NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS FROM COALAND OIL-FIRED ELECTRIC UTILITY STEAM GENERATING UNITS – 

RECONSIDERATION; 

SUMMARY OF PUBLIC COMMENTS AND RESPONSES 

U.S. Environmental Protection Agency 

Office of Air Quality Planning and Standards 

Sector Policies and Programs Division 

Research Triangle Park, North Carolina 27711 

March 2013 
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THIS PAGE INTENTIONALLY LEFT BLANK 

 
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Table of Contents

1.0 LEGAL ................................................................................................................................................. 8

1.1 New Source Trigger Date: May 3, 2011 ........................................................................................... 8

1.2 Comments on issues which were not reconsidered in this notice ..................................................... 8

1.3 Other legal ....................................................................................................................................... 14

2.0 NEW SOURCE EMISSION LIMITS ............................................................................................. 17

2.1 New coal-fired EGU ....................................................................................................................... 17

2.1.1 Filterable PM (9.0E-02 lb/MWh) ............................................................................................ 17

2.1.2 Hydrogen Chloride (1.0E-02 lb/MWh).................................................................................... 24

2.1.3 Sulfur dioxide (1.0 lb/MWh) ................................................................................................... 25

2.1.4 Lead (3.0E-02 lb/GWh) ........................................................................................................... 32

2.1.5 Selenium (5.0E-02 lb/GWh) .................................................................................................... 33

2.2 New coal-fired EGU, not low rank virgin coal ............................................................................... 34

2.2.1 Mercury (3.0E-03 lb/GWh) ..................................................................................................... 35

2.3.1 Mercury (possible revision) ..................................................................................................... 53

2.4 IGCC EGU ...................................................................................................................................... 55

2.4.1 Sulfur dioxide (4.0E-01 lb/MWh) ............................................................................................ 56

2.5 Solid oil-derived fuel-fired EGU .................................................................................................... 57

2.5.1 Filterable PM (3.0E-02 lb/MWh) ............................................................................................ 58

2.5.2 Sulfur dioxide (1.0 lb/MWh) ................................................................................................... 59

2.6 Liquid oil-fired EGU – continental ................................................................................................. 59

2.6.1 Filterable PM (4.0E-01 lb/MWh) ............................................................................................ 59

2.7 Other ............................................................................................................................................... 60

3.0 BEYOND-THE-FLOOR (BTF) ANALYSIS..................................................................................... 73

3.1 New coal-fired EGU ....................................................................................................................... 74

3.1.1 Filterable PM ........................................................................................................................... 74

3.1.2 Hydrogen chloride ................................................................................................................... 75

3.2 Other beyond-the-floor ................................................................................................................... 76

4.0 FILTERABLE PM MONITORING ................................................................................................... 80

4.1 Quarterly stack testing .................................................................................................................... 80

4.2 PM CEMS ....................................................................................................................................... 82

4.3 PM CPMS ....................................................................................................................................... 86

4.3.1 First Approach for establishing the operating limit for PM CPMS – Requiring use of the 

highest parameter value obtained during any run of an individual emissions test as the operating 
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limit, provided that the result of that individual emissions test met the emission limit. .................. 90

4.3.2 Second Approach for establishing the operating limit for PM CPMS – Requiring use of the 

average parameter value obtained from all runs of an individual emissions test as the operating 

limit, provided that the result of the individual emissions test met the emissions limit. .................. 90

4.3.3 Third Approach for establishing the operating limit for PM CPMS – Requiring use of the 

higher of a parameter scaled from all values obtained during an individual emissions test to 75 

percent of the emissions limit or the average parameter value obtained from all runs of an 

individual emissions test as the operating limit, provided that the result of the individual emissions 

test met the emissions limit. .............................................................................................................. 91

4.3.4 Emissions Testing After Each Exceedance .............................................................................. 94

4.3.5 Exceedances Leading to Violation ........................................................................................... 94

5.0 TECHNICAL CORRECTIONS AND CLARIFICATIONS ............................................................. 98

5.1 Definitions (existing) ...................................................................................................................... 98

5.2 Definitions (new) ............................................................................................................................ 99

5.3 Rule language.................................................................................................................................. 99

5.4 Other technical corrections and clarifications ............................................................................... 100

6.0 IMPACTS AND COST ANALYSIS ................................................................................................ 103

6.1 Air Impacts.................................................................................................................................... 103

6.2 Energy Impacts ............................................................................................................................. 104

6.3 Economic Impacts/Employment Impacts ..................................................................................... 104

6.4 Health Co-Benefits ........................................................................................................................ 105

6.5 Other impacts and cost analysis .................................................................................................... 106

7.0 GENERAL COMMENTS ................................................................................................................ 108

8.0 OTHER OUT OF SCOPE ................................................................................................................ 109

9.0 INCORPORATE BY REFERENCE ................................................................................................ 111

10.0 OTHER COMMENTS NOT COVERED ...................................................................................... 113

11.0 DUPLICATE COMMENTS ........................................................................................................... 114

 
5 

LIST OF COMMENTERS 

Commenter Name Commenter Organization Docket ID

Floyd Gilzow Missouri Joint Municipal Electric Utility 

Commission EPA-HQ-OAR-2009-0234-20238 

Cecile M. Conroy International Brotherhood of Boilermakers 

(IBB) EPA-HQ-OAR-2009-0234-20241 

David Ussery Platte River Power Authority EPA-HQ-OAR-2009-0234-20242 

Terry M. Hogan Wabash Valley Power Association, Inc. EPA-HQ-OAR-2009-0234-20243 

Karen Jackson Grand Parents Second Time Around EPA-HQ-OAR-2009-0234-20244 

Eric Redman Summit Power EPA-HQ-OAR-2009-0234-20245 

Bart Sponseller Wisconsin Department of Natural 

Resources (WDNR) EPA-HQ-OAR-2009-0234-20246 

Claire M. Olson Basin Electric Power Cooperative EPA-HQ-OAR-2009-0234-20247 

Walter Stone NRG Energy, Inc. EPA-HQ-OAR-2009-0234-20248 

Todd Parfitt Wyoming Department of Environmental 

Quality EPA-HQ-OAR-2009-0234-20249 

Kimberly A. Scarborough PSEG Services Corporation EPA-HQ-OAR-2009-0234-20250 

Bob Holmes Omaha Public Power District (OPPD) EPA-HQ-OAR-2009-0234-20251 

Lisa Jaeger Edgecombe Genco LLC and Spruance 

Genco LLC EPA-HQ-OAR-2009-0234-20252 

Gregory C. Staple American Clean Skies Foundation (ACSF) EPA-HQ-OAR-2009-0234-20253 

Joe L. Citta, Jr. Nebraska Public Power District (NPPD) EPA-HQ-OAR-2009-0234-20254 

Patrick O’Loughlin Buckeye Power, Inc. EPA-HQ-OAR-2009-0234-20255 

Raymond L. Evans FirstEnergy Corp. EPA-HQ-OAR-2009-0234-20256 

Kenneth J. Anderson Ameren Corporation EPA-HQ-OAR-2009-0234-20257 

Frank L. Kohlasch Minnesota Pollution Control Agency EPA-HQ-OAR-2009-0234-20258 

Anonymous Individual EPA-HQ-OAR-2009-0234-20259 

Anonymous Individual EPA-HQ-OAR-2009-0234-20260 

Paul Chu Electric Power Research Institute (EPRI) EPA-HQ-OAR-2009-0234-20261 

Mark Thoma Otter Tail Power Company EPA-HQ-OAR-2009-0234-20262 

Bob Davis Airgas, Inc. EPA-HQ-OAR-2009-0234-20263 

Catharine Fitzsimmons Iowa Department of Natural Resources EPA-HQ-OAR-2009-0234-20264 

