comment 117: Commenter 17691 notes the following typographical errors in the rule:

 At 76 FR 25036, ECPMS could be modified [ .. .], ECPMS should be ECMPS.

 At 63.9990, “(2) EGUs designed for coal< 8,300 Btu/l b. (b) Oil-fired EGUs are [ ... ], 40 CFR 63 .9990(b) should begin on the next lin e for better understanding. 76 FR 25103

 At 63.10005, the numbering of the 63.10005(k) is outof 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 comment er’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 re quires establishment of maximu m pollutant fuel input levels.

Comment 118: Commenter 17691 states that the rule refers back to a site-specific monitoring plan required by section 63.10000(d) in several places, however, secti on 63.10000(d) says there is an exemption in which some sources will not need a s ite-specific monitoring plan(i.e., facilities with763 existing monitoring plans that meet the requirem ents of section 63.10010). Then, the proposed section 63.10010 refers back to 40 CFR 63.10000(d). The commenter states that this circ ular reference causes confusion, makes the regulation difficult to follow, and should be eliminated. The commenter suggests that for each instance wh ere the text refers back to the pr oposed 40 CFR 63.10000(d), there should be additional language to address the exemption.

Response to Comment 118: Although the agency disagrees with the commenter’s assertions, the rule has been revised so that only thos e EGUs without existing site-specifi c monitoring plans are required to submit those plans.764 8E - Rule: Other Language Corrections

Commenter : 17851

Comment 1: Commenter 17851 states that it is impossibl e to eliminate the causes for certain malfunctions, such as lightning strikes. The co mmenter also recommends that the EPA allow notification by email or other electronic means in a ddition to faxing to make th e rule more modern and useful. The commenter requests that the rule be modified to in clude these notification methods.

Response to Comment 1: The agency agrees that some causes for malfunctions may be difficult to eliminate, which is why the rule offers EGU ow ners or operators the ab ility to describe the circumstances concerning a malfunction in a repo rt. The agency understands and appreciates the commenter’s suggestion regarding use of electronic mail, but at this time the ru le has not been changed to allow it for notification purposes. As the agency works through security and routing issues, the rule may be revised in the future to a llow for electronic mail notification.

Comment 2: Commenter 17691 requests an inclusion of an equation in 40 CFR 63.10009 to provide a compliance demonstration method for each individual affected unit exhausting through a common stack.

Response to Comment 2: The EPA disagrees with the commenter’s suggestion. As mentioned elsewhere, the rule contains instructions on how EGUs sharing a common stack and subject to an emissions averaging program meet eligibility requ irements 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 le tters expressing general support for the EGU NESHAP. Due to the high number of such comment s for this proposed rule, these comments were categorized and sorted according to th e group that organized the mass-mailing.

The U.S. Docket office identified 664,695 mass-mail comment letters and assi gned them to 65 DCNs. These mass-mail DCNs are listed in Table 9A-1 of this sec tion 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 ge neral support that are not associated with any mass-mail campaign are listed in Ta ble 9A-21 in this section.

Many organizations provided members with form le tters. 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 Amer ican 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 stan dards, particularly in regard to the standards’ effect on human health. Further comments from the American L ung Association can be found in the document in comments from commenters 16826 and 18445.

Commenters (19111, 19210, 19225) representing chapters of the National A udubon 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 un its and is part owner of four additional units ranging in size from small to large, anticipat es the units will achieve the proposed standards, and therefore supports the proposed subcategories and emissions standards for coal-fired EGUs and agrees that they are consistent with requirements in the CAA.

Response to Comments 1 - 2: The EPA appreciates the commenters’ support for the Mercury and Air Toxics Standards.766 Section 9A Tables

Mass Mailings - General Support for the Proposed Rule

Table 9A-1. Mass mail comments identi fied by the U.S. Docket Office

DCN Docket Entry Count

3084 Early Mass Comment Campaign sponsor ed by National Wildlife Federation (NWF) 10,845

3085 Early Mass Comment Campaign sponsor ed by Environmental Defense Fund (EDF) 66,532

3086 Early Mass Comment Campaign spons ored by League Of Conservation Voters 65,149 3087 Early Mass Comment Campaign sponsored by Sierra Club 27,019

3088 Early Mass Comment Campaign s ponsored by Union of Concerned Scientists 10,872

3089 Early Mass Comment Campaign sponsor ed by American Lung Association Action Network 2,116 3090 Early Mass Comment Campaign s ponsoring organization unknown 3,053

3091 Early Mass Comment Campaign s ponsored by Union of Concerned Scientists 47 6638 Mass Comment Campaign sponsored by Greenpeace 4,685 11053 Mass Comment Campaign spons ored by Earthjustice 8,704 12055 Mass Comment Campaign sponsored by Earthjustice (Part 1 of 2) 3,112 12056 Mass Comment Campaign sponsored by Earthjustice (Part 2 of 2) 13059 Mass Comment Campaign sponsored by the League of Conservation Voters 593 13060 Mass Comment Campaign sponsoring organization unknown 78

13061 Mass Comment Campaign sponsored by Citizens for Pennsylvania’s Future (PennFuture) 172 13062 Mass Comment Campaign sponsoring organization unknown 202 13063 Mass Comment Campaign sponsored by Sierra Club 27,255 13421 Mass Comment Campaign sponsoring organization unknown 4,258 16530 Mass Comment Campaign sponsoring organization unknown 95 16531 Mass Comment Campaign sponsored by Environment Florida 43 16546 Mass Comment Campaign spons ored by Earthjustice 29 16547 Mass Comment Campaign sponsoring organization unknown 220

16553 Mass Comment Campaign sponsored by Natural Resources Defense Council (NRDC) 9,678 16554 Mass Comment Campaign sponsoring organization unknown 513 16562 Mass Comment Campaign sponsoring organization unknown 73 16565 Mass Comment Campaign sponsored by Phys icians for Social Responsibility 2,607 16566 Mass Comment Campaign sponsoring organization unknown 42 16567 Mass Comment Campaign sponsored by National Audubon Society 5,279 17007 Mass Mail Campaign sponsored by Alliance for Climate Protection 47,525 17030 Mass Mail campaign sponsored by First C ongregational Church of Sonoma 28 17058 Mass Comment campaign sponsored by Environmental Defense Fund (EDF) 18,425767 17059 Mass Comment campaign sponsored by Na tural Resources Council of Maine 123

17060 Mass Comment campaign sponsored by National Wildlife Federation Action Fund 9,106

17802 Mass comment Campaign sponsored by Kentucky Environmental Foundation 12 18190 Mass comment campaign sponsored by Sierra Club 9,440 18490 Mass Comment Campaign sponsored by Ohio Citizen Action 1,405 18491 Mass Comment Campaign sponsored by Fair Climate Project 52 18492 Mass Comment Campaign sponsored by Clean Air Council 49 18493 Mass Comment Campaign sponsoring organization unknown 39 18494 Mass Comment Campaign sponsored by Interfaith Power & Light 643 18495 Mass Comment Campaign sponsoring organization unknown 2,181 18496 Mass Comment Campaign sponsored by Restoring Eden 11,819

18546 Mass Comment Campaign sponsored by National Wildlife Federation (NWF) 433 18638 Mass Comment Campaign sponsoring organization unknown 58

18639 Mass Comment Campaign sponsored by Citizens Campaign for the Environment 33,165 18640 Mass Comment Campaign sponsoring organization unknown 67 18641 Mass Comment Campaign sponsoring organization unknown 29 18642 Mass Comment Campaign sponsoring organization unknown 105 18643 Mass Comment Campaign sponsoring organization unknown 2,611 18965 Mass Comment Campaign sponsored by CREDO Action 136,779 18979 Mass Comment Campaign sponsored by GASP (formerly Alabama First) 94 18986 Mass Comment Campaign sponsored by NC Conservation Network 904

18988 Mass Comment Campaign sponsored by One Million Calls For Clean Energy 4,481 19112 Mass Comment Campaign sponsored by Greenpeace 77,844 19113 Mass Comment Campaign sponsoring organization unknown 20

19125 Mass Comment Campaign sponsored by Re spiratory Health Association of Metropolitan Chicago 94 19150 Mass comment campaign spons ored by Earthjustice 37,286

19550 Mass Comment Campaign sponsored by Fall-line Alliance for a Clean Environment (FACE) 130 19573 Mass Comment Campaign sponsoring organization unknown 23

19615 Mass Comment Campaign sponsored by Gr eenFaith, Interfaith Partners in Action for the Earth 13,074 19632 Mass Comment Campaign sponsoring organization unknown 25 19643 Mass Comment Campaign sponsored by Moms Clean Air Force 95 19644 Mass Comment Campaign sponsoring organization unknown 2,959 19647 Mass Comment Campaign sponsoring organization unknown 32

19648 Mass Comment Campaign sponsored by Environmental Defense Fund (EDF) 269 Total: 664,695768769 In addition to the mass mailings identified by the Docket Office, 12,437 mass mail comments were also identified by RTI International. Not all of the comments can be linked to a specific organization.

Table 9A-2. American Lung Association

3328 5122 5212 5216 7582 7583 7586 7587 7588 7658 7659 7662
7663 7664 7665 7666 7667 7668 7669 7670 7671 7673 7674 7675
7747 7828 7859 8287 8434 8520 8521 8579 8958 8961 9022 9072
9112 9154 9159 9172 9376 9790 11314 11915 12384 12409 12411 12418
12425 12430 12431 12439 12467 12508 12521 12589 12630 12639 12675 12676
12715 12716 12720 12768 12801 13099 13539 14288 14303 14345 14347 14844
14901 14952 14965 14969 14972 14973 15020 15171 15209 15230 15280 15387
15457 15525 16054 16073 16214 16215 16217 16228 16241 17075 17076 17080
17081 17082 17086 17146 17147 18531 18559 18663 18676 18678 18679 18680
18688 18698 18914 18945 19203 19250 Total: 114

Table 9A-3. National Audubon Society

14180 14186 14191 14227 14228 14230 14233 14235 14239 14243 14258 14259
14265 14266 14269 14270 14273 14276 14277 14278 14285 14289 14290 14291
14292 14293 14294 14295 14296 14297 14298 14302 14304 14305 14306 14307
14308 14320 14321 14322 14323 14324 14326 14351 14352 14353 14355 14356
14357 14360 14361 14362 14363 14364 14383 14384 14385 14387 14389 14396
14401 14412 14415 14438 14439 14452 14453 14454 14455 14456 14457 14458
14459 14727 14767 14768 14778 14779 14791 14793 14805 14841 14843 14846
14853 14902 14903 14950 14951 14953 14962 14963 14964 14966 14970 14974
14975 15003 15006 15016 15017 15019 15042 15044 15050 15060 15165 15166
15167 15168 15194 15195 15196 15198 15211 15244 15252 15264 15265 15267
15268 15275 15277 15278 15279 15289 15290 15291 15292 15293 15294 15295
15296 15297 15298 15299 15324 15325 15326 15327 15333 15334 15340 15342
15343 15346 15386 15346 15389 15390 15391 15399 15400 15401 15405 15406
15407 15409 15419 15420 15421 15422 15423 15461 15494 15498 15532 15681
15683 15684 15891 15895 15913 16011 16049 16060 16064 16065 16066 16067
16068 16069 16072 16080 16081 16083 16084 16092 16100 16104 16117 16218
16282 16312 16528 16587 Total: 196