Paul Bailey American Coalition for Clean Coal 

Electricity (ACCCE) EPA-HQ-OAR-2009-0234-20265 

Lindil C. Fowler, Jr. Railroad Commission of Texas (RRC) EPA-HQ-OAR-2009-0234-20266 

PJ Becker City of Springfield, City Water Light and 

Power EPA-HQ-OAR-2009-0234-20267 

Betsy Natz Institute of Clean Air Companies (ICAC) EPA-HQ-OAR-2009-0234-20268 

Debra J. Jezouit Baker Botts L.L.P. et al. on behalf of The 

Class of ‘85 Regulatory Response Group EPA-HQ-OAR-2009-0234-20269 

Chris M. Hobson Southern Company EPA-HQ-OAR-2009-0234-20270 

Cathy S. Woollums MidAmerican Energy Holdings Company EPA-HQ-OAR-2009-0234-20271 

Jay Hudson Santee Cooper EPA-HQ-OAR-2009-0234-20272 

John A. Riley Bracewell & Giuliani LLP, on behalf of 

Las Brisas Energy Center, LLC EPA-HQ-OAR-2009-0234-20273 

Susan Eckerly National Federation of Independent 

Businesses (NFIB) EPA-HQ-OAR-2009-0234-20274 
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Michael J. Nasi Jackson Walker, LLP, on behalf of Gulf 

Coast Lignite Coalition (GCLC) EPA-HQ-OAR-2009-0234-20275 

Jon Madison Montana-Dakota Utilities Company EPA-HQ-OAR-2009-0234-20276 

Greg F. Myers Consumers Energy EPA-HQ-OAR-2009-0234-20277 

Myra Glover Entergy Services, Inc. EPA-HQ-OAR-2009-0234-20279 

Kelly J. Barr Salt River Project (SRP) EPA-HQ-OAR-2009-0234-20280 

J. Michael Geers Duke Energy EPA-HQ-OAR-2009-0234-20281 

Lee B. Zeugin, et al. Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2009-0234-20282 

Alex Bond National Mining Association (NMA) EPA-HQ-OAR-2009-0234-20284 

Jeffrey A. McNelly ARIPPA EPA-HQ-OAR-2009-0234-20285 

Zak Covar Texas Commission on Environmental 

Quality (TCEQ) EPA-HQ-OAR-2009-0234-20286 

Chet Thompson Crowell & Moring LLP, on behalf of 

Homer City Generation, L.P. EPA-HQ-OAR-2009-0234-20287 

Stephen Fotis Generators for Clean Air (GCA) EPA-HQ-OAR-2009-0234-20288 

Henry E. Eby Lower Colorado River Authority (LCRA) EPA-HQ-OAR-2009-0234-20289 

Daniel R. Wilkus Westar Energy, Inc. EPA-HQ-OAR-2009-0234-20290 

Paul M. Ling Kansas City Power & Light Company 

(KCP&L) EPA-HQ-OAR-2009-0234-20291 

Mark J. Sedlacek Los Angeles Department of Water and 

Power EPA-HQ-OAR-2009-0234-20292 

Arthur N. Marin Northeast States for Coordinated Air Use 

Management (NESCAUM) EPA-HQ-OAR-2009-0234-20293 

J. Michael Brown Ohio Valley Electric Corporation EPA-HQ-OAR-2009-0234-20294 

Quinlan J. Shea Edison Electric Institute (EEI) EPA-HQ-OAR-2009-0234-20295 

Peter Glaser Troutman Sanders, LLP, for New Unit 

Developers EPA-HQ-OAR-2009-0234-20296 

Brian Brazil TransAlta Centralia Generation, LLC EPA-HQ-OAR-2009-0234-20297 

Gary S. Rose Connecticut Department of Energy and 

Environmental Protection EPA-HQ-OAR-2009-0234-20298 

Norman Schilling General Electric Company (GE) EPA-HQ-OAR-2009-0234-20299 

David Woodsmall Sierra Club, et al. EPA-HQ-OAR-2009-0234-20300 

Donna Nelson Public Utility Commission of Texas EPA-HQ-OAR-2009-0234-20301 

Michael L. Krancer Pennsylvania Department of 

Environmental Protection (PDEP) EPA-HQ-OAR-2009-0234-20302 

Joseph G. Eutizi San Miguel Electric Cooperative EPA-HQ-OAR-2009-0234-20303 

Melvin E. Keener Coalition for Responsible Waste 

Incineration (CRWI) EPA-HQ-OAR-2009-0234-20304 

David Woodsmall Sierra Club, et al. EPA-HQ-OAR-2009-0234-20305 

Gregory Ryan DTE Energy EPA-HQ-OAR-2009-0234-20306 

Holly Rachel Smith, Esq. National Association of Regulatory Utility 

Commissioners (NARUC) EPA-HQ-OAR-2009-0234-20307 

John M. McManus American Electric Power (AEP) EPA-HQ-OAR-2009-0234-20308 

Terrance Stanton Individual EPA-HQ-OAR-2009-0234-20309 

David Low Individual EPA-HQ-OAR-2009-0234-20310 

Nancy Barta-Smith Individual EPA-HQ-OAR-2009-0234-20311 
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Jay Sweeney Individual EPA-HQ-OAR-2009-0234-20312 

Mass comment campaign 

sponsoring organization 

unknown (email) 

Mass mail EPA-HQ-OAR-2009-0234-20313 

Berdell Knowles JEA EPA-HQ-OAR-2009-0234-20321 

Joaquin C. Flores Guam Power Authority EPA-HQ-OAR-2011-0044-5785 

Megan Murphy PPL Services Corporation EPA-HQ-OAR-2011-0044-5803 
8 

1.0 LEGAL 

1.1 New Source Trigger Date: May 3, 2011 

Comment: Commenters (20251 and 20308) stated that the meaning of paragraph 63.9982(c) in the 

proposed reconsideration is not clear. The Commenters agreed that applicability for new and 

reconstructed electric utility steam generating units (“EGUs”) rely on the 5/3/2011 date. The 

Commenters recommended that the “or if” in 40 CFR §63.9982(c) should be “and” because you must 

meet the reconstruction criteria and begin reconstruction after 5/3/2011. The Commenters noted that 

otherwise this is retroactive to any work that causes a source to meet the reconstruction criteria, even if 

the changes were made prior to the effective date in 40 CFR §63.9982(b). The Commenters suggested 

the following change to the language: 

An EGU is reconstructed if you meet the reconstruction criteria as defined in §63.2, or

and if you commence reconstruction after May 3, 2011. 

Commenter (20282) disagreed that the EPA’s proposed change to correct the discrepancy between 40 

CFR §63.9982(c) and §63.9985(a) is a technical correction that may be undertaken without additional 

analysis. The Commenter stated that with the correction, the EPA proposes, contrary to CAA §112 and 

the existing rule, to apply the more stringent emission limits for new EGUs that were not constructed or 

reconstructed after May 3, 2011. The Commenter stated that to avoid this result, and limit the change to 

a technical correction, the EPA should substitute the word “and” in place of the word “or.” 

Commenter (20282) stated that in the event that the Agency’s use of the word “or” was intentional, and 

not a drafting error, the Commenter reminds the Agency that it lacks the statutory authority to trigger the 

reconstruction rule for activities that occurred before May 3, 2011. The Commenter discussed this point. 

Response: The EPA has made the change suggested by the Commenter in the final rule. 