Table 9A-4. Care2Address

13791 13863 13864 13867 13869 13873 13874 13876 13880 13881 13882 13883
13888 13923 13983 17987 17988 17989 17990 17991 17992 17993 17994 17995
17996 17997 17998 18000 18001 18002 18003 18004 18005 18006 18007 18008
18010 18011 18012 18013 18050 18064 18069 18070 18071 18072 18073 18074
18075 18076 18077 18078 18079 18080 18081 18082 18083 18084 18085 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 fo r 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 5494 5495 5496 5497 5498 5499 5500 5501 5502 5503 5504 5505
5506 5507 5508 5509 5510 5511 5512 5513 5514 5515 5516 5519
5520 5521 5522 5523 5524 5525 5526 5527 5528 5529 5530 5531
5532 5533 5534 5535 5536 5537 5538 5539 5540 5541 5542 5543
5544 5545 5546 5547 5548 5549 5550 5551 5552 5553 5554 5555
5556 5557 5558 5561 5563 5564 5565 5566 5567 5568 5569 5570
5571 5572 5573 5574 5575 5577 5578 5579 5580 5581 5582 5583
5584 5585 5586 5587 5588 5589 5590 5591 5592 5593 5594 5595
5596 5597 5598 5599 5600 5601 5602 5603 5604 5605 5606 5607
5608 5609 5610 5611 5612 5613 5614 5615 5616 5617 5618 5619
5620 5621 5622 5623 5624 5625 5626 5627 5628 5629 5630 5631
5632 5633 5634 5635 5636 5637 5638 5639 5640 5641 5642 5643
5644 5645 5646 5647 5649 5650 5651 5652 5653 5654 5655 5656
5657 5658 5659 5660 5661 5662 5663 5664 5665 5666 5667 5668
5669 5670 5671 5672 5673 5674 5675 5676 5677 5678 5679 5680
5681 5682 5683 5684 5685 5686 5687 5688 5689 5690 5692 5693
5694 5695 5696 5697 5698 5699 5700 5714 5715 5716 5717 5718
5719 5720 5721 5722 5723 5724 5725 5726 5727 5728 5729 5730
5731 5732 5733 5734 5735 5736 5737 5738 5739 5740 5741 5742
5743 5744 5745 5746 5747 5748 5749 5754 5755 5756 5757 5758
5759 5760 5761 5762 5763 5764 5765 5766 5767 5768 5769 5770
5771 5772 5773 5774 5775 5776 5777 5778 5779 5780 5781 5782
5783 5784 5785 5786 5787 5788 5789 5790 5791 5792 5793 5794
5795 5796 5797 5798 5799 5800 5801 5802 5803 5804 5805 5806
5807 5808 5809 5810 5811 5812 5813 5816 5817 5818 5819 5821
5822 5823 5824 5825 5826 5827 5828 5829 5830 5831 5832 5833
5834 5835 5836 5837 5841 5842 5843 5844 5845 5846 5849 5850
5851 5853 5862 5863 5864 5865 5866 5867 5868 5869 5870 5871
5872 5873 5874 5875 5876 5877 5878 5879 5880 5881 5882 5883
5884 5885 5886 5885 5888 5889 5890 5891 5892 5893 5894 5895
5896 5897 5898 5899 5900 5901 5902 5903 5904 5905 5906 5907
5908 5909 5910 5912 5914 5915 5916 5917 5918 5919 5920 5921
5922 5923 5924 5925 5926 5927 5928 5929 5930 5931 5932 5933
5934 5935 5936 5937 5938 5939 5940 5941 5942 5943 5944 5945
5946 5947 5948 5949 5950 5951 5952 5953 5954 5955 5956 5957
5958 5959 5960 5961 5962 5963 5964 5965 5966 5967 5968 5969
5970 5971 5972 5973 5974 5975 5976 5977 5978 5979 5980 5981
5982 5983 5984 5985 5986 5987 5988 5989 5990 5991 5992 5993
5994 5995 5996 5997 5998 5999 6000 6001 6002 6003 6004 6005
6006 6007 6009 6010 6011 6012 6013 6014 6015 6016 6017 6018
6019 6020 6021 6022 6023 6024 6025 6026 6027 6028 6029 6030
6031 6032 6033 6034 6035 6036 6037 6038 6039 6040 6041 6042786 6043 6044 6045 6046 6047 6048 6049 6050 6051 6052 6053 6055
6056 6057 6058 6059 6060 6061 6062 6063 6064 6065 6066 6067
6068 6069 6070 6071 6072 6073 6074 6075 6076 6077 6078 6079
6080 6081 6082 6083 6084 6085 6086 6087 6088 6089 6090 6091
6092 6093 6094 6095 6096 6097 6098 6099 6100 6101 6102 6103
6104 6105 6106 6107 6108 6109 6110 6111 6641 6642 6643 6644
6645 6646 6647 6648 6649 6650 6651 6652 6653 6654 6655 6656
6657 6658 6659 6660 6661 6662 6663 7124 7125 7126 7127 7128
7130 7131 7132 7133 7134 7137 7138 7139 7140 7141 7142 7143
7144 7145 7146 7147 7148 7149 7150 7151 7152 7153 7154 7155
7156 7157 7158 7159 7160 7161 7162 7163 7164 7165 7166 7167
7168 7169 7170 7171 7172 7173 7174 7175 7176 7177 7178 7179
7180 7181 7182 7183 7184 7185 7186 7187 7188 7189 7190 7191
7192 7193 7194 7195 7196 7197 7345 7589 7590 7591 7592 7593
7594 7595 7596 7597 7598 7599 7600 7601 7602 7603 7604 7605
7606 7607 7608 7609 7610 7611 7612 7613 7614 7615 7616 7617
7618 7619 7620 7621 7622 7623 7624 7625 7626 7627 7628 7629
7630 7631 7656 7657 7676 7677 7678 7679 7680 7681 7682 7683
7684 7685 7686 7687 7688 7689 7690 7691 7692 7693 7694 7695
7696 7697 7698 7699 7700 7701 7702 7703 7704 7705 7706 7707
7708 7709 7710 7711 7712 7713 7714 7715 7716 7717 7718 7719
7720 7721 7722 7723 7724 7725 7726 7727 7728 7729 7730 7731
7732 7733 7734 7735 7736 7737 7738 7739 7740 7741 7742 7743
7744 7745 7746 7748 7749 7750 7751 7752 7753 7754 7755 7756
7757 7758 7759 7758 7761 7762 7763 7764 7765 7766 7767 7768
7769 7770 7771 7772 7773 7774 7775 7776 7777 7778 7779 7780
7781 7782 7783 7784 7785 7786 7787 7788 7789 7790 7791 7792
7793 7794 7795 7796 7797 7798 7799 7800 7801 7802 7803 7804
7805 7806 7807 7808 7809 7810 7811 7812 7813 7814 7815 7816
7817 7818 7819 7820 7821 7822 7823 7824 7825 7826 7827 7829
7830 7831 7832 7833 7834 7835 7836 7837 7838 7839 7840 7841
7842 7843 7844 7845 7846 7847 7848 7849 7850 7851 7852 7853
7854 7855 7856 7857 7858 7860 7861 7862 7863 7864 7865 7866
7867 7868 7869 7870 7871 7872 7873 7874 7875 7876 7877 7878
7879 7880 7881 7882 7883 7884 7885 7886 7887 7888 7889 7890
7891 7892 7893 7894 7895 7896 7897 7898 7899 7900 7901 7902
7903 7904 7905 7906 7907 7908 7909 7910 7911 7912 7913 7914
7915 7916 7917 7918 7919 7920 7921 7922 7923 7924 7925 7926
7927 7928 7929 7930 7931 7932 7933 7934 7935 7936 7937 7938
7939 7940 7941 7942 7943 7944 7945 7946 7947 7948 7949 7950
7951 7952 7953 7954 7955 7956 7957 7958 7959 7960 7961 7962
7963 7964 7965 7966 7967 7968 7969 7970 7971 7972 7973 7974787 7976 7977 7978 7979 7980 7981 7982 7983 7984 7985 7986 7988
7989 7990 7991 7992 7993 7994 7995 7996 7997 7998 7999 8000
8001 8002 8003 8004 8005 8006 8007 8008 8009 8010 8011 8012
8013 8014 8015 8016 8017 8018 8019 8020 8021 8022 8023 8024
8025 8026 8027 8028 8029 8030 8031 8032 8033 8034 8035 8036
8037 8038 8039 8040 8041 8042 8043 8044 8045 8046 8047 8048
8049 8050 8051 8052 8053 8054 8055 8056 8057 8058 8059 8060
8061 8062 8063 8064 8065 8066 8067 8068 8069 8070 8071 8072
8073 8074 8075 8076 8077 8078 8079 8080 8081 8082 8083 8084
8085 8086 8087 8088 8089 8090 8091 8092 8093 8094 8095 8096
8097 8098 8099 8100 8101 8102 8103 8104 8105 8106 8107 8108
8109 8110 8111 8112 8113 8114 8115 8116 8117 8118 8119 8120
8121 8122 8123 8124 8125 8126 8127 8128 8129 8130 8131 8132
8133 8134 8135 8136 8137 8138 8139 8140 8141 8142 8143 8144
8145 8146 8147 8148 8149 8150 8151 8152 8153 8154 8155 8156
8157 8158 8159 8160 8161 8162 8163 8164 8165 8166 8167 8168
8169 8170 8171 8172 8173 8174 8175 8176 8177 8178 8179 8180
8181 8182 8183 8184 8185 8186 8187 8188 8189 8190 8191 8192
8193 8194 8195 8196 8197 8198 8199 8200 8201 8202 8203 8204
8205 8206 8207 8206 8209 8210 8211 8212 8213 8214 8215 8216
8217 8218 8219 8220 8221 8222 8223 8224 8225 8226 8227 8228
8229 8230 8231 8232 8233 8234 8235 8236 8237 8238 8239 8240
8241 8242 8243 8244 8245 8246 8247 8248 8249 8250 8251 8252
8253 8254 8255 8258 8259 8260 8261 8262 8263 8264 8265 8266
8267 8268 8269 8270 8271 8272 8273 8274 8275 8276 8277 8278
8279 8280 8281 8282 8283 8284 8285 8286 8288 8289 8290 8291
8292 8293 8294 8295 8296 8297 8298 8299 8302 8303 8304 8305
8306 8307 8308 8309 8310 8311 8312 8313 8314 8315 8316 8317
8318 8319 8320 8321 8322 8323 8324 8325 8326 8327 8328 8329
8330 8331 8332 8333 8334 8335 8336 8337 8338 8339 8340 8341
8342 8343 8344 8345 8346 8347 8348 8349 8350 8351 8352 8353
8354 8355 8356 8357 8358 8359 8360 8361 8362 8363 8364 8365
8366 8367 8368 8369 8370 8371 8372 8373 8374 8375 8376 8377
8378 8379 8380 8381 8382 8383 8384 8385 8386 8387 8388 8389
8390 8391 8392 8393 8394 8395 8396 8397 8398 8399 8400 8401
8402 8403 8404 8405 8406 8407 8408 8409 8410 8411 8412 8413
8414 8415 8416 8417 8418 8419 8420 8421 8422 8423 8424 8425
8426 8427 8428 8429 8430 8431 8432 8433 8435 8436 8437 8438
8439 8440 8441 8442 8444 8445 8446 8447 8448 8449 8450 8451
8452 8453 8454 8455 8456 8457 8458 8459 8460 8461 8462 8463
8464 8465 8466 8467 8468 8469 8470 8471 8472 8473 8474 8475
8476 8477 8478 8479 8480 8481 8482 8483 8484 8485 8486 8487788 8488 8489 8490 8491 8492 8493 8494 8495 8496 8497 8498 8499
8500 8501 8502 8503 8504 8505 8506 8507 8508 8509 8510 8511
8512 8513 8514 8515 8516 8517 8518 8519 8522 8523 8524 8525
8526 8527 8528 8529 8530 8531 8532 8533 8534 8535 8536 8537
8538 8539 8540 8541 8542 8543 8544 8545 8546 8547 8548 8549
8550 8551 8552 8553 8554 8555 8556 8557 8558 8559 8560 8561
8562 8563 8564 8565 8566 8567 8568 8569 8570 8571 8572 8573
8574 8575 8576 8577 8578 8589 8590 8591 8592 8593 8594 8595
8596 8597 8598 8599 8600 8601 8602 8603 8604 8605 8606 8607
8608 8609 8610 8611 8612 8613 8614 8615 8616 8617 8618 8619
8620 8621 8622 8623 8624 8625 8626 8627 8628 8629 8630 8631
8632 8633 8634 8635 8636 8637 8638 8639 8640 8641 8642 8643
8644 8645 8646 8647 8648 8649 8650 8651 8652 8653 8654 8655
8656 8657 8658 8659 8660 8661 8662 8663 8664 8665 8666 8667
8668 8669 8670 8669 8672 8673 8674 8675 8676 8677 8678 8679
8680 8681 8682 8683 8685 8686 8687 8688 8689 8690 8691 8692
8693 8694 8695 8696 8697 8698 8699 8700 8701 8702 8703 8704
8705 8706 8707 8708 8709 8710 8711 8712 8713 8714 8715 8716
8717 8718 8719 8720 8721 8722 8723 8724 8725 8726 8727 8728
8729 8730 8731 8732 8733 8734 8735 8736 8737 8738 8739 8740
8741 8742 8743 8744 8745 8746 8747 8748 8749 8750 8751 8752
8753 8754 8755 8756 8757 8758 8759 8760 8761 8762 8763 8764
8765 8766 8767 8768 8769 8770 8771 8772 8773 8774 8775 8776
8777 8778 8779 8780 8781 8782 8783 8784 8785 8786 8787 8788
8789 8790 8791 8792 8793 8794 8795 8796 8797 8798 8799 8800
8801 8802 8803 8804 8805 8806 8807 8808 8809 8810 8811 8812
8813 8814 8815 8816 8817 8818 8819 8820 8821 8822 8823 8824
8825 8826 8827 8828 8829 8830 8831 8832 8833 8834 8835 8836
8837 8838 8839 8840 8841 8842 8843 8844 8845 8846 8847 8848
8849 8850 8851 8852 8853 8854 8855 8856 8857 8858 8859 8860
8861 8862 8863 8864 8865 8866 8867 8868 8869 8870 8871 8880
8881 8882 8883 8884 8885 8886 8887 8888 8889 8890 8891 8892
8893 8894 8895 8896 8897 8898 8899 8900 8901 8902 8903 8904
8905 8906 8907 8908 8909 8910 8911 8912 8913 8914 8915 8916
8917 8918 8919 8920 8921 8922 8923 8924 8925 8926 8927 8928
8929 8930 8931 8932 8933 8934 8935 8936 8937 8938 8939 8940
8941 8942 8943 8944 8945 8946 8947 8948 8949 8950 8951 8952
8953 8954 8955 8956 8957 8959 8960 8962 8963 8964 8965 8966
8967 8968 8969 8970 8971 8972 8973 8974 8975 8976 8977 8978
8979 8980 8981 8982 8983 8984 8985 8986 8987 8988 8989 8990
8991 8992 8993 8994 8995 8996 8997 8998 8999 9000 9001 9002
9003 9004 9005 9006 9007 9008 9009 9010 9011 9012 9013 9014789 9015 9016 9017 9018 9019 9020 9021 9023 9024 9025 9026 9027
9028 9029 9030 9031 9032 9033 9034 9035 9036 9037 9038 9039
9040 9041 9042 9043 9044 9045 9046 9047 9048 9049 9050 9051
9052 9053 9054 9055 9056 9057 9058 9059 9060 9061 9062 9063
9064 9065 9066 9067 9068 9069 9070 9071 9073 9074 9075 9076
9077 9078 9079 9080 9081 9082 9083 9084 9085 9086 9087 9088
9089 9090 9091 9092 9093 9094 9095 9096 9097 9098 9099 9100
9101 9103 9104 9105 9106 9107 9108 9109 9110 9111 9113 9114
9115 9116 9117 9119 9120 9121 9122 9123 9124 9125 9126 9127
9128 9129 9130 9129 9132 9133 9134 9135 9136 9137 9138 9139
9140 9141 9142 9143 9144 9145 9146 9147 9148 9149 9150 9151
9152 9153 9155 9156 9157 9160 9161 9162 9163 9164 9165 9166
9167 9168 9169 9170 9171 9173 9218 9219 9220 9286 9287 9288
9289 9290 9291 9292 9293 9294 9295 9296 9297 9345 9347 9348
9350 9351 9352 9353 9354 9355 9356 9357 9358 9359 9360 9361
9362 9363 9364 9365 9366 9367 9368 9369 9370 9371 9372 9373