1.2 Comments on issues which were not reconsidered in this notice 

Comment: Commenters (20273, 20286, 20295, 20296, 20302, and 20308) disagree with the EPA’s 

pollutant-by-pollutant approach to setting MACT standards. 

Commenter (20273) stated that EPA’s reconsidered MATS are still based on the incorrect premise that 

EPA can establish limits through a pollutant-by-pollutant methodology and not based on the 

performance of a single source. The Commenter stated that EPA’s Reconsidered MATS, although 

improved over the promulgated MATS, are contrary to the explicit language of CAA §112(d)(3) 

because they were established using a pollutant-by-pollutant approach where different EGUs were 

selected as the best controlled source for each individual pollutant to be regulated. The Commenter 

observed that the statutorily prescribed method for determining these standards requires EPA to identify 

the single “best controlled similar source” for all of the pollutants to be regulated. The Commenter 

stated that because EPA deviated from the statutorily mandated method, it is unclear as to whether the 

reconsidered MATS standards are “achievable” by any new solid oil-derived fueled EGUs. The 

Commenter stated that the Joint Brief of Petitioners filed in the United States Court of Appeals for the 

District of Columbia Circuit (“D.C. Circuit”) on July 27, 2012 in Case No. 12-1272, Document No. 
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1386256, correctly sets forth the legal constraints on EPA in setting the MATS and the points made in 

Section II of that brief, of which EPA is unquestionably aware, are incorporated by reference into these 

comments, the EPA’s statements to the contrary notwithstanding. 

Commenter (20286) stated that the hazardous air pollutant (HAP)-by-HAP approach used by the EPA to 

develop numerical emission standards does not consider overall technical feasibility. The Commenter 

stated that EPA’s arbitrary acceptance of the results of the HAP-by-HAP analysis when establishing 

MACT emission standards is contrary to the federal Clean Air Act (CAA) §112. The Commenter 

suggests an alternate MACT analysis approach using the HAP-by-HAP approach initially to screen 

facilities to determine the “best controlled similar source” while basing the final MACT floor 

determination on a holistic approach. The Commenter provided justification for why they believe that 

EPA’s HAP by HAP approach is arbitrary and capricious, highlighting The Logan Generating Plant, 

previous litigation, and the CAA. 

Commenter (20295) stated that the pollutant-by-pollutant approach to setting MACT standards for 

existing EGUs is contrary to CAA §112(d)(3). 

Commenter (20296) disagreed that the EPA’s pollutant-by-pollutant approach is a correct method of 

implementing CAA §112(d)(3) and maintain that EPA instead must set the standard based on the single 

EGU that emits the lowest level of all of the pollutants to be regulated. The Commenter attached a court 

brief with more details. 

Commenter (20302) stated that in the development of new emission standards for certain pollutants 

emitted by new and reconstructed EGUs, the EPA cherry-picked one of the best performing EGUs for 

each particular pollutant and statistically derived an emission limit based on that one EGU. The 

Commenter disagreed with this approach, and stated that a more appropriate approach would be to 

identify the best performing EGU or EGUs for total HAP and statistically derive all emission limits 

based on those EGUs. The Commenter referred to the language of CAA §112(d)(3), and noted that the 

CAA requires that emissions limitations for new EGUs may not be less stringent ‘‘than the emission 

control that is achieved in practice by the best controlled similar source,” not the best controlled sources. 

The Commenter stated that the rulemaking docket does not support a conclusion that the standards are in 

fact achievable. 

Commenter (20308) objected to proposed standards for individual HAP or surrogates for HAP based on 

the performance of a different set of EGUs for each different HAP standard, which establishes emission 

limits that are not indicative of what a single source has demonstrated or could demonstrate to be 

achieved or achievable in practice. The Commenter stated that EPA’s methodology fails to provide 

appropriate consideration of the potential impact on the ability to effectively control other HAP when 

choosing the “best performing” results for a given HAP. The Commenter suggested that the EPA follow 

the language of CAA §112(d)(3) for setting new source MACT limits. The Commenter encouraged the 

EPA to re-evaluate the emissions data for HAP in their entirety to develop new source emission limits 

that can be met by the best performing EGUs in accordance with the CAA language. 

Response: 

We did not re-open the pollutant-by-pollutant issue. In any event, we vigorously disagree with the 
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Commenters who dispute the Agency’s long-standing pollutant-by-pollutant approach to setting MACT 

floors. As explained in the preamble and response to comments supporting the February 2012 final rule, 

the pollutant-by-pollutant approach to setting MACT floors for new sources under 42 U.S.C. § 

7412(d)(3) reflects a reasonable interpretation of that section.1

 The Commenters’ approach is clearly not 

mandated by the statutory text. Indeed, the statute does not specify whether the best controlled source is 

to be identified in regard to each pollutant for which standards are set, or in regard to the entire suite of 

regulated pollutants emitted. The EPA’s approach is reasonable for all of the reasons set forth in the 

preamble to the final rule and response to comments, and we incorporate those responses herein by 

reference. See, e.g., 77 FR 9304, 9386-88 (February 16, 2012); Response to Comments document for the 

final MATS rule (RTC, Docket ID EPA-HQ-OAR-2009-0234-20126) Vol. 1, pp. 423 - 433. Moreover, 

as explained previously, EPA’s approach is consistent with the context, purpose and legislative history 

of section 7412. See S. Rep. 101-228 (1989) at 3553 (“[t]he technology-based standards promulgated 

pursuant to this authority shall provide for the maximum degree of reduction in emissions of each of the 

listed pollutants released by sources in the category”) (emphasis added). 

Although not required, EPA has reviewed all of the new source limits, including the revised numerical 

limits, and the existing data in the record. It is worth noting that some sources are, in fact, meeting all of 

these limits. First, the test data available to the EPA at the time of the 2012 rule show that there are a 

number of existing coal-fired EGUs that have achieved the new source limits (considering all of their 

submitted data). Specifically, in the reconsideration proposal notice, the EPA indicated that “based on 

our review of the data EPA collected as part of the 2010 Information Collection Request (ICR) process, 

at least eight existing non-low rank virgin coal-fired EGUs and one low rank virgin coal-fired EGU” in 

this category meet the new source limits for mercury (“Hg”), particulate matter (“PM”), and 

hydrochloric acid/hydrogen chloride (“HCl”), which cover all of the HAP subject to numerical emission 

standards in the final rule (see 77 FR 71329). Because this analysis was based on a review of the same 

2010 ICR data available to the public (and, thus, the analysis could also have been done by the public), 

the EPA did not identify these EGUs. The following EGUs have short-term stack test data that 

demonstrate that these EGUs have in practice achieved all the numeric new source limits for Hg, PM, 

and HCl: 

Logan Unit 1 

Elm Road Unit 1 

Clover Units 1 and 2 

Chambers Units 1 and 2 

Mount Tom Unit 1 

H.L. Spurlock Unit 3 

Sandow Unit 5A 

In addition, contrary to both the language of CAA section 112(d)(3) and the broader purpose it reflects, 

Commenters’ approach to setting MACT floors based on a single source could result in standards that 

reflect emissions levels achieved by an existing EGU that is not a best performer in regard to any HAP – 

 

1

 The Agency has used the pollutant-by pollutant approach to setting MACT floors for almost two 

decades. See 60 FR 65387, 65395 (December 19, 1995); see also Portland Cement Ass’n v. EPA, 665 

F.3d 177, 189 (D.C. Cir. 2011) (challenge to pollutant-by-pollutant approach not raised in response to 

initial 1999 rule was barred). 
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a result the EPA has aptly stated would lead to “least common denominator floors.” See 77 FR 9387. In 

fact, utilizing the single-EGU theory proferred by Commenters could result in the EPA setting standards 

at levels that would, for some pollutants, actually be based on emissions data from lower performing 

EGUs (as a poorly-performing source for a particular pollutant could nevertheless be identified as 

having the best overall performance), rather than the best-performing EGU, as required by the statute. 