9374 9375 9377 9378 9379 9380 9381 9383 9384 9385 9386 9387
9388 9389 9390 9391 9392 9393 9394 9395 9396 9397 9398 9399
9400 9401 9402 9403 9404 9405 9406 9407 9408 9409 9410 9411
9412 9413 9414 9415 9416 9417 9418 9419 9420 9421 9422 9423
9424 9425 9426 9427 9428 9429 9448 9466 9467 9468 9484 9497
9499 9507 9509 9512 9514 9523 9616 9728 9729 9731 9734 9735
9739 9740 9741 9745 9746 9747 9748 9750 9751 9752 9753 9771
9772 9773 9774 9775 9776 9777 9778 9779 9780 9781 9782 9783
9784 9785 9786 9787 9788 9789 9791 9792 9793 9794 9795 9796
9797 9798 9799 9800 9801 9802 9803 9804 9850 9851 9852 9853
9856 9857 9861 9865 9905 9906 9908 9910 9911 9912 9913 9914
9915 9916 9917 9918 9922 9923 9924 9925 9926 9927 9928 9929
9930 9935 9936 9937 9938 9945 9948 9949 9950 9952 9954 9955
9956 9957 9960 9961 10030 10031 10032 10033 10034 10035 10036 10037
10038 10039 10040 10042 10043 10044 10045 10046 10047 10048 10049 10050
10051 10052 10053 10054 10055 10056 10057 10058 10059 10060 10061 10062
10063 10064 10066 10067 10068 10069 10070 10071 10072 10073 10074 10075
10076 10077 10078 10079 10080 10081 10082 10083 10084 10085 10086 10087
10088 10089 10090 10091 10092 10093 10094 10095 10096 10097 10098 10101
10102 10103 10105 10107 10108 10111 10112 10113 10123 10124 10127 10129
10130 10131 10132 10133 10134 10135 10136 10137 10138 10139 10140 10141
10142 10143 10144 10145 10146 10147 10148 10149 10150 10151 10152 10153
10154 10155 10156 10157 10158 10159 10161 10162 10163 10164 10168 10171
10173 10174 10175 10176 10177 10178 10179 10180 10181 10183 10184 10185
10186 10187 10188 10189 10190 10191 10192 10193 10195 10196 10197 10198
10199 10202 10203 10204 10205 10206 10207 10208 10209 10210 10211 10212790 10216 10217 10218 10219 10220 10221 10222 10223 10224 10225 10226 10227
10228 10229 10230 10231 10232 10233 10234 10235 10236 10237 10238 10239
10240 10241 10242 10243 10244 10245 10246 10247 10248 10249 10250 10251
10252 10253 10254 10255 10256 10257 10258 10259 10260 10261 10262 10263
10264 10265 10266 10265 10268 10269 10270 10271 10272 10273 10274 10275
10276 10277 10278 10279 10280 10281 10282 10283 10284 10285 10286 10287
10288 10289 10290 10291 10292 10293 10294 10295 10296 10297 10298 10299
10300 10301 10302 10303 10304 10305 10306 10307 10308 10309 10310 10311
10312 10313 10314 10315 10316 10317 10318 10319 10320 10321 10322 10323
10324 10325 10326 10327 10328 10329 10330 10331 10332 10333 10334 10335
10336 10337 10338 10339 10340 10341 10342 10343 10344 10345 10346 10347
10348 10349 10350 10351 10352 10353 10354 10355 10356 10357 10358 10359
10360 10361 10362 10363 10364 10365 10366 10367 10368 10369 10370 10371
10372 10373 10374 10375 10376 10377 10378 10379 10380 10381 10382 10383
10384 10385 10386 10387 10388 10389 10390 10391 10392 10393 10394 10395
10396 10397 10398 10399 10400 10401 10402 10403 10404 10405 10406 10407
10408 10409 10410 10411 10412 10413 10414 10415 10416 10417 10418 10419
10420 10421 10422 10423 10424 10425 10426 10427 10428 10429 10430 10431
10432 10433 10434 10435 10436 10437 10438 10439 10440 10441 10442 10443
10444 10445 10446 10447 10448 10449 10450 10451 10452 10453 10454 10455
10456 10457 10458 10459 10460 10461 10462 10463 10464 10465 10466 10467
10468 10469 10470 10471 10472 10473 10474 10475 10476 10477 10478 10479
10480 10481 10482 10483 10484 10485 10486 10487 10488 10489 10490 10491
10492 10493 10494 10495 10496 10497 10498 10499 10500 10501 10502 10503
10504 10505 10506 10507 10508 10509 10510 10511 10512 10513 10514 10515
10516 10517 10518 10519 10520 10523 10524 10525 10526 10527 10528 10529
10530 10531 10532 10533 10534 10535 10536 10537 10538 10539 10540 10541
10542 10543 10544 10545 10546 10547 10548 10549 10550 10551 10552 10553
10554 10555 10556 10557 10558 10559 10560 10561 10562 10563 10564 10565
10566 10567 10568 10570 10571 10572 10573 10574 10575 10576 10577 10578
10579 10580 10581 10582 10583 10584 10585 10586 10587 10588 10589 10590
10591 10592 10593 10594 10595 10596 10597 10598 10599 10600 10601 10602
10603 10604 10605 10606 10607 10608 10609 10611 10612 10613 10614 10615
10616 10617 10618 10619 10620 10621 10622 10624 10625 10626 10627 10628
10629 10630 10631 10632 10633 10634 10635 10636 10638 10639 10640 10641
10642 10643 10644 10645 10647 10648 10649 10650 10652 10653 10654 10655
10656 10657 10658 10661 10662 10663 10664 10665 10666 10667 10668 10669
10670 10671 10672 10673 10674 10675 10676 10677 10678 10679 10680 10681
10682 10683 10684 10685 10686 10687 10688 10689 10690 10691 10692 10693
10694 10695 10696 10697 10698 10699 10700 10701 10702 10703 10704 10705
10706 10707 10708 10709 10710 10711 10712 10713 10714 10715 10716 10717
10718 10719 10720 10719 10722 10723 10724 10725 10726 10727 10728 10730791 10731 10733 10735 10737 10738 10739 10740 10741 10742 10743 10744 10745
10746 10747 10748 10749 10751 10752 10753 10754 10755 10756 10759 10760
10761 10763 10764 10765 10768 10769 10770 10771 10772 10773 10774 10775
10776 10777 10778 10779 10780 10781 10782 10783 10784 10785 10786 10787
10788 10789 10790 10791 10792 10793 10794 10795 10796 10797 10798 10799
10800 10801 10802 10803 10804 10805 10806 10807 10808 10809 10810 10812
10814 10815 10816 10817 10818 10819 10820 10823 10824 10825 10826 10829
10830 10831 10832 10833 10834 10835 10836 10837 10838 10839 10840 10841
10842 10843 10844 10845 10846 10863 10864 10865 10866 10867 10868 10914
11082 11083 11084 11085 11086 11087 11282 11283 11284 11289 11290 11291
11292 11293 11294 11295 11296 11297 11300 11301 11302 11303 11304 11305
11306 11307 11308 11309 11310 11311 11312 11313 11315 11316 11317 11318
11319 11320 11321 11322 11323 11324 11325 11326 11327 11328 11329 11330
11331 11332 11333 11334 11335 11336 11337 11338 11339 11340 11341 11342
11343 11344 11345 11346 11347 11348 11349 11350 11353 11354 11355 11356
11357 11358 11360 11361 11362 11363 11365 11367 11369 11372 11375 11376
11381 11385 11397 11398 11399 11400 11405 11406 11407 11408 11409 11412
11420 11428 11429 11430 11431 11432 11433 11434 11435 11436 11437 11438
11449 11450 11451 11452 11453 11454 11455 11456 11457 11458 11459 11460
11461 11462 11463 11464 11465 11466 11467 11468 11469 11470 11471 11472
11473 11474 11475 11476 11478 11479 11480 11481 11482 11483 11484 11485
11486 11487 11488 11489 11490 11491 11492 11493 11494 11495 11496 11497
11498 11499 11500 11501 11502 11503 11504 11505 11506 11507 11508 11509
11510 11511 11512 11513 11514 11515 11516 11517 11518 11519 11520 11521
11522 11523 11524 11525 11526 11527 11537 11538 11539 11540 11541 11542
11543 11544 11545 11548 11551 11553 11568 11575 11579 11587 11593 11594
11595 11604 11621 11625 11629 11631 11632 11637 11638 11646 11649 11650
11652 11657 11658 11662 11663 11664 11668 11696 11697 11698 11699 11700
11701 11704 11705 11713 11714 11715 11716 11717 11718 11719 11720 11721
11722 11723 11724 11726 11727 11729 11730 11731 11732 11733 11734 11735
11736 11737 11738 11739 11740 11741 11742 11743 11744 11745 11746 11747
11748 11749 11750 11751 11752 11753 11754 11755 11756 11758 11759 11760
11761 11762 11765 11766 11773 11774 11775 11776 11777 11778 11779 11780
11781 11786 11787 11788 11789 11796 11797 11798 11799 11800 11817 11818
11819 11820 11821 11822 11823 11824 11825 11826 11827 11828 11829 11830
11831 11833 11838 11839 11843 11845 11859 11861 11866 11875 11880 11895
11925 11926 11929 11926 11934 11936 11937 11938 11939 11950 11956 11957
11958 11959 11960 11961 11962 11964 11965 11966 11968 11995 12005 12006
12010 12015 12016 12017 12018 12019 12020 12021 12034 12044 12052 12057
12058 12063 12064 12069 12070 12071 12074 12075 12076 12081 12082 12088
12089 12092 12096 12097 12098 12123 12124 12125 12126 12127 12130 12145
12146 12147 12149 12150 12153 12154 12170 12172 12201 12202 12229 12233792 12239 12240 12242 12243 12244 12245 12246 12247 12248 12249 12250 12251
12263 12266 12279 12280 12282 12385 12386 12387 12388 12389 12390 12391
12392 12393 12394 12395 12396 12397 12398 12399 12400 12401 12403 12404
12407 12408 12410 12412 12413 12414 12415 12419 12420 12422 12423 12424
12426 12427 12428 12429 12432 12433 12434 12435 12436 12437 12444 12445
12446 12447 12451 12452 12453 12454 12455 12456 12458 12465 12469 12470
12471 12472 12473 12475 12476 12477 12478 12479 12480 12481 12482 12483
12484 12485 12486 12487 12488 12489 12490 12491 12492 12493 12494 12496
12497 12498 12499 12500 12501 12502 12514 12515 12516 12517 12522 12523
12524 12527 12528 12529 12530 12531 12538 12541 12542 12543 12544 12545
12549 12550 12552 12553 12554 12555 12557 12558 12559 12575 12576 12577
12578 12579 12580 12581 12582 12583 12585 12586 12587 12588 12590 12591
12592 12593 12594 12595 12596 12597 12598 12600 12601 12602 12603 12604
12605 12606 12607 12608 12610 12611 12612 12613 12614 12616 12623 12631
12632 12633 12634 12635 12636 12637 12638 12640 12641 12642 12643 12646
12647 12655 12656 12657 12658 12659 12660 12666 12667 12668 12669 12670
12671 12672 12680 12681 12688 12689 12690 12691 12692 12693 12694 12695
12696 12697 12698 12699 12700 12701 12702 12703 12713 12721 12726 12728
12729 12730 12731 12732 12733 12734 12735 12736 12737 12738 12739 12740
12741 12742 12743 12744 12745 12746 12747 12748 12749 12750 12751 12752
12753 12754 12771 12773 12774 12775 12776 12777 12778 12779 12781 12782
12783 12784 12785 12786 12787 12788 12789 12790 12792 12804 12805 12806
12808 12809 12810 12811 12813 12817 12818 12819 12820 12821 12822 12823
12824 12825 12826 12827 12829 12830 12831 12832 12833 12834 12835 12837
12838 12839 12840 12841 12842 12843 12844 12845 12846 12847 12848 12849
12850 12851 12852 12853 12854 12855 12856 12857 12858 12859 12860 12861
12862 12863 12864 12865 12866 12867 12868 12869 12870 12871 12872 12873
12874 12876 12877 12878 12879 12880 12882 12883 12884 12885 12893 12895
12897 12898 12899 12900 12902 12903 12904 12905 12906 12907 12908 12909
12910 12911 12912 12913 12914 12915 12916 12917 12918 12919 12920 12921
12922 12923 12924 12925 12926 12927 12928 12929 12930 12931 12932 12933
12934 12935 12936 12935 12938 12939 12940 12941 12942 12943 12944 12945
12946 12947 12972 12973 12974 12975 12978 12980 12981 12982 12983 12984
12985 12986 12990 12993 12997 12998 12999 13000 13001 13002 13003 13004
13009 13011 13012 13013 13014 13015 13016 13017 13018 13019 13020 13021
13022 13023 13024 13025 13026 13027 13028 13030 13031 13032 13033 13034
13035 13036 13037 13038 13039 13040 13041 13042 13043 13044 13045 13046
13047 13048 13049 13050 13051 13053 13054 13057 13058 13064 13065 13066
13067 13068 13069 13070 13071 13072 13073 13074 13075 13076 13077 13078
13079 13080 13081 13082 13083 13086 13087 13088 13094 13095 13096 13098
13102 13103 13104 13108 13111 13113 13114 13115 13116 13123 13124 13125
13129 13130 13135 13136 13142 13143 13144 13145 13146 13147 13155 13156793 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) letter s 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 le tters expressing general opposition to the electric generating units NESHAP. Co mmenter’s concerns include the rule ’s effect on electricity prices, system dependability, employment, and the effect on small businesses and the overall economy. Due to the high number of comments for this proposed ru le, 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-m ail DCNs are listed in Table 9B-1 of this sectio n with the count of comment letters and th e 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 a ny mass-mail campaign are listed in Table 9B-5 in this section.

Many organizations provided members with form le tters. Form letters containing substantive comments had a few representative letters excerpted and summarized for the Response to Comments document. The remaining letters are listed here.

Many commenters (17295, 17401, 17748, 17749, 17750, 17763, 17778, 17783, 17788, 17792, 17822, 17825, 17826, 17827, 17866, 17890, 17891, 17897, 17910, 17924, 18414, 18482, 18499, 18705, 18706, 18894, 18936, 18937, 18944, 19549, 19559, 19560, 19566) representing municipal utilities expressed concerns about the proposed rule. These commenters asked that the EPA evaluate the impact of the proposed rule under SBREFA, UMRA and EO 13563, EO 13132, EO 12866, and EO 13211. Comments are discussed in furthe r detail by commenter 18038.

Response to Comment 1: The EPA acknowledges the general conc erns 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 cons ideration of SBREFA, UMRA, EO 13563, EO 13132, EO 12866, and EO 13211 may also be found elsewhere inthis document.802 Section 9B Tables

Mass Mailings - General Opposition to the Proposed Rule

Table 9B-1. Mass mail comments identi fied by the U.S. Docket Office

DCN Docket Entry Count

19651 Mass Comment Campaign sponsoring organization unknown 142 19633 Mass Comment Campaign sponsoring organization unknown 885 19646 Mass Comment Campaign sponsoring organization unknown 20 19645 Mass Comment Campaign sponsoring organization unknown 945 19650 Mass Comment Campaign sponsoring organization unknown 1,788 19652 Mass Comment Campaign sponsoring organization unknown 747 Total: 4,527

In addition to the mass mailings identified by the U.S. Docket Office, 268 mass mail comments were also identified by RTI International.

Table 9B-2. American Electric Power

14487 14509 14511 14520 14610 14612 14613 14614 14616 14617 14618 14619
14620 14621 14624 14628 14630 14631 14634 14635 14636 14637 14638 14639
14640 14641 14642 14643 14644 14645 14646 14647 14649 14651 14652 14654
14656 14658 14659 14660 14662 14664 14666 14667 14668 14671 14679 14680
14681 14682 14683 14684 14685 14686 14687 14688 14689 14690 14691 14692
14693 14694 15190 15439 15560 15566 15567 15568 15569 15661 15662 15663
15664 15670 15768 15769 15770 15771 15772 15773 15779 15780 15781 15782
15783 15785 15793 15794 15795 15796 15797 15798 15799 15812 15825 15826
15827 15829 15850 15851 15868 15869 15870 15871 15872 15880 15882 15924
15925 15935 15948 15950 15958 16127 16130 16154 16159 16160 16161 16162
16208 16212 16221 16222 16223 16224 16234 16239 16285 16286 16287 16300
16314 16315 16316 16324 16349 16350 16351 16353 16354 16355 16357 16358
16376 16379 16381 16379 16436 16450 16461 16488 16489 16501 16517 16536
16537 16542 16597 16845 17108 17184 17300 17330 17331 17332 17333 17334
17335 17354 17365 17370 17445 17472 17486 17908 17947 17953 18186 18301
18357 18377 18558 18565 18571 18620 18621 18623 18631 18661 18662 18664
18682 18683 18686 18689 18690 18692 18693 18694 18699 18776 18780 18784
18841 18849 18874 18917 18925 18926 18927 18940 18955 18969 18971 19085
19295 19320 19625 Total: 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 - Incorporation by Reference

Comment: Many commenters requested that th e remarks of other commenters be incorporated into their own comments on the proposed rule. The table below lists the commenters who have been referenced, followed by the commenters who asked to incorp orate the referenced commenters’ remarks. Specifically, the first column in Table 10-1 is a list of commenters who were referred to by other commenters. The second column gives a short name for the commenters who were referenced. The third column provides a list of the commenters who re ferred 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 regul atory impact analysis supporting materials.

Table 10-1. Incorporation by Reference

Referenced Commenter DCN Referenced Commenter Short Name Referencing Commenters

17799 ACCCE 17790 17877 AECI 19094 17815 AECT 17904, 18785 19114 AEP 17715, 17757, 18907, 19041 17810 ANGA 17853 8443, 17868 APPA 17655, 17702, 17705, 17767, 18015, 18018, 18031, 18032, 18437, 18500, 18831, 19121, 19213 17754 ARIPPA 18427 17757 Buckeye 19041 17760 Class 85 17702, 17722, 17776, 17807, 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 GCLC 17813, 17904, 18785 17698 GPA 17710 19506 IDEM 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

aNextEra Energy Inc. (DCN 17870) incorporated by re ference comments from several contributors, but with the caveat, “except in instances when the comments of th ese industry groups may conflict with NextEra Energy’s position as set forth in the comments below.”
b Montana-Dakota Utilities Company (DCN 17805) in corporated by reference the majority of EEI’s comments, as identified in Montan a-Dakota Utilities Company’s letter.

c PowerSouth Energy Cooperative (DCN 17909) inco rporated by reference comments from NRECA on setting numerical standards.
dAmerican Public Power Associ ation (DCN 17868) incorporated by reference UARG’s comments in regard to data availability, data analys 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 Ge orgia 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 E nvironmental Policy Consultants9:50 Dr. Anne MellingerBirdsong 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 Georgi a Interfaith Power & Light 10:50 Robert D. Bullard Environm ental Justice Resource Center Clark Atlanta University 10:55 Dr. Yolanda Whyte Individual 11:00 Mike Kennedy Progress Energy 11:05 Byron T. Burrows Tampa Electric Company 11:10 Alison Amyx Georgia Interfaith Power & Light 11:15 Bob Donaghue Georgia Interfaith Power & Light 11:20 Clark Efaw Georgia Interfaith Power and Light 11:25 Dr. James Rust 11:30 Thomas Pearce Sierra Club 11:35 Robin Mann Sierra Club 11:40 Jaffer Khimani Clean Air Task Force 11:45 Mark MacLeod Environmental Defense Fund 11:50 John B. Hammond National Wildlife Federation 11:55 Jack Thirolf Business Council for Sustainable Energy 12:00 Dabney Dixon Individual 12:05 Lance Brown Partnership for Affordable Clean Energy (PACE) 12:10 Steve Earle UMWA Region 3 12:15 Virginia Galloway Americans for Prosperity 12:20 Kevin McGrath GA Trout Unlimited 12:25 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 Heywood Sierra Club 12:45 Roger Mills Individual 12:50 Sean Hutchins KY Environmental Foundation 2:10 Seandra Rawls Southern Alliance for Clean Energy

2:15 Eriqua Foreman Williams Southern Alliance for Clean Energy 2:20 Emily Enderlee Earthjustice 2:25 Danny Schweinhart Individual 2:30 Alexei Laushkin The Evangelical Environment Network 2:35 Rev. Richard Cizik Evange licals 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 E nvironment Georgia 2:55 Dave Muhly Sierra Club 3:00 Eddie Ehlert Individual 3:05 Lyndsay Moseley Sierra Club 3:10 Imran Battla The Prana Group 3:15 David Richardson 3:20 Ron Shipman Georgia Power Company 3:25 Seth Hutchins KY Environmental Foundation 3:30 Thomas Hutegger Individual 3:35 John Walsh Sierra Club 3:40 Robert Fletcher 3:45 Elizabeth Crowe Kentucky Environmental Foundation 3:50 Kathy Little Kentucky Environmental Foundation 3:55 Robert Ukeiley Citizen 4:00 Natalie Crone & Student
group Chelsea Carroll Matt Callo Shawn Hutchins Alex English Austin Delph Seth Hutchins Kentucky Environmental Foundation

4:05 Simon Montelongo Kentucky Environmental Foundation 4:10 Benita Dodd 4:15 Shelia Tyson Citizen-Birmingham, Al 4:20 Jessica Spruill Southern Energy Network

4:25 Joan Lindop Sierra Club GA 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 / Pe rkerson 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 J obs and the Environment (UJAE) Mark Woodall SierraClub Georgia Chapter 7:10 Tony C. Anderson The Lets Raise a Million Education Fund 7:15 Erin Glynn (presented video testimony narrated by Erin Savage) Sierra Club