The available emissions information demonstrates that there are, in fact, EGUs which are best 

performing EGUs for one HAP, but these EGUs are among the worst performing EGUs for other HAP. 

For example, Hatfield’s Ferry Unit 1 is number 5 on the acid gas list but only number 255 on the Hg list; 

Rawhide Unit 101 is number 14 on the acid gas list but only number 314 on the Hg list; Dunkirk Unit 1 

is number 2 on the PM list but only number 166 on the Hg list; and Sheldon Station Unit 2 is number 5 

on the PM list but only number 102 on the Hg list. Given this circumstance, it would be virtually 

impossible for EPA to identify a specific EGU that represents the overall best-performing EGU for all 

HAP. Such a result is not consistent with the statutory requirement that new source MACT limits be 

based on the performance of the best performing source. Moreover, the approach taken by the Agency 

provides a reasonable mechanism for ensuring that each new source limit is based on the best controlled 

similar source, and, as noted above, there are sources that have demonstrated they are meeting all the 

numerical new source limits. 

Comment: Commenter (20286) stated that the EPA has not properly considered the impacts of its 

approach for establishing MACT emission standards on reconstructed EGUs. The Commenter stated 

that there is no documentation in the proposed MATS rule that EPA considered the technical feasibility 

of the proposed new source standards to reconstructed sources. The Commenter stated that the HAP-byHAP approach used by the EPA is incompatible with reconstructed sources, because it does not consider 

technical feasibility to a specific emission source because the selection of emission rates from multiple 

sources draws from multiple unique designs and specific fuel characteristics. 

Commenter (20286) stated that the EGU design and other unique aspects already exist and the 

reconstruction of those sources may not fundamentally change the existing reconstructed source into the 

newly constructed source. The Commenter stated that the EPA either needs to apply a “whole-plant” 

view in establishing emission standards (i.e., look at the performance of all pollutants from one single 

reconstructed EGU) or if EPA wants to continue a piecemeal approach to establishing the standards, it 

must further subcategorize emission standards to consider specific emission source designs and fuel 

type, which have significant effects on emission performance. 

Response: This issue is outside the scope of this rulemaking. Subcategorization was addressed in the 

final rule (see, e.g., 77 FR 9378 - 9379, 9394 - 9402). The EPA did not solicit comment in the 

reconsideration proposal on additional subcategories. In addition, as noted in response to comments 

above, the EPA did not open for comment the pollutant-by-pollutant approach to establishing new 

source MACT limits. In any case, the EPA does not agree with the Commenter. The EPA has broad 

discretion in making decisions concerning subcategorization, and the Commenter has not provided data 

to support an argument that additional new source categories are necessary or supportable for 

reconstructed EGUs. See CAA section 112(d)(1) (stating that the Agency “may” establish 

subcategories). 

Furthermore, the EPA’s understanding of reconstructions is based primarily on the enforcement actions 

brought against power plants and on self-reporting by power plants. Over the lengthy history of the 
12 

Agency’s programs, such actions have been too few in number to allow us to develop a sufficiently 

robust base of knowledge. The EPA is aware of the KCP&L situation at the Hawthorn Station (i.e., Unit 

5 boiler explosion in 1999 and subsequent rebuilding) and data from Hawthorn Unit 5 are in the 2010 

ICR database and were, thus, considered in the analyses. Further, data from any other reconstructed 

EGUs would also be in the 2010 ICR database and analyses. In any case, if an owner or operator intends 

to reconstruct an EGU, the reconstruction will need to occur in a manner that ensures that the 

reconstructed EGU will be able to comply with the final MATS rule. The Commenters have not 

demonstrated that reconstructed EGUs will be unable to comply with the applicable new source limits. 

Nothing in the statute requires the EPA to consider every potential scenario in establishing new source 

MACT standards and the Agency maintains that its approach is consistent with the statute and no 

information provided by the Commenters supports a different conclusion. 

Comment: Commenter (20246) stated the EPA should develop separate emission limit categories for 

EGUs using different types of coal-fired boiler technologies, such as super critical pulverized boilers 

(SPC), fluidized bed combustion (FBC) boilers, conventional pulverized coal (PC), and advanced stoker 

boilers. The Commenter said the EPA is proposing new source emission limitations for all coal-fired 

power plants based on the best emission rate (by pollutant) demonstrated by either a SPC boiler or a FB 

boiler. The Commenter stated it is not clear that the resulting set of hybrid emission limits can be 

achieved at all types of new coal-fired EGUs at the cost levels considered in EPA’s analysis. The 

Commenter also stated that the EPA appears to believe that these two specific boiler types are 

interchangeable and can meet requirements for all different types of EGU configurations and projects. 

The Commenter stated this is not true. The Commenter said SPC boilers are exclusive to large base-load 

power plant applications, whereas FB boilers are utilized for smaller generation or co-generation 

projects. The Commenter said another factor to consider is that different boiler types, such as advanced 

stoker boilers, may serve a project more efficiently or allow the use of alternative fuel combinations 

which results in lower overall emissions. The Commenter stated more efficient options should not be 

precluded by the new source emission limits. 

Response: This issue is outside the scope of this rulemaking. Subcategorization was addressed in the 

final rule (see, e.g., 77 FR 9378 - 9379, 9394 - 9402). The EPA did not solicit comment in the 

reconsideration proposal on additional subcategories. In any case, the EPA does not agree with the 

Commenter. The EPA has broad discretion in making decisions concerning subcategorization. See CAA 

section 112(d)(1) (stating that the Agency “may” establish subcategories). Furthermore, the Commenter 

has provided no data that would support its contention that additional subcategories are warranted or 

necessary. The EPA maintains that without such demonstration it would be unreasonable to establish 

additional subcategories for new sources. 

Comment: Commenter (20273) stated the MATS limit for solid oil-derived fuel for HCl is too stringent. 

The Commenter noted there was no change in the MATS limit for HCl emissions (4.0 x 10-4 pounds per 

megawatt-hour, lb/MWh) for new solid oil-derived fuel-fired EGUs. The Commenter stated that based 

on discussions with equipment manufacturers, the HCl limit of 0.0004 lb/MWh is too low to provide a 

guarantee. The Commenter said this limit represents a very low concentration of HCl where the 

accuracy of the test methods is questioned by the vendors. The Commenter continued that one potential 

vendor confirmed to the Commenter’s consultants that without a reliable method to measure emissions 

at the proposed levels, it is unlikely to provide a guarantee. The Commenter stated, nonetheless, with the 

alternate limit for sulfur dioxide (SO2) emissions as a surrogate for compliance with the HCl MATS 
13 

appropriately raised from 0.4 to 1.0 lb/MWh in the proposed reconsidered MATS for solid oil-derived 

fuel-fired EGUs, and that compliance with the reconsidered MATS is possible. 

Response: The HCl limit for solid oil-derived fuel-fired EGUs was not among those limits revised and 

proposed for comment in the reconsideration notice. Moreover, the EPA is under no obligation to review 

HCl limit for solid oil-derived fuel because the deadline for commenting on the RDL procedure for HCl 

in the petition for reconsideration is long past. Should a solid oil-derived fuel-fired EGU owner or 

operator believe HCl CEMS incapable of providing accurate measurements for compliance purposes, he 

can choose to use quarterly testing, along with continuous monitoring of one or more parameters. 

Further, as Commenter notes, such EGUs with add-on SO2 controls in-place are eligible for the alternate 

SO2 emission limit. 