7:20 John Noel Individual 7:25 Burt Lesnick American Thoracic Society 7:35 Brandon Sutton Sierra Club 7:40 Carly Queen Individual 7:45 Melissa Nummink 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 Illinoi s Interfaith Power and Light Campaign 9:20 Rev. Faith Bugel Environm ental Law and Policy Center 9:25 Brian Urbaszewski Respiratory HealthAssociation of Me tropolitan 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 E nvironmental Illinois 10:10 Steve Frenkel Union of Concerned Scientists 10:15 Jerry Mead-Lucero Pilsen Environm ental Rights and Reform Organization 10:20 William “Bill” Kempiners American Lung Association Advocacy Committee

10:25 Jennifer Johnson Monberg Individual

10:30 Lyman C. Welch Alliance for the Great Lakes 10:35 Erika Dornfeld Faith in Place 10:40 Michael T.W. Carey Ohio Coal Association 10:45 Matt Most Encana Natural Gas Inc. 10:50 Dr. Michael S. Hogue Meadvi lle 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 Me tropolitan Chicago 11:30 Jim Ginderske Neighbors for a Healthy Rogers Park 11:35 Michael Murray Individual 11:40 Eve Pytel Metropolitan Mayors Caucus Clean Air Counts Campaign 11:45 Terry Grace Educator – Retired 11:50 Cory Jones Sierra Club 11:55 Don Ferber Sierra Club 12:00 Rev. Homer Cobb NAACP 12:05 Kimberly Wasserman Little Village Environmental Justic e Organization /NETAC 12:10 Ian Viteri Little Village E nvironmental Justice Organization 12:15 Victoria Persky Individual 12:20 John Blair Valley Watch

12:25 Leigh Touchton NAACP 12:30 Dr. Howard Ehrman UIC/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 Envir onmental Law and Policy Center 2:55 Boise Jones Sierra Club/EJAM 3:00 Ade Oba Abdalla Energy Efficiency and Environmental Health Services - Task Force 3:05 Dennis Nelson NEIS 3:10 Jerry B. Cain Judson University 3:15 Rebecca Rossof Climate and Energy Program 3:20 Michelle Martinez Sierra Club 3:25 Ingrid Wendland (daughter of Juliee De La Terre) Individual

3:27 Juliee De La Terre Individual 3:30 Lance Green Individual 3:35 Patricia Rosenthal Sierra Club 3:40 Kelly Pierce Individual 3:45 Patricia A.S. Crowley Kala mazoo County Drain Commissioner 3:50 James McPike Individual 3:55 Vivian Hood Individual 4:00 Joan Arnold Individual 4:05 Dr. Sarah Lovinger Physicia ns 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 E nvironmental Health Sciences Center811 Time Name Affiliation 4:55 Amanda Kaley Individual 5:00 Susan Williams Sierra Club 5:05 David A. Creech ELCA World Hunger 5:10 Dr. Edward (Ted) Naureckas Individual

5:15 Sue Blaine Labadie Envir onmental Organization/Individual 5:20 Dana March Individual 5:25 Jason Duba Individual 5:30 Jennifer Jansen National Wildlife Federation 5:35 Jocelyn Travis NAACP 5:40 David L. DePrez Individual 5:45 Rose Joshua NAACP 5:50 Auriel Banister Little Villag e Environmental Justice Organization 6:45 Olivia Woollam University of Chicago Climate Action Network, and the Chicago Youth Climate Coalition 6:50 Caroline Wooten UChicago Climate Action Network, Chicago Youth Climate Coalition 6:55 Pamela Ortner Individual 7:00 Donna Hriljac Individual 7:05 Rev. Theresa Dear NAACP 7:10 Jim Schneider Individual 7:15 Dr. Sam Dorevitch University of Illinois 7:20 Susanne Brooks Environmental Defense Fund 7:25 Brian Perbix Sierra Club 7:30 Sherry Leonard Individual 7:35 Marianne Flanagan Individual 7:40 Jessica Brackett Individual 7:45 Paul Kim University of Chicago 7:50 Joyce Blumenshine Heart of Illinois Sierra Club 7:55 Dr. Maureen McCue Iowa Physic ians for Social Responsibility 8:00 Susan Lannin Individual 8:05 Tim Sutherlin Individual 8:10 Kristen Vyhnal Individual 8:15 Melissa Mullarkey 8:20 Alexandra Sipiora Individual 8:25 Kevin Carol Individual 8:30 Adam Burke Individual 8:35 Marybeth Gardam Women’s Intern ational League fo r Peace & Freedom 8:40 Richard Stucky Individual 8:45 Grace Pai University of Chicago 8:50 Dr. Robert A. Rosenstein Sierra Club, Uni on 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 He aring – Philadelphia – 24 May 2011

Time Name Affiliation 9:15 Rabbi Daniel Swartz Scranton Area Minist erium and PA Interfaith Power and Light 9:20 Deborah P. Brown The American Lung Assoc. 9:25 Charles McPhedran Citizens fo r 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 Phys icians for Social Responsibility 9:55 Stephen Harvey SierraClub; Pepper Hamilton LLP 10:00 Reverend Cheryl Pyrch Summit Presbyterian Church 10:05 Eileen O’Boyle Greenpeace USA 10:10 Jay Butera Individual 10:15 Rev. Mitchell Hescox Evange lical Environmental Network 10:20 Leslie G. Fields Sierra Club 10:25 Paul G. Billings American Lung Association 10:30 James W. Banford, Jr. International Br otherhood of Boilerm akers; Boilermakers Local Lodge No. 13 10:35 Dr. Poune Sabieri Sierra Club 10:40 Doug Keith Sierra Club 10:45 Joy Bergey The Center for the Celebration of Creation 10:50 Kevin M. Stewart American Lung Association of the Mid-Atlantic 10:55 Christine Guhl Sierra Club Statement from Anna Maria Caldera read by Christine Guhl Individual

11:00 Scott Segal Electric Reliab ility Coordinating Council/B&G 11:05 Corinne Wright Sisters of St. Francis of Philadelphia 11:10 Thomas Au Clean Air Bo ard of Central Pennsylvania 11:05 Ed Perry National Wildlife Federation 11:10 Don Robertson Isaac Walton League of America 11:15 Rev. Horace W. Strand Ches ter Environmental Partnership 11:20 William Kramer Sierra Club 11:25 Dr. Scott Manaker American Thoracic Society 11:30 Chris Salmi New Jersey Depart ment 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 Uni on of Concerned Scientists 12:20 Catherine Bowes National Wildlife Federation 12:25 Rabbi Kevin M. Kleinman Individual 12:30 Jamin Bogi Group Against Smog and Pollution 2:15 Nancy Parks SC/PA Chapter/Clean Air Committee 2:20 Jay Butera One Million Calls For Clean Energy 2:25 Katie Feeney Clean Air Council 2:30 Tyra Bryant-Stephens The Comm unity Asthma Prevention Program 2:35 Candance Cheatham Individual 2:40 Mark Schmerling Individual 2:45 Dr. Rima Synnestivedt Sierra Club 2:50 Robert Cooper Union of Concerned Scientists 2:55 Sarah Bucic Delaware City Environmental Coalition 3:00 Dr. Kristen Welker-Hood Physic ians for Social Responsibility3:05 Gretchen DahlkemperAlfonso 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 Evangeli cal Lutheran Church in America 3:30 Donna Henry Individual 3:35 Dr. Kevin Osterhoudt Ameri can Academy of Pediatrics 3:40 Theodore Carrington NAACP 3:45 Gina E. Wood Joint Center for Political and Economic Studies 3:50 John Hanger PA Dept of Environmental Protection Hanger Consulting 3:55 Teresa Mendez-Quigley Women’s Health and Environmental Network 4:00 Amy Roe Individual 4:05 Geneva Boyer Individual 4:10 Shreena Bindra Individual 3:55 Coralie A. Pryde Individual 4:00 Josh Nelson CREDO Action from Working Assets 4:20 Jeff A McNelly ARIPPA 4:25 Brenda Afzal HCWH, U.S. Climate Policy Coordinator 4:30 Ed Braun City of Philadelphia Department of Public Health, Air Management Services 4:35 Mary Anne Rushlau Sierra Club 4:40 Jenny Kordick Individual 4:45 Bruce Alexander Exelon Corporation 4:50 Kate Etherington Philadelphia P hysicians 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 Freyda Black Individual 6:45 Al Rizzo American Lung Association 6:50 Matthew Pale PennEnvironment 6:55 Joe Parrish American Lung Association of New Jersey 7:00 Kendall Mackey National Wildlife Federation 7:05 Adam H. Cutler Public Health and Environmental Justice Law Clinic 7:10 Rachel Men tin Individual 7:15 Lynn Jaeger Eastern MontCo Action 7:20 Captain Joel Fogel Wa terwatch International 7:25 Kate Zaidan Individual 7:30 Myriam Fallon Greenpeace 7:35 Christina Marie Glessner Individual 7:40 Rosa Michmya Individual 7:30 Dr. Gwen DuBois Chesapeake Phys icians for Social Responsibility 7:35 Dr. Cindy Parker Chesapeake Phys icians for Social Responsibility 7:40 Jeff Player Individual 7:45 Lisa Hastings Individual 7:50 Stephen Shapiro Chesapeake Phys icians 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 Individual12/08/11 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. MellingerBirdsong 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 Se minole Electric Cooperative, Inc EPA-HQ-OAR-2009-0234-10569-A1 Juan Ramirez Florida Electric Power Coordinating Group, Inc. (FCG) EPA-HQ-OAR-2009-0234-10750-A1 John M. McManus American Electric Power (AEP)

EPA-HQ-OAR-2009-0234-10821-A2 Michael J. Nasi Jackson Walker, LLP on behalf of Gulf Coast Lignite Coalition (GCLC) EPA-HQ-OAR-2009-0234-10822-A2 L. Mohorovic, PhD None

EPA-HQ-OAR-2009-0234-10942-A1 John D. Free Alabama Public Service Commission (APSC) EPA-HQ-OAR-2009-0234-10943-A1 James O. Vick Gulf Power Company EPA-HQ-OAR-2009-0234-10944-A1 Charles McPhedran Citizens for Pennsylvania’s Future (PennFuture) EPA-HQ-OAR-2009-0234-10987-A1 Rae Cronmiller, James J. Nipper National Rural Electric Cooperative Association (NRECA), American Public Power Association (APPA) EPA-HQ-OAR-2009-0234-11107-A1 Alan H. Lockwood None

EPA-HQ-OAR-2009-0234-11889 Douglas K. Stevens None

EPA-HQ-OAR-2009-0234-12050-A2 Thomas AuClean Air Board of Central Pennsylvania (CAB) EPA-HQ-OAR-2009-0234-12267-A1 S. W. Kuntz, PhD EPA-HQ-OAR-2009-0234-12380-A2 Anonymous public comment None12/08/11 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 Quic k Utah Geological Survey, Utah Department of Natural Resources EPA-HQ-OAR-2009-0234-12996-A2 Michael P. Halpin Division of Air Resource Management, Florida Department of Environmental Protection (DEP) EPA-HQ-OAR-2009-0234-13178-A1 Patrick O’Loughlin Buckeye Power, Inc.

EPA-HQ-OAR-2009-0234-13526-A1 Susana M. Hildebrand Texas Commision on Environmental Quality (TCEQ) EPA-HQ-OAR-2009-0234-13529-A1 Byron T. Burrows Tampa Electric Company (TECO)

EPA-HQ-OAR-2009-0234-13827-A1 Darrell DorseyKansas City Board of Public Utilities (BPU) EPA-HQ-OAR-2009-0234-14017-A1 David R. Tripp and Dennis Lane Stinson Morrison Hecker LLP on behalf of Westar Energy, Inc. EPA-HQ-OAR-2009-0234-14069-A1 Raymond L. Evans FirstEnergy Corp.

EPA-HQ-OAR-2009-0234-14070-A1 G. Vinson Hellwig Michigan Department of Environmental Quality (MDEQ) EPA-HQ-OAR-2009-0234-14070-A2 G. Vinson Hellwig Michigan Department of Environmental Quality (MDEQ) EPA-HQ-OAR-2009-0234-14115-A1 Dr. W. Soon None EPA-HQ-OAR-2009-0234-14368-A1 Niger Innis Congress of Racial Equality on behalf of Affordable Power Alliance (APA) EPA-HQ-OAR-2009-0234-15002-A1 Barbara Got tlieb Physicians for Social Responsibility (PSR) EPA-HQ-OAR-2009-0234-15160-A1 Dr. Lawrence Raymond Clean Air Carolina

EPA-HQ-OAR-2009-0234-15182-A2 James Zorn Great Lakes Indian Fish and Wildlife Commission (GLIFWC) EPA-HQ-OAR-2009-0234-15678-A2 William Skrabak Transportation and Environmental Services, Office of Environmental Quality, City of Alexandria, Virginia EPA-HQ-OAR-2009-0234-15884-A2 Joseph Otis Minott Clean Air Council

EPA-HQ-OAR-2009-0234-16121-A1 Cynthia Bearer, Board Chair Children’s Environmental Health Network (CEHN) EPA-HQ-OAR-2009-0234-16122-A1 Harold “Gus” Frank Forest County Potawatomi Community (FCPC)12/08/11 DRAFT

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 Am erican 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 Grah am 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. EstyConnecticut Department of Energy and Environmental Protection EPA-HQ-OAR-2009-0234-16549-A1 Lance Brown et al. Partnership for Affordable Clean Energy (PACE) EPA-HQ-OAR-2009-0234-16626-A1 Congressman John D. Dingell, et al. Congress of the United States

EPA-HQ-OAR-2009-0234-16627-A1 Illona A. Jeffcoat-Sacco North Dakota Public Service Commission EPA-HQ-OAR-2009-0234-16630-A1 Ellen Rendulich Citizens Against Ruining the Environment (CARE) EPA-HQ-OAR-2009-0234-16682-A1 Juliet Cohen Upper Chattahoochee Riverkeepers EPA-HQ-OAR-2009-0234-16705-A2 William H. Conrad City of Newberry, Florida

EPA-HQ-OAR-2009-0234-16738-A1 Leonard Levin Electric Power Research Institute (EPRI) EPA-HQ-OAR-2009-0234-16822-A1 Senator James A. Inhofe, et al. Congress of the United States

EPA-HQ-OAR-2009-0234-16824-A2 Chris Clark Georgia Chamber of Commerce EPA-HQ-OAR-2009-0234-16826-A1 Brian Sayl or American Lung Association EPA-HQ-OAR-2009-0234-16844-A1 John A. Arwa y Pennsylvania Fish and Boat Commission (PFBC) EPA-HQ-OAR-2009-0234-16849-A1 Rebecca Heffren Em pire District Electric Company EPA-HQ-OAR-2009-0234-16850-A2 Cindy B. M iller Florida Public Service Commission EPA-HQ-OAR-2009-0234-16856-A1 Tom Bloss Pritchard Electric EPA-HQ-OAR-2009-0234-16857-A1 Carolin e Choi Progress Energy EPA-HQ-OAR-2009-0234-16858-A1 R.D. Cross Gilmer, TX EPA-HQ-OAR-2009-0234-16859-A1 Leo M. Drozdof f Environmental Council of the States (ECOS) EPA-HQ-OAR-2009-0234-16861-A1 Thomas R. K uhn Edison Electric Institute (EEI) EPA-HQ-OAR-2009-0234-16872-A1 Tony Clark National Association of Regulatory Utility Commissioners12/08/11 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. Sega l 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. Jo ines 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 Bradle y Clean Energy Group’s Clean Air Policy Initiative EPA-HQ-OAR-2009-0234-17114-A1 Rosemary Elebash National Federation of Independent Business (NFIB) EPA-HQ-OAR-2009-0234-17123-A1 Andrew J. Such Michigan Manufacturers Association (MMA) EPA-HQ-OAR-2009-0234-17137-A1 Mike Arms Association of Tennessee Valley Governments (ATVG) EPA-HQ-OAR-2009-0234-17157-A1 Evelyn Fang Leadership Council Alaska, American Lung Association EPA-HQ-OAR-2009-0234-17174-A2 Myra C. Reece Bureau of Air Quality, South Carolina Department of Health and Environmental Control (DHEC) EPA-HQ-OAR-2009-0234-17191-A2 Terry Hogan Wabash Valley Power Association (WVPA) EPA-HQ-OAR-2009-0234-17197-A1 Paul Schulz Platte River Power Authority EPA-HQ-OAR-2009-0234-17254-A1 Public Hearing in Atlanta, GA on May 26, 2011 EPA-HQ-OAR-2009-0234-17265-A1 Michael P. Halpin Division of Air Resource Management, Florida Department of Environmental Protection (FDEP) EPA-HQ-OAR-2009-0234-17270 V. Watson None EPA-HQ-OAR-2009-0234-17278-A1 Donald H. Picard Southeast Volusia Audubon Society chapter of the National Audubon Society EPA-HQ-OAR-2009-0234-17279 Mark Mueller St. Petersburg chapter of the National Audubon Society EPA-HQ-OAR-2009-0234-17281-A2 Kenneth J. Schilling Washington Electric Cooperative, Inc.12/08/11 DRAFT

819 EPA-HQ-OAR-2009-0234-17283-A1 Carli Smith et al. Cooper Environmental Services, LLC (CES) EPA-HQ-OAR-2009-0234-17291 Anonymous public comment None

EPA-HQ-OAR-2009-0234-17294 L. McClain None EPA-HQ-OAR-2009-0234-17295-A2 L. J. Joey Durel, Jr., Lafayette Consolidated Government on behalf of Lafayette Utilities System EPA-HQ-OAR-2009-0234-17296-A2 Marshall D. Moore Chemtura Corporation

EPA-HQ-OAR-2009-0234-17297-A2 Orjiakor N. Isiogu, Monica Martinez, and Greg R. White Department of Licensing and Regulatory Affairs, Michigan Public Service Commission

EPA-HQ-OAR-2009-0234-17299-A2 George Ca rter Paulding Putnam Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17305-A2 Gerald Lauer Consolidated Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17306-A2 Glenn W. Miller Holmes-Wayne Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17316-A2 B. Machaver None EPA-HQ-OAR-2009-0234-17381 Jon Hinck Main e 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 Vél ez Taunton Municipal Lighting Plant (TMLP) EPA-HQ-OAR-2009-0234-17400-A1 Eugene F. Wallace and Paul H. Beckhusen Coldwater Board of Public Utilities, City of Coldwater, Michigan

EPA-HQ-OAR-2009-0234-17401-A1 Jay Vavricek and Timothy Luchsinger City of Grand Island, Nebraska

EPA-HQ-OAR-2009-0234-17402-A1 Basil G. Constantelos Edison Mission Energy, LLC

EPA-HQ-OAR-2009-0234-17403-A1 Anthony N. Jacobs International Brotherhood of Boilermakers, Iron Ship Builders, Blacksmiths, Forgers and Helpers and AFL-CIO (Boilermakers Union) EPA-HQ-OAR-2009-0234-17405-A1 Jennifer Lu st Brainerd Lakes Area Audubon Society EPA-HQ-OAR-2009-0234-17406-A1 Raymond Burns Rogers-Lowell Area Chamber of Commerce12/08/11 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 El ectric Power Research Institute (EPRI) EPA-HQ-OAR-2009-0234-17622-A1 David Foerter Institute of Clean Air Companies (ICAC) EPA-HQ-OAR-2009-0234-17623-A1 Brian H. Moeck Large Public Power Council (LPPC) EPA-HQ-OAR-2009-0234-17625-A1 Ronald Poltak New England Interstate Water Pollution Control Commission (NEIWPCC) EPA-HQ-OAR-2009-0234-17626-A1 Robert G. Hilton Power Technologies for Government Affairs, Alstom EPA-HQ-OAR-2009-0234-17627-A1 Raymond L. Evans FirstEnergy Corp. (FE)

EPA-HQ-OAR-2009-0234-17628-A1 Les Oakes Ki ng & Spalding LLP on behalf of Power4Georgians, LLC (P4G) EPA-HQ-OAR-2009-0234-17629-A1 John V. Corra Wyoming Department of Environmental Quality EPA-HQ-OAR-2009-0234-17637-A1 Ruthanne F. Calabrese Northeast Utilities System Company (NUSCO) EPA-HQ-OAR-2009-0234-17638-A1 James O. Vick Florida Electric Power Coordinating Group, Inc. (FCG) EPA-HQ-OAR-2009-0234-17639-A1 Terry E. Branstad, Governor State of Iowa

EPA-HQ-OAR-2009-0234-17640-A1 Paul A. Yost National Association of Manufacturers (NAM) EPA-HQ-OAR-2009-0234-17648-A2 Kathleen Barron Exelon Corporation (Part 1 of 3) EPA-HQ-OAR-2009-0234-17654-A1 David E. Meehan Sunbury Generation LP

EPA-HQ-OAR-2009-0234-17655-A1 David M. Fraley City Utilities of Springfield, Missouri (CU) EPA-HQ-OAR-2009-0234-17656-A1 Holly Props t Western Business Roundtable EPA-HQ-OAR-2009-0234-17657-A1 Joan Small Gilmer Area Chamber of Commerce EPA-HQ-OAR-2009-0234-17658-A1 Lynda Munkres, Morris County, TX12/08/11 DRAFT

821 Judge EPA-HQ-OAR-2009-0234-17659-A1 Kelly R. Ha ll 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 Mordhors t Black Hills Corporation (BH) EPA-HQ-OAR-2009-0234-17678-A1 Eric RedmanSummit 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. Bore ll 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 Sewe ll Henderson Area Chamber of Commerce EPA-HQ-OAR-2009-0234-17685-A1 Bobby Beane Kilgore Economic Development Corporation EPA-HQ-OAR-2009-0234-17686-A1 Alan Grantham and Connie Ware Marshall Chamber of Commerce

EPA-HQ-OAR-2009-0234-17689-A1 Rae E. Cronmiller The National Rural Electric Cooperative Association (NRECA) EPA-HQ-OAR-2009-0234-17690-A1 Roger Caiazza Environmental Energy Alliance of New York, LLC EPA-HQ-OAR-2009-0234-17691-A1 John S. L yons Commonwealth of Kentucky, Division for Air Quality EPA-HQ-OAR-2009-0234-17692-A1 Daniel L. Juneau Louisiana Association of Business and Industry (LABI) EPA-HQ-OAR-2009-0234-17693-A1 Stephen J. Metcalf and Susan Longview Economic Development Corporation12/08/11 DRAFT

822 Mazarakes-Gill EPA-HQ-OAR-2009-0234-17694-A1 Lynda Rausch er Mineola, Texas, Community Development Department EPA-HQ-OAR-2009-0234-17695-A1 Sue Henderson Henderson Economic Development Corporation EPA-HQ-OAR-2009-0234-17696-A2 Linda Whelan Dynegy, Inc. EPA-HQ-OAR-2009-0234-17697-A1 Edward J. B. Calvo Governor of Guam on behalf of Guam Power Authority (GPA) EPA-HQ-OAR-2009-0234-17698-A1 Joaquin C. Flores Guam Power Authority (GPA)

EPA-HQ-OAR-2009-0234-17699-A1 Alexander Jackson Fond du Lac Band of Lake Superior Chippewa EPA-HQ-OAR-2009-0234-17700-A1 R. E. Spradlin, III, Mayor Kilgore, TX

EPA-HQ-OAR-2009-0234-17701-A1 Robin J. Lunt National Association of Regulatory Utility Commissioners (NARUC) EPA-HQ-OAR-2009-0234-17702-A1 Robert E. Hunzinger Gainesville Regional Utilities (GRU) EPA-HQ-OAR-2009-0234-17703-A1 Ronald W. Gore Alabama Department of Environmental Management (ADEM) EPA-HQ-OAR-2009-0234-17704-A1 Angela Rodriguez City Public Service (CPS Energy)

EPA-HQ-OAR-2009-0234-17705-A1 Kevin Wan ttaja Salt River Project (SRP) EPA-HQ-OAR-2009-0234-17707-A1 Jack Pelfre y 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 Inni s 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. Jone s Ohio Valley Electric Corporation (OVEC)/Indiana Kentucky12/08/11 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 PPL Corporation EPA-HQ-OAR-2009-0234-17719-A1 Martha E. Rudolph Colorado Department of Public Health and Environment EPA-HQ-OAR-2009-0234-17720-A1 Angila M. Retherford Vectren Corporation

EPA-HQ-OAR-2009-0234-17721-A1 Winston & Strawn LLP on behalf of Chem-Mod LLC

EPA-HQ-OAR-2009-0234-17722-A1 Mary Jo Roth Great River Energy (GRE) EPA-HQ-OAR-2009-0234-17723-A1 David M. Fraley City Utilities of Springfield, Missouri (CU) EPA-HQ-OAR-2009-0234-17724-A1 John W. Dw yer Lignite Energy Council (LEC) EPA-HQ-OAR-2009-0234-17725-A1 Verne S hortell 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. Fu lle Oglethorpe Power Corporation EPA-HQ-OAR-2009-0234-17729-A1 Bruce Park er Electric Energy, Inc. (EEI) EPA-HQ-OAR-2009-0234-17730-A1 Barbara A. Walz Tri-State Generation & Transmission Association, Inc. EPA-HQ-OAR-2009-0234-17731-A1 Parthenia B. Evans and Dennis Lane Stinson Morrison Hecker LLP on behalf of the Kansas City Board of Public Utilities (BPU) EPA-HQ-OAR-2009-0234-17732-A1 Stephen B. Etsitty Navajo Nation Environmental Protection Agency EPA-HQ-OAR-2009-0234-17733-A1 Harold “Gus” Frank and James Crawford Forest County Potawatomi Community (FCPC)

EPA-HQ-OAR-2009-0234-17734-A1 Ed Williams Novinda Corporation EPA-HQ-OAR-2009-0234-17735-A1 Wayne E. Penrod Coalition of New Units

EPA-HQ-OAR-2009-0234-17736-A1 Ryan D. Elliott Shumaker, Loop & Kendrick, LLP on behlaf of Ohio Utility Group EPA-HQ-OAR-2009-0234-17737-A1 Arie Hoekstra Tucson Electric Power Company (TEP) EPA-HQ-OAR-2009-0234-17738-A1 Derek R. McDonald Baker Botts LLP on behalf of the IPA Coleto Creek LLC (IPA) EPA-HQ-OAR-2009-0234-17739-A1 Neal J. Cabr al McguireWoods LLP on behalf of CONSOL Energy, Inc.12/08/11 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 Lewis F itzgerald Water, Light & Bond Commission EPA-HQ-OAR-2009-0234-17750-A1 Charlie Denh am 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 Terr ill Oklahoma Department of Environmental Quality (ODEQ) EPA-HQ-OAR-2009-0234-17756-A1 Paul M. Li ng Kansas City Power & Light Company (KCP&L EPA-HQ-OAR-2009-0234-17757-A1 Patrick O’Loughlin Buckeye Power, Inc.