Comment: Commenter (20273) stated the MATS standard for solid oil-derived fuel for Hg is too 

stringent. The Commenter noted, as with HCl, the reconsidered MATS standard has not changed for Hg 

emissions for solid oil-derived fuel-fired EGUs and remains at 2.0 x 10-3 pounds per gigawatt-hour 

(lb/GWh). The Commenter stated that to achieve this standard, the Hg removal efficiency requirements 

are approximately 99.6 percent for some petroleum coke fuel to stack. 

Commenter (20273) stated, furthermore, although the proposed Hg limit for new coal EGUs (0.003 

lb/GWh) is considered very aggressive and compliance will present a significant challenge with current 

control technologies and require an improved understanding of removal performance for these 

technologies, the proposed MATS standard for Hg for solid oil-derived fuel-fired EGUs is even more 

aggressive at 0.002 lb/GWh. The Commenter’s consultants have advised that with application of a 

combination of different technologies, at least one vendor suggests that it would guarantee the 

reconsidered MATS Hg limits for new coal EGUs. The Commenter stated that with the suite of controls 

planned for the LBEC, there is growing operating experience that helps them understand the 

mechanisms for Hg capture and, over time, may provide a sufficient basis for vendors to provide a 

guarantee at the lower reconsidered MATS standard applicable to petroleum coke fuel. The Commenter 

stated, however, the detectability, operability, and practicality concerns that EPA accepted and endorsed 

in justifying the higher Hg MATS standard for coal EGUs are equally applicable to solid oil-derived 

fuel-fired EGUs. The Commenter stated that the EPA must be consistent and apply the same 

considerations and reasoning in setting standards for all types of EGUs. The Commenter stated that they 

are advised that the use of PAC in conjunction with circulating semi-dry scrubber flue gas 

desulfurization (CDS-FGD) technology for control of Hg can support guarantees at the reconsidered 

MATS limits for new coal EGUs, 0.003 lb/GWh. 

Commenter (20273), based on the above, requested that EPA reset the proposed limit for Hg for solid 

oil-derived fuel-fired EGUs where it sets the limit for coal. The Commenter stated, as EPA explains in 

its overarching justification for the reconsideration of the promulgated MATS rule, the reconsidered 

MATS rule will not lead to the application of different controls and that is certainly true for Hg in the 

LBEC context. 

Response: The EPA did not propose to revise the Hg limit for solid oil-derived fuel fired EGUs, and, for 

that reason, the comment is outside the scope of this action and we have no obligation to respond. 

Although not required, we did review the impact of using the three times the representative detection 

level (“3XRDL”) approach for Hg emissions from solid oil-derived fuel fired EGUs and conclude that 
14 

the use of such approach would not change the standard finalized in the February 2012 final rule. 

Specifically, the EPA conducted the same type of 3XRDL analysis for the solid oil-derived fuel Hg limit 

as was conducted for the coal Hg limit using the Hg data from the solid-oil fired EGUs. The EPA found 

the average RDL from the best performing solid oil-derived fuel fired EGUs for which data were 

available to be 1.2 nanograms. Using that value, as well as the heat rate and F-factor for solid oil-derived 

fuel (8,900 British thermal units per kilowatt-hour (Btu/kWh) and 9,830 cubic meters per million Btu 

(m3/MMBtu), respectively) in calculations to express the 3XRDL value in terms of an emissions limit, 

the resulting 3XRDL value was 0.00060 lb/MWh. Thus, the EPA found the 0.0020 lb/GWh limit 

finalized in MATS for solid oil-derived fuel-fired EGUs to be appropriate for those EGU owners or 

operators who believe frequent sampling times (30 minutes of sample collection) over short periods of 

load or process transition is necessary. EGU owners or operators who choose to sample for longer 

periods should have no problems using sorbent monitoring systems for compliance purposes. 

Comment: Commenter (20303) stated that the beyond-the-floor (BTF) limit for existing low-rank virgin 

coal EGUs, established at 4.0 pounds per trillion Btu (lb/TBtu) in the rulemaking, cannot be attained by 

existing EGUs. The Commenter stated that the BTF limit was based on the lowest data point from a 

single EGU rather than the group of EGUs required by the CAA, and that this is a violation of the CAA. 

The Commenter noted that the one newest EGU could not consistently meet the proposed 4.0 lb/TBtu 

limit. The Commenter concluded that the Hg BTF limit for low-rank virgin coal EGUs should be struck 

from the rule or at a minimum be revised to an achievable limit. The Commenter suggested a limit of 7.0 

lb/TBtu. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding the existing-source emission limits. 

Comment: Commenter (20282) asked that the EPA further revise portions of the MATS rule to address 

issues in its petition for reconsideration (incorporated by reference in their comment) that were not 

addressed in the proposed reconsideration. 

Response: This issue is outside the scope of this rulemaking. The EPA specifically identified the issues 

being proposed for reconsideration in the November 30, 2012, notice (77 FR 71323); other issues 

contained in the petitions for reconsideration are being addressed outside of this rulemaking. 

1.3 Other legal 

Comment: Commenters (20265 and 20296) urged EPA to finalize the proposed rule as quickly as 

possible. 

Commenter (20265) stated the combination of the new source standards in the MATS rule and EPA’s 

proposed greenhouse gas (GHG) New Source Performance Standards (NSPS) for new coal-fueled EGUs 

has created a regulatory Catch-22 for new EGUs. The Commenter stated that on the one hand, under the 

proposed GHG NSPS, new EGUs having PSD permits must commence construction by April 12, 2013, 

in order to avoid being subject to the proposed NSPS (which new coal EGUs cannot meet). On the other 

hand, according to the Commenter, the EPA’s MATS rule new source standards, because they also 

could not be met, effectively prevented new EGUs from commencing construction. The Commenter 

stated because of the time EPA has taken to reconsider the new source MACT standards, the 1-year 
15 

deadline to commence construction under the GHG NSPS is about to expire. 

Commenter (20265) noted that EPA stated that it intends to finalize the reconsidered new source MACT 

standards by “March.” The Commenter stated, however, new EGUs cannot commence construction 

immediately after new source MACT standards are published because time will be needed to evaluate 

the final standards, to negotiate equipment purchase contracts with vendors, and to take other necessary 

steps that are a prerequisite to commencing construction. The Commenter said, therefore, March may be 

too late to ensure that new EGUs can commence construction by April 12. The Commenter concluded 

that to give new EGU developers at least some chance to meet the April 12 deadline, the EPA must issue 

the final standard as early in March as possible. 

Commenter (20296) further asked that the EPA extend the transitional source period for the GHG NSPS 

rule by an amount of time equal to the period of time between publication of the initial MATS rule and 

publication of the reconsidered MATS rule. 

Response: Comments on the GHG NSPS rule are outside the scope of this rulemaking. The remaining 

comments concerning finalization of the new source limits are moot. 

Comment: Commenter (20251) stated that the MATS rule should clearly state that it does not apply to 

stationary CTs that are not associated with an IGCC EGU. The Commenter stated that there is a 

statement on page 9309 of the preamble to the February 16, 2012, final rule that indicates that EPA does 

not consider stationary CTs to be EGUs for the purpose of the final MATS rule, and a footnote to this 

statement states that the CT NESHAP regulates HAP emissions from all simple-cycle and combinedcycle stationary CTs producing electricity or steam for any purpose. The Commenter stated that this is 

not correct, as the CT NESHAP only applies to CTs located at major sources. The Commenter asked 

that this be clarified by revising paragraph 63.9983(a) of the MATS rule, which specifies EGUs not 

subject to the rule, to read as follows: 

(a) Any unit designated as a stationary combustion turbine, other than an integrated 

gasification combined cycle (IGCC) unit., covered by 40 CFR part 63, subpart YYYY.