EPA-HQ-OAR-2009-0234-17758-A1 Thomas R. K uhn Edison Electric Institute (EEI) EPA-HQ-OAR-2009-0234-17760-A1 William M. Bumpers Baker Botts L.L.P., on behalf of Class of 1985 Regulatory Response Group EPA-HQ-OAR-2009-0234-17761-A1 Cathy S. Woollums Mid American Energy Holdings Company EPA-HQ-OAR-2009-0234-17763-A1 Camille Payne, Mayor Thomasville, GA

EPA-HQ-OAR-2009-0234-17765-A1 John T. Heard The Virginia Coal Association, Inc. (VCA) EPA-HQ-OAR-2009-0234-17766-A1 Dennis M. Grzezinski Midwest Environmental Advocates, Inc. (MEA) EPA-HQ-OAR-2009-0234-17767-A1 PJ Becker Cityof Springfield, Illinois - City Water Light & Power (CWLP) EPA-HQ-OAR-2009-0234-17768-A1 Michael A. Livermore et al. Institute for Policy Integrity, New York University School of Law EPA-HQ-OAR-2009-0234-17769-A1 Mike Roddy Seminole Electric Cooperative, Inc.12/08/11 DRAFT

825 EPA-HQ-OAR-2009-0234-17770-A1 Bruce W. Ramme We Energies

EPA-HQ-OAR-2009-0234-17771-A1 Dave Mart in New Mexico Environment Department (NMED) EPA-HQ-OAR-2009-0234-17772-A1 JoAnne Rau Dayton Power and Light Company (DP&L) EPA-HQ-OAR-2009-0234-17773-A1 Leonard Levin Electric Power Research Institute (EPRI) EPA-HQ-OAR-2009-0234-17774-A1 Jay Hudson Santee Cooper EPA-HQ-OAR-2009-0234-17775 None Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-17775-A1 Lee B. Zeugin et. al Hunton and Williams LLP on behalf of Utility Air Regulatory Group (UARG)

EPA-HQ-OAR-2009-0234-17776-A1 Patricia D. Horn Oklahoma Gas And Electric Company (OGandE) EPA-HQ-OAR-2009-0234-17777-A1 Hunton and Williams LLP on behalf of Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-17778-A1 Willie E. Burns, Mayor City of Washington, Georgia

EPA-HQ-OAR-2009-0234-17779-A1 Albert Doughty, Mayor Town of Benton, Louisiana

EPA-HQ-OAR-2009-0234-17780-A1 Mary Jo Graham Oakmoss Education EPA-HQ-OAR-2009-0234-17781-A1 Hunton and Williams LLP on behalf of Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-17782-A1 Rosemary Elebash National Federation of Independent Business (NFIB) EPA-HQ-OAR-2009-0234-17783-A1 Kenneth D. Roberts City of Barnesville, Georgia

EPA-HQ-OAR-2009-0234-17784-A1 Hunton and Williams LLP on behalf of Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-17785-A1 Hunton and Williams LLP on behalf of Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-17786-A1 Lauren Freeman Hunton & Williams LLP on behalf of Utility Air Regulatory Group EPA-HQ-OAR-2009-0234-17787-A1 Lauren Freeman Hunton & Williams LLP on behalf of Utility Air Regulatory Group EPA-HQ-OAR-2009-0234-17788-A1 Scott Getzschman and Derril Marshall Fremont Department of Utilities, Nebraska

EPA-HQ-OAR-2009-0234-17789-A2 Scott M. Lorey Adirondack Council EPA-HQ-OAR-2009-0234-17790-A2 William Rogers DTE Energy EPA-HQ-OAR-2009-0234-17791-A2 Robin J. Lunt National Association of Regulatory Utility Commissioners (NARUC)12/08/11 DRAFT

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 Kreb sbach 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 Br adley The Clean Energy Group EPA-HQ-OAR-2009-0234-17809-A1 Mike Roddy Seminole Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17810-A1 Regina Hoppe r 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. Eutiz i San Miguel Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17814-A1 James O. Vick Gulf Power Company12/08/11 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 Wayne E. Penrod Sunflower Electric Power Corporation EPA-HQ-OAR-2009-0234-17818-A2 Ronald A. Amirikian State of Delware, Department of Natural Resources & Environmental Control, Division of Air and Waste Management EPA-HQ-OAR-2009-0234-17819-A2 Keith Harley Environment Illinois, Chicago Legal Clinic, Inc. on behalf of Environmental Law and Policy Center (ELPC) EPA-HQ-OAR-2009-0234-17820-A1 Pamela F. Faggert Dominion

EPA-HQ-OAR-2009-0234-17820-A2 Pamela F. Faggert Dominion

EPA-HQ-OAR-2009-0234-17821-A1 John L. Stowell Duke Energy EPA-HQ-OAR-2009-0234-17822-A1 Richard Barr, Mayor Adel, GA

EPA-HQ-OAR-2009-0234-17823-A1 Woodrow Wilson, Jr. Parrish of Caddo

EPA-HQ-OAR-2009-0234-17824-A1 Peter B. St orey 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 Fr ed Hlava, Gordon, NE EPA-HQ-OAR-2009-0234-17830-A1 Dan Leise Ce dar-Knox Public Power District (CKPPD) EPA-HQ-OAR-2009-0234-17831-A1 Neal D. Suess Loup River Public Power District EPA-HQ-OAR-2009-0234-17833-A1 David P. Hackett and Jessica Mitchell Wicha, Baker & McKenzie LLP on behalf of Michael A. Gardner Gypsum Association

EPA-HQ-OAR-2009-0234-17834-A1 Jon Bruning State of Nebraska et al. EPA-HQ-OAR-2009-0234-17835-A1 David M. Fraley City Utilities of Springfield, Missouri (CU) EPA-HQ-OAR-2009-0234-17836 John T. Suttle s Southern Environmental Law Center (SELC) EPA-HQ-OAR-2009-0234-17836-A1 John T. Suttles, Jr., Southern Environmental Law Center (SELC) and Southeast12/08/11 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. Sha ffer 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. Mari n 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. Richar d 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. Mb iad Guernsey-Muskingum Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17850-A1 Je ff A. McNelly ARIPPA EPA-HQ-OAR-2009-0234-17851-A2 Melvin E. Keener Coalition for Responsible Waste Incineration (CRWI) EPA-HQ-OAR-2009-0234-17852-A2 Gregory C. Staple American Clean Skies Foundation (ACSF) EPA-HQ-OAR-2009-0234-17853-A2 Matt Most Encana Natural Gas, Inc. EPA-HQ-OAR-2009-0234-17854-A1 Kristina Cu rtis 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. Benedi ct West Virginia Department of Environmental Protection, Division of Air Quality EPA-HQ-OAR-2009-0234-17866-A1 Jackie L. Wilson, Mayor City of Douglas, Georgia12/08/11 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, LLC (NNEI) EPA-HQ-OAR-2009-0234-17872-A2 W. Lawrence Givens Umatilla County Board of County Commissioners, Oregon EPA-HQ-OAR-2009-0234-17873-A2 Frank P. Prager Xcel Energy, Inc. EPA-HQ-OAR-2009-0234-17875-A1 Susan Lyon Center for American Progress EPA-HQ-OAR-2009-0234-17876-A2 Deborah Fohr Levchak Basin Electric Power Cooperative (BEPC) EPA-HQ-OAR-2009-0234-17877-A1 Todd A. Tolbert Associated Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17877-A2 Todd A. Tolbert Associated Electric Cooperative, Inc. EPA-HQ-OAR-2009-0234-17878-A3 Ben Yamagata Coal Utilization Research Council (CURC) EPA-HQ-OAR-2009-0234-17879-A2 Thomas S. Howard Domtar

EPA-HQ-OAR-2009-0234-17880-A2 Adrienne Esposito Citizens Campaign for the Environment (CCE) EPA-HQ-OAR-2009-0234-17881-A2 Louis P. Pocalujka Consumers Energy

EPA-HQ-OAR-2009-0234-17882-A2 Shelley Viny ard 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. My ers 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 District12/08/11 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, Inc. EPA-HQ-OAR-2009-0234-17903-A2 Leland M. Searles Iowa Environmental Council (IEC) EPA-HQ-OAR-2009-0234-17904-A3 Leslie Garrett Allen Balch & Bingham LLP on behalf of Luminant EPA-HQ-OAR-2009-0234-17909-A1 Keith M. Stephens PowerSouth Energy Cooperative

EPA-HQ-OAR-2009-0234-17910-A1 Robert T. Hunnicutt, Sr. Fort Valley Utility Commission, Fort Valley, CA EPA-HQ-OAR-2009-0234-17911-A1 Floyd Gilzow Mi ssouri Joint Municipal Electric Utility Commission (MJMEUC) EPA-HQ-OAR-2009-0234-17912-A1 Les Oakes and Cynthia Stroman King & Spalding LLP on behalf of IPP Coalition EPA-HQ-OAR-2009-0234-17913-A1 Russ Baker Omaha Public Power District (OPPD) EPA-HQ-OAR-2009-0234-17914-A1 R. L. Killion Babcock & Wilcox Power Generation Group, Inc. (B&W) EPA-HQ-OAR-2009-0234-17915-A1 Alice Edwards Division of Air Quality, Alaska Department of Environmental Conservation (ADEC) EPA-HQ-OAR-2009-0234-17916-A1 John Wilkinson Province of Ontario Ministry of the Environment, Canada EPA-HQ-OAR-2009-0234-17917-A1 Matthew H. Mead, Governor State of Wyoming

EPA-HQ-OAR-2009-0234-17918-A1 Dustin McDani el Arkansas Attorney General’s Office EPA-HQ-OAR-2009-0234-17919-A1 Scott H. Sega l Electric Reliability Coordinating Council (ERCC) EPA-HQ-OAR-2009-0234-17920-A1 Joseph Ha ntz Entergy Services, Inc. EPA-HQ-OAR-2009-0234-17921-A1 Indra Fran k Improving Kids’ Environment EPA-HQ-OAR-2009-0234-17922-A1 Ross Gould E nvironmental Advocates of New York EPA-HQ-OAR-2009-0234-17923-A1 Craig Bressan Prairie State Ge nerating Company, LLC (PSGC) EPA-HQ-OAR-2009-0234-17924-A1 James C. Wel sh Kissimmee Utility Authority (KUA) EPA-HQ-OAR-2009-0234-17925-A2 Bill Matthews Cleco Power LLC12/08/11 DRAFT

831 EPA-HQ-OAR-2009-0234-17926-A2 Derf J ohnson Montana Environmental Information Center (MEIC) EPA-HQ-OAR-2009-0234-17927-A2 Grant Rodw ay Bison Engineering, Inc. EPA-HQ-OAR-2009-0234-17928-A2 Paul J. Allen Constellation Energy EPA-HQ-OAR-2009-0234-17929-A2 James Pew Earthjustice EPA-HQ-OAR-2009-0234-17930-A2 Michael J. Nasi Jackson Walker L.L.P. on behalf of Gulf Coast Lignite Coalition (GCLC) EPA-HQ-OAR-2009-0234-17931-A2 William D. Bissett Kentucky Coal Association (KCA)