Response: This issue is outside the scope of this rulemaking. The EPA did not receive petitions for 

reconsideration on this issue and it was not open for reconsideration in the November 30, 2012, notice. 

Comment: Commenter (20286) stated that although the EPA in this action is reconsidering the SO2

limit for new coal-fired EGUs based on its original inclusion of a unit that is actually an industrial 

boiler, and therefore, not subject to MATS, the EPA also states in the preamble (77 FR 71326) to the 

proposed rule that “As an initial matter, nothing in the CAA precludes the EPA from identifying a 

source in another source category as the best controlled similar source.” The Commenter disagreed with 

this statement, stating that it is clearly in opposition to the decision of the U.S. Court of Appeals for the 

District of Columbia regarding the Portland Cement NESHAP. (Portland Cement Association v. EPA, 

665 F.3d 177 (D.C. Cir. 2011)). The Commenter provided discussion regarding other court rulings 

pertaining to this approach. 

Commenter (20296) disagreed with EPA’s assertion that “nothing in the CAA precludes the EPA from 

identifying a source in another source category as the best controlled similar source.” The Commenter 
16 

stated that by definition, a source in a different category cannot be deemed to be “similar” to sources in a 

different category. 

Commenter (20249) stated in Item 2 of Section IV, when addressing whether a boiler used to establish 

the SO2 standard for new coal-fired EGUs qualified as an EGU, the EPA states: 

As an initial matter, nothing in the CAA precludes the EPA from identifying a source in 

another source category as the best controlled similar source. However, they believe that 

it is appropriate in this case, where we have considerable data on EGUs, to base the new 

source standard on the best performing unit that is an EGU.” 

Commenter (20249) stated that when EPA establishes NSPS, the EPA must consider whether the 

standards are achievable given the type and operation of the source. The Commenter stated, when 

identifying sources in other source categories for consideration in establishing a new performance 

standard, the EPA should provide an analysis demonstrating similarity between the source from another 

category and sources affected by the new standard. The Commenter added that this analysis must also 

address whether the data used by the similar source applies to all modes of operation or just specific 

operating times. 

Response: Although we disagree with the Commenters’ assertions concerning the term “similar source” 

as it appears in CAA section 112(d)(3), we need not address this issue as the Agency established all of 

the final MATS MACT standards based on EGUs. 

 
17 

2.0 NEW SOURCE EMISSION LIMITS 

2.1 New coal-fired EGU 

2.1.1 Filterable PM (9.0E-02 lb/MWh) 

Filterable PM emission standard 

Comment: Commenter (20293) stated that EPA finalized a filterable particulate matter (fPM) limit of 

0.007 lb/MWh, which should be revised on reconsideration because it is not feasible and appears to be 

the result of an error in interpreting or transcribing test results from one facility. The Commenter stated 

that the 0.09 lb/MWh limit that EPA now proposes is higher than would be warranted based on the data 

in the record. The Commenter stated that the result of EPA’s calculation was 8.23 x 10-2 lb/MW. 

Expressed to two significant digits, this result properly rounds to 8.2 x10-2 lb/MW or, arguably 8.3 x10-2

lb/MW, but not to 9.0 x10-2 lb/MW, as proposed by EPA. 

Response: This comment focuses on the use of EPA’s rounding convention, and that issue is outside the 

scope of this rulemaking. The EPA did not solicit comment in the reconsideration proposal regarding the 

rounding convention used in determining the final emission limits. The EPA used the same rounding 

convention for fPM as was used in the MATS proposal and final (see, e.g., RTC, Vol. 1, pp. 463 - 465), 

and we maintain that the approach is reasonable for the reasons stated in the entire MATS record. 

Accordingly, we disagree with the Commenter that the fPM limit, as revised in the final reconsideration 

rule, is incorrect. 

Comment: Commenter (20305) stated that the proposed reconsidered fPM standards are extraordinarily 

lenient. The Commenter stated that the numeric emissions rate is well in excess of emissions 

demonstrated by the best-performing plants. The Commenter noted that the Agency has already relaxed 

the stringency of its limits by extending compliance to 30 operating days. 

Response: The EPA used the same approach for selecting the “best performing similar source” and in 

conducting the MACT floor analyses in the proposed reconsideration as was used at proposal and final 

(see, e.g., Docket ID EPA-HQ-OAR-2009-0234-9858, National Emission Standards for Hazardous Air 

Pollutants (NESHAP) Maximum Achievable Control Technology (MACT) Floor Analysis for Coal- and 

Oil-fired Electric Utility Steam Generating Units – REVISED; Docket ID EPA-HQ-OAR-2009-0234-

20132, National Emission Standards for Hazardous Air Pollutants (NESHAP) Maximum Achievable 

Control Technology (MACT) Floor Analysis for Coal- and Oil-fired Electric Utility Steam Generating 

Units for Final Rule; “MATS MACT Floor Memos”). That is, the EPA selected the best controlled EGU 

for the MACT floor analysis after ranking the EGUs based on their single best 3-run test average. The 

EPA then incorporated any other data from the EGUs selected for the MACT floor analysis into the 

variability analyses. Issues related to the incorporation of variability were addressed at final (see, e.g., 

RTC, Vol. 1, p. 662). The EPA recognizes that other approaches to selecting the best performing source 

exist, but the Agency maintains that its approach is reasonable and consistent with the statute. The 

Commenter has not demonstrated that the Agency erred in calculating the final fPM limit using the 

approach for establishing MACT limits in the MATS rule. 

Comment: Commenter (20305) stated that the 30-day rolling average was originally developed to 
18 

account for variability during periods of startup and shutdown, but EPA failed to explain in the final 

Rule why the standard was not made more stringent based on EPA’s decision to exclude periods of 

startup, shutdown, and maintenance from compliance calculations. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding adjustments to the filterable PM standard based on exclusion during 

periods of startup or shutdown. In any event, the EPA disagrees with the Commenter’s suggestion that 

the 30-boiler operating day rolling average was developed primarily to account for variability during 

periods of startup and shutdown and that the emission limit should become more stringent when periods 

of startup or shutdown are excluded. Comments regarding variability were received after publication of 

the proposed rule, and those comments were addressed at final. As mentioned in the RTC, the 30-boiler 

operating day rolling average was designed to incorporate a variety of sources of variability, including, 

but not limited to, load, operational, fuel, and CEMS use (see, e.g., RTC, Vol. 1, p. 564). Removal of 

just one component of potential variability in no way diminishes the other components of variability. 

The Commenter has provided no data or information to suggest that the possible variability associated 

with periods of startup and shutdown is sufficiently great such that a less robust variability analysis is 

necessary. In fact, the Agency did not have startup and shutdown data when developing the rule, so the 

impact of those periods on HAP emissions is unknown. 

Moreover, the EPA explained its approach to assessing variability in the proposed MATS rule, and the 

Agency did not revise its approach to assessing variability in this reconsideration of certain new source 

MACT standards. See 76 FR 25041; EPA-HQ-OAR-2009-0234-20062 (explaining the UPL analysis). 

The EPA relies on the prior discussions of variability in the MACT standard setting process and further 

notes the following about the variability analysis in the MATS MACT standard setting process. 

The EPA also followed the same methodological approach to setting new source standards that reflect 

the “level of emission control achieved in practice” (CAA section 112(d)(3)) by the best controlled 

source for each of the hazardous air pollutants at issue in this final reconsideration rule, as it did in the 

February 2012 final rule. See Sierra Club v. EPA, 479 F.3d 875, 880 (D.C. Cir. 2007) (“EPA may not 

deviate from section 7412(d)(3)’s requirement that floors reflect what the best performers actually 

achieve...”). 

Specifically, when setting MACT floors, the EPA considers variability in operations in estimating the 

degree of emission reduction that has been achieved by the best-performing sources. See Mossville 

Environmental Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 2004) (EPA may consider variability 

of emissions of the best performing source when setting the MACT floor). However, the EPA has 

considerable discretion in determining the appropriate way to account for variability. See 370 F.3d at 

1242. 

Variability in performance comes from a number of causes. Run-to-run variability is variability in each 

test, and includes uncertainties in correlation of monitoring parameters and emissions, and imprecision 

of stack test methods. Test-to-test variability results from varying efficiencies of control equipment over 

time (including variations in routine maintenance cycles), and is a longer-term variability. Additional 

sources of variable performance come from different levels of HAP in raw materials, fuels, and other 

process inputs. 
19 

The EPA assessed these types of short- and long-term variability by means of a statistical tool, an 

“Upper Prediction Limit” or “UPL” analysis which was applied to actual stack test data from the best 

performing sources. The UPL analysis is used in order to provide an appropriate margin for the 

variability in a best performing source’s operations. The UPL analysis estimates what the upper bound 

of future values will be, based upon present or past samples taken and specifically estimates a level that 

future 3-run stack averages from the best performing source would achieve 99 percent of the time. The 

UPL formula uses a pooled variance (in the s2 term) that encompasses all the data-point to data-point 

variability in the best performing source used to establish the MACT floor for each HAP. The UPL 

formula thus accounts for both short-term and long-term variability. See 76 FR 25041-48; EPA-HQOAR-2009-0234-20062. By applying this statistical tool, the EPA reasonably accounted for sources’ 

variability. See Kennecott v. EPA, 780 F.2d at 450 (upholding technology-based standards where longterm limits were derived from short-term data by application of statistical procedures). 

Next, to assure that a potential standard can be measured to a relative imprecision similar to that of EPA 

test methods reliably, the EPA compared the value resulting from the UPL analysis with the value 

equivalent to level 3 times the “Representative Detection Limit” (“RDL”) of the stack test laboratory 

emissions measurement methodology for each pollutant. 76 FR 25044. To identify the RDL, the EPA 

identifies the “method detection level” (“MDL”), which is the smallest quantity of a pollutant that can 

be accurately measured (i.e., that can be distinguished from a reading of zero). The MDL for any EPA 

test method will vary among testing contractors and the laboratories they use for any number of reasons 

(e.g., different testing equipment, sampling volumes, laboratory equipment, etc.). In order to determine 

the RDL, the EPA averages the MDLs from all individual tests from the best performing EGUs to 

provide a reasonable representation of the level at which a competent testing contractor, along with its 

laboratory, can measure emissions. See EPA-HQ-OAR-2009-0234-20062. The RDL thus accounts for 

intra- and inter-laboratory variability. Once it determined the RDL, the EPA multiplied the RDL by a 

factor of three and compared that value (3XRDL) to the value from the UPL calculation. If the 3XRDL 

calculation resulted in a value greater (i.e., less stringent, emissions-wise) than the value resulting from 

the UPL calculation, then the floor was determined to be equivalent to the 3XRDL value. 76 FR 25044. 

The EPA also noted in the final MATS rule that it was providing an additional measure of variability by 

(77 FR 9385) allowing sources to average their emissions, as measured by a continuous emissions 

monitoring system (“CEMS”) or, in the case of Hg, a sorbent trap monitoring system, over a rolling 30-

boiler operating day period.2

 77 FR 9371, 9384-85. Thus, even if a source experiences a short-term spike 

in emissions, it will not necessarily be deemed to have violated the applicable emissions limit so long as 

the 30-day rolling average remains below the limit. The 30-boiler operating day averaging period can 

thus effectively dampen short-term perturbations or upsets to the system because a EGU’s emissions 

performance, averaged over 30 days, will not be as good as its single best performance within that time 

frame. 

Therefore, the EPA’s use of the 99th percentile UPL calculation, its comparison of the results of that 

calculation to the 3XRDL value, and the 30-boiler operating day emissions average compliance option 

adequately accounts for variability in the operations of the best performing sources identified for the 

 

2

 Existing EGUs that use non-lignite coal as fuel have the option of using a longer averaging period (90-

boiler operating days) coupled with a more stringent emissions limit (1.0 lb/TBtu or 1.1 E-02 lb/GWh) 

for mercury (see 40 CFR 63.10009(a)(2)). 
20 

MACT floor analyses for each HAP. 

Best performing source 

Comment: Commenter (20293) stated that EPA is proposing to base the new source MACT floor for 

fPM on the performance of Springerville Unit 3, because that EGU has the next lowest test run after the 

Dunkirk plant. The Commenter stated that at least five other EGUs in EPA’s data set have lower average 

emission test results and lower standard deviation than Springerville Unit 3. The Commenter stated that 

the Springerville Unit 3 test results average 1.91 x10-3 lb/MW with a standard deviation of 1.48 x 10-3

lb/MMBtu and a 99th percentile UPL of 8.23 x10-2 lb/MW. The Commenter stated that Mercer Unit 2’s 

average test results were 1.23 x10-3 lb/MW with a standard deviation of 6.68 x10-4 lb/MW and 99th

percentile UPL of 6.0 x10-2 lb/MMBtu. The Commenter stated that EPA’s estimate of the performance 

of the number two performing EGU, at 6.0 x10-2 lb/MMBtu, is much higher than the 2.5 x 10-2

lb/MMBtu that the agency would calculate as the average performance of that EGU and the next higher 

emitting EGU. 

Response: The EPA used the same approach for selecting the “best performing similar source” in the 

proposed reconsideration as was used at proposal and final (see, e.g., MATS MACT Floor Memos - 

Docket ID EPA-HQ-OAR-2009-0234-9858, Docket ID EPA-HQ-OAR-2009-0234-20132). 

CAA section 112(d)(3) requires EPA to establish the new source limits based on the performance of the 

best controlled “similar source.” The statute does not define the term “similar source” and, for that 

reason, the Agency has discretion to evaluate the sources for which the Agency has data and make a 

selection as long as the Agency has a reasoned basis for it selection. In this case, the EPA acknowledges 

that there are various approaches that can be used for selecting the “best performer,” including that 

noted by Commenter. However, for consistency the EPA has used the same approach as was used at 

both proposal and final – i.e., ranking of sources based on their lowest 3-run average. The EPA decided 

upon this approach of selecting the “best performing” sources on the premise that the lowest 3-run 

average was indicative of the best the source could perform; the additional data from the sources in the 

MACT floor pool were then used to assess variability. Issues with this approach were not raised in 

comment on the proposed MATS rule, and EPA did not open that issue for reconsideration in this rule. 

However, the Commenter also questions why the Agency did not select other sources with a lower 3-run 

average. As discussed in the final MATS MACT Floor Memo (Docket ID EPA-HQ-OAR-2009-0234-

20132), there were situations for some pollutants from certain EGUs where only a single test average, 

and no individual run-level data, was available for the EGU identified as the best-controlled source. In 

these cases, no emission variability could be determined based on a single data point. Therefore, the next 

best-controlled similar source with sufficient data to account for variability was used to determine the 

new source MACT. With the exception of the Stanton data set noted elsewhere in this document, the 

EPA knows of no instance where an EGU with a lower single 3-run average meeting the above criteria 

was not considered the “best performing similar source” for the MACT floor analyses. 