EPA-HQ-OAR-2009-0234-17973-A1 John A. Paul Regional Air Pollution Control Agency (RAPCA) of Dayton, Ohio EPA-HQ-OAR-2009-0234-17974-A1 James O. Vick Florida Electric Power Coordinating Group, Inc. (FCG) EPA-HQ-OAR-2009-0234-17975-A1 Eric Schaeffe r 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. F ox 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 Oliv er 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 E nvironmental 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. Sv enson PSEG Services Corporation EPA-HQ-OAR-2009-0234-18026-A2 Kevin Schmidt Ohio Manufacturers’ Association (OMA) EPA-HQ-OAR-2009-0234-18027-A2 Vickie Patt on Environmental Defense Fund (EDF) EPA-HQ-OAR-2009-0234-18028 J. Butera Environmental Defense Fund (EDF)12/08/11 DRAFT

832 EPA-HQ-OAR-2009-0234-18029-A2 Thomas M. Gibbons Jersey City Environmental Commission EPA-HQ-OAR-2009-0234-18030-A2 Bill Schuette State of Michigan Attorney General Office EPA-HQ-OAR-2009-0234-18031-A2 Michael G. Cashin Minnesota Power (ALLETE)

EPA-HQ-OAR-2009-0234-18032-A2 Jim Weeks Michigan Municipal Electric Association (MMEA) EPA-HQ-OAR-2009-0234-18033-A2 Thomas C. Perry National Mining Association (NMA) EPA-HQ-OAR-2009-0234-18034-A2 Mark R. Vickery Texas Commission on Environmental Quality (TCEQ) EPA-HQ-OAR-2009-0234-18034-A3 Mark R. Vickery Texas Commission on Environmental Quality (TCEQ) EPA-HQ-OAR-2009-0234-18035-A2 Lauren Freeman, et al. Hunton & Williams LLP Utility Air Regulatory Group (UARG)

EPA-HQ-OAR-2009-0234-18036-A2 Aaron Flynn, Hunton & Williams LLP Utility Air Regulatory Group (UARG)

EPA-HQ-OAR-2009-0234-18037-A2 Douglas L. Biden Electric Power Generation Association (EPGA) EPA-HQ-OAR-2009-0234-18038-A2 Justin M. Nickels City of Manitowoc Public Utilities, Wisconsin EPA-HQ-OAR-2009-0234-18039-A2 Kenneth L. Kimmell Massachusetts Department of Environmental Protection (MassDEP) EPA-HQ-OAR-2009-0234-18043-A2 Allison D. Beals Adirondack Mountain Club (ADK) EPA-HQ-OAR-2009-0234-18051-A2 Greg Sch aefer Arch Coal, Inc. (ACI) EPA-HQ-OAR-2009-0234-18248-A2 Joseph Mendelson III National Wildlife Federation (NWF) EPA-HQ-OAR-2009-0234-18414-A1 Larry L. Guest, Mayor City of Elberton, Georgia

EPA-HQ-OAR-2009-0234-18415-A1 W. Kurt Foreman North Louisiana Economic Partnership (NLEP) EPA-HQ-OAR-2009-0234-18416-A1 Greg Hines, Mayor City of Rogers, Arkansas

EPA-HQ-OAR-2009-0234-18417-A1 Patsy Meck Panola County Economic Development Corporation EPA-HQ-OAR-2009-0234-18418-A1 Doug Sprouse, Mayor City of Springdale, Arkansas

EPA-HQ-OAR-2009-0234-18419-A1 Jennifer G. Trammell Greater Shelby County Chamber of Commerce EPA-HQ-OAR-2009-0234-18420-A1 Perry Webb Springdale Chamber of Commerce EPA-HQ-OAR-2009-0234-18421-A2 Susanne Br ooks Environmental Defense Fund12/08/11 DRAFT

833 (EDF) EPA-HQ-OAR-2009-0234-18422-A1 Ted Hampton Ut ah Associated Municipal Power Systems (UAMPS) EPA-HQ-OAR-2009-0234-18422-A2 Ted Hampton Ut ah 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 No land Indiana Coal Council, Inc. EPA-HQ-OAR-2009-0234-18425-A2 Erika Padge tt 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 Ke lly Waste Management (WM) EPA-HQ-OAR-2009-0234-18428-A2 Carolin e 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 DorganAlabama Rivers Alliance EPA-HQ-OAR-2009-0234-18437-A1 Patrick L. Pope Nebraska Public Power District EPA-HQ-OAR-2009-0234-18438-A2 Vickie Patt on Environmental Defense Fund (EDF) EPA-HQ-OAR-2009-0234-18439-A2 Lisa Jacobs on Business Council for Sustainable Energy (BCSE) EPA-HQ-OAR-2009-0234-18440-A2 Dustin McCani el Arkansas Attorney General’s Office EPA-HQ-OAR-2009-0234-18441-A2 Craig Glaze r 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 Re illy Hoosier Energy Rural Electric12/08/11 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 Ho rne 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 Schaedlic h Tekran Instruments Corporation EPA-HQ-OAR-2009-0234-18450-A2 Donald Neal Calpine Corporation EPA-HQ-OAR-2009-0234-18477-A3 Ronald R. C ox Hawaiian Electric Company, Inc. EPA-HQ-OAR-2009-0234-18478-A1 Lois Capps, etal. Congress of the United States EPA-HQ-OAR-2009-0234-18480-A1 Neal F. Nied feldt City of Beatrice, Nebraska EPA-HQ-OAR-2009-0234-18481-A1 William I. McLarty, Mayor City of South Sioux City, Nebraska EPA-HQ-OAR-2009-0234-18482-A1 Ann H. Campbell, Mayor Mayor’s Office, City of Ames, Iowa

EPA-HQ-OAR-2009-0234-18483-A2 Larry G. Carlson Tenaska, Inc. EPA-HQ-OAR-2009-0234-18484-A2 Steven C. Bore ll Alaska Miners Association (AMA) EPA-HQ-OAR-2009-0234-18486-A2 Mark Maslyn Am erican 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 Loom is Wyoming Mining Association (WMA) EPA-HQ-OAR-2009-0234-18497-A2 Jolene M. Thompson American Municipal Power, Inc. (AMP) EPA-HQ-OAR-2009-0234-18498-A2 Jerry Purvis East Kentucky Power Cooperative, Inc. (EKPC) EPA-HQ-OAR-2009-0234-18499-A2 Sal LoBianco Muscatine Power and Water EPA-HQ-OAR-2009-0234-18500-A2 Climate Policy Group (CPG) Climate Policy Group (CPG)

EPA-HQ-OAR-2009-0234-18501-A2 Tyler Edga r 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. Nels on 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 None12/08/11 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 McGrat h American Lung Association in Idaho EPA-HQ-OAR-2009-0234-18716-A2 Taylor A. Davis III, Patty Unfred and Matthew Walker American Lung Association in Oregon

EPA-HQ-OAR-2009-0234-18721-A2 Jon Breiner, et al. American Lung Association in Washington EPA-HQ-OAR-2009-0234-18749-A2 Mike Moody American Lung Association in Kentucky EPA-HQ-OAR-2009-0234-18750-A2 Harry Perlstadt American Lung Association in Michigan EPA-HQ-OAR-2009-0234-18751-A2 William Lawson and Jesse Neeley American Lung Association in Tennessee EPA-HQ-OAR-2009-0234-18759-A2 Rick MacCornack Washington Asthma Initiative (WAI) EPA-HQ-OAR-2009-0234-18785-A2 Eddy Young Optim Energy LP, Twin Oaks EPA-HQ-OAR-2009-0234-18820-A1 M. Stiefe rmann 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, Ma yor City of Blakely, Georgia EPA-HQ-OAR-2009-0234-18897-A2 Da niel Sutton American Lung Association in Ohio (ALAO) EPA-HQ-OAR-2009-0234-18898-A2 Linn Billings ley American Lung Association, Nevada EPA-HQ-OAR-2009-0234-18899-A2 Marlis HadleyAmerican Lung Association, New Mexico EPA-HQ-OAR-2009-0234-18900-A2 Caroline Moassessi American Lung Association, Nevada12/08/11 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 Hawk s 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 Howa rd 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 Tr aynor Northampton Generating Company, L.P EPA-HQ-OAR-2009-0234-18964-A2 CONSOL Energy Inc. CONSOL Energy Inc.

EPA-HQ-OAR-2009-0234-19032-A1 James M. Andrew Arizona Electric Power Cooperative, Inc. (AEPCO) EPA-HQ-OAR-2009-0234-19033-A1 Samuel H. Bruntz Alcoa Power Generating, Inc. (APGI) EPA-HQ-OAR-2009-0234-19040-A1 D. S. McKeown None EPA-HQ-OAR-2009-0234-19041-A1 Steven K. Nelson The Frontier Power Company

EPA-HQ-OAR-2009-0234-19042-A2 James Parkhurst EOP Foundation EPA-HQ-OAR-2009-0234-19094-A1 Michael C. Stiefermann Central Electric Power Cooperative (CEPC) EPA-HQ-OAR-2009-0234-19101-A1 James J. Eg ge 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 O liger Indianapolis Power & Light Company (IPL) EPA-HQ-OAR-2009-0234-19121-A1 Jon A. Finl inson Intermountain Power Service Corporation (IPSC) EPA-HQ-OAR-2009-0234-19122-A1 Mark J. Sedlacek Los Angeles Department of Water12/08/11 DRAFT

837 and Power (LADWP) EPA-HQ-OAR-2009-0234-19123-A1 Markus I. Brya nt 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. Cofi eld 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 Cr oce Virginia Manufacturers Association (VMA) EPA-HQ-OAR-2009-0234-19212-A2 James D. Atterholt Indiana Utility Regulatory Commission (IURC) et al. EPA-HQ-OAR-2009-0234-19213-A1 J. Michael Houston, Mayor City of Springfield, Illinois

EPA-HQ-OAR-2009-0234-19214-A1 Willie R. Taylor, Director United States Department of the Interior EPA-HQ-OAR-2009-0234-19225-A1 Mike G odwin Orange Audubon Society EPA-HQ-OAR-2009-0234-19296-A1 Richard H. Bremer Greater Shreveport Chamber of Commerce EPA-HQ-OAR-2009-0234-19506-A1 Thomas W. Easterly Indiana Department of Environmental Management EPA-HQ-OAR-2009-0234-19540 Ann Brewster Weeks Clean Air Task Force, et al.

EPA-HQ-OAR-2009-0234-19549-A1 David Theiss, Mayor City of Ellaville, Georgia

EPA-HQ-OAR-2009-0234-19559-A1 C. Neil Ma yer 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 Timm ons National Association of12/08/11 DRAFT

838 Manufacturers (NAM) EPA-HQ-OAR-2009-0234-19581-A1 Kent Greenwalt, Mayor City of Terrytown

EPA-HQ-OAR-2009-0234-19595 N.A. Bis hop City of Terrytown EPA-HQ-OAR-2009-0234-19601-A1 J. M. Gibney, Jr. Wahoo Public Utility EPA-HQ-OAR-2009-0234-19603-A1 Steve Rent frow Crisp County Power Commission EPA-HQ-OAR-2009-0234-19622-A2 Adriana Oller Nickel Producers Environmental Reseach Association (NiPERA, Inc) EPA-HQ-OAR-2009-0234-19653-A1 Richard Marshall Spectrum Systems Inc. EPA-HQ-OAR-2009-0234-19654 Rick Wajda Indiana Builders Association (IBA) EPA-HQ-OAR-2009-0234-19671-A2 Lee A. Casey, Counsel, Baker & Hostetler LLP on behalf of Institute for Liberty et al. Institute for Liberty et al.

EPA-HQ-OAR-2009-0234-19671-A3 Lee A. Casey, Counsel, Baker & Hostetler LLP on behalf of Institute for Liberty et al. Institute for Liberty et al.

EPA-HQ-OAR-2009-0234-19677-A1 Michael Ralston Iowa Association of Business and Industry (ABI) EPA-HQ-OAR-2009-0234-19678-A2 Barbara A. Walz Tri-State Generation and Transmission Association, Inc. EPA-HQ-OAR-2009-0234-19679 John Artes Maryland Department of the Environment

EPA-HQ-OAR-2009-0234-19741 A. Gwen Ecklund West Associates

EPA-HQ-OAR-2009-0234-19742 Andrew J. Such Michigan Manufacturer’s Association