Comment: Commenter (20305) questioned why the EPA has not gathered or examined PM continuous 

emission monitoring system (CEMS) data from the nearly 100 plants with PM CEMS to determine what 

emission limits might be achieved on a 30-day rolling average basis. The Commenter provided as an 

attachment PM CEMS data for two coal-fired electric generating plants reporting 30-day rolling 

averages that are lower than the proposed new plant limits. 
21 

Response: As a part of the 2010 ICR, the EPA required all coal- and oil-fired EGUs to provide all 

emission data gathered in the period January 1, 2005, to the issuance of the ICR itself. The EPA 

received no PM CEMS data through the ICR; however, the EPA reviewed the provisions of three 

publicly available consent decrees (not among the data provided by Commenter) that required the 

installation of PM CEMS on coal-fired EGUs.3,4,5 The EPA notes that though the consent decrees 

require the companies to “install, correlate, maintain, and operate PM CEMS,” the consent decrees also 

state that each company “maintains that its agreement in this Consent Decree to install, correlate, 

maintain, and operate PM CEMS shall not prevent...in any future proceedings from challenging the 

relationship between the data generated from such PM CEMS, including the averaging period for which 

such data is reported...and the results of performance tests for PM...” or “may attempt to demonstrate 

that it is infeasible to continue operating PM CEMS...” Moreover, most, if not all, of the PM CEMS data 

were unavailable for rule-making review, because installation dates in most consent decrees that 

required PM CEMS were too late to provide information in the timeframe necessary to develop the rule, 

and EPA did not undertake an additional information collection process prior to issuing the 

reconsideration notice. 

Concerning the data provided by the Commenter, the data were not certified by the EGU owner or 

operator as to being true, accurate, or complete, and, for that reason, the data were not considered as 

reliable as those data collected pursuant to the ICR. The EPA required EGU owners and operators to 

certify the data submitted in response to the MATS ICR, and the EPA determined in the MATS rule that 

it was reasonable to consider only those data certified as accurate (or data the Agency could 

independently verify through, for example, review of test reports provided with the data) in the 

rulemaking effort, given the considerable certified data the EPA collected pursuant to the ICR. In 

addition, other data suggested by the Commenter as being available also has credibility concerns, as 

most owners or operators of EGUs subject to consent decrees were not required to install the PM CEMS 

according to PS-11 requirements, and, as mentioned earlier, could challenge any data collected by PM 

CEMS if the source questioned the validity of the data. Although it is possible that some value could be 

extracted from PM CEMS operated to provide indicator or trend information, the EPA decided that a 

mere collection of data with suspect quality assurance, suspect correlation to emissions of concern, and 

lack of certification is inappropriate for consideration in establishing MACT floors. Moving forward, as 

those PM CEMS are installed to meet PS-11 and ongoing quality assurance criteria, and as compliance 

with those data are certified and reported, the EPA will be able to use those data in future rule reviews. 

 

3

 United States District Court, Eastern District of Kentucky, Central Division, Lexington. United States 

of America, Plaintiff, v. East Kentucky Power Cooperative, Inc., Defendant. Civil Action No. 04-34-

KSF. Consent Decree.

4

 United States District Court for the District of Arizona. United States of America, Plaintiff, v. Salt 

River Project Agricultural Improvement and Power District, Defendant. Civil Action No. 2:08-cv-1479-

JAT. Consent Decree.

5

 United States Environmental Protection Agency. In the matter of: Tennessee Valley Authority, 400 

West Summit Hill Drive, Knoxville, Tennessee 37902. Allen, Bull Run, Colbert, Cumberland, Gallatin, 

Johnsonville, John Sevier, Kingston, Paradise, Shawnee, and Widows Creek Fossil Plants. Federal 

Facilities Compliance Agreement Between the United States Environmental Protection Agency and the 

Tennessee Valley Authority. Docket No. CAA-04-2010-1760.
22 

Comment: Commenter (20265) stated that the EPA appears to have corrected errors by using all the 

available test results in setting the fPM standard. The Commenter pointed out that the data the EPA 

relied on in setting the re-proposed standard were obtained under well-controlled conditions. The 

Commenter concluded, however, the re-proposed emission limit could still be difficult to meet “in 

practice,” that is, under real-world operating conditions. 

Response: The EPA agrees that the fPM limit was established using all the data available for the best 

performing source and consistent with the statute. The Agency explained why its variability analysis is 

valid and accounts for different real-world operating conditions (see, e.g., RTC, Vol. 1, pp. 493 - 496). 

The EPA explained its approach to assessing variability in the proposed MATS rule, and further 

discussion is provided elsewhere in this document. 

Comment: Commenter (20305) stated that the EPA may not distinguish between sources based on the 

pollution control technology they employ. The Commenter’s concern was based on EPA elimination 

from consideration any best performing source that did not employ an advanced scrubber. The 

Commenter stated that CAA §112(d) requires that MACT standards be set to reflect the performance 

actually achieved by the best performer, however that performance is achieved, including through 

upgraded control technology. See Cement Kiln Recycling Coalition v. EPA, 255 F.3d 855, 861 (D.C. Cir. 

2001). The Commenter stated that for the same reason, the Act does not permit EPA to exclude sources 

from consideration as not “similar” because they use different control technology. The Commenter 

provided discussion about the term “similar source.” The Commenter stated that a source may be 

discarded as dis-similar only if other sources are incapable of achieving its level of control because of 

differences in their design, capacity, or emissions. The Commenter stated that 40 CFR §63.41 does not 

permit the EPA to discard sources based on the control technology that they employ, and doing so would 

violate CAA §112(d). 

Commenter (20305) stated that the EPA provided no record evidence that sources employing state-ofthe-art scrubbers are not capable of achieving the PM emission reductions achieved by the best 

performing sources without such scrubbers. The Commenter stated that this rule does not present a 

situation where the Act could impose incompatible obligations. The Commenter stated that assuming 

arguendo that the Act would permit EPA to exclude best performers to accommodate other sources 

using control technology that both 1) is required for compliance with another CAA requirement and 2) 

renders those sources incapable of achieving of the level of control of the best performer and the 

Commenter asserts that the Act does not permit EPA to do so where, as here, the record does not show, 

and EPA does not claim, that required controlled technology makes sources incapable of achieving of 

the level of control of the best performer. The Commenter observed that a contrary interpretation would 

violate CAA §112(d)(2) and §112(d)(3), because it would render the floor setting process under (d)(3), 

which does not even permit consideration of cost, even more accommodating of cost than section (d)(2), 

which does, but only for the purpose of determining “the maximum degree of reduction in 

emissions...that the Administrator...determines is achievable[.]” 

Commenter (20305) stated that discarding sources without advanced scrubbers because some state-ofthe-art scrubbers can add PM to the flue stream is arbitrary. The Commenter stated that the EPA does 

not provide an explanation why there is sufficient reason to eliminate all sources without advanced 

scrubbers from consideration as the best performer for PM. The Commenter stated that it is arbitrary for 

EPA to discard data from best performers without determining whether sources with advanced scrubbers 
23 

are achieving an emission level consistent with a standard based on the emissions of the best performer 

without an advanced scrubber. 

Commenter (20305) stated that at least two scrubbed EGUs are achieving lower fPM emissions than the 

EGU selected as the “best performer” in EPA’s reconsidered proposal, and the Commenter provided 

stack test from those EGUs as attachments. 

Commenter (20293) stated that in regards to fPM for new oil-, coal-, and low rank virgin coal-fired 

EGUs, the EPA is proposing in its reconsideration to eliminate two plants, the Dunkirk and Martin 

Drake plants, as the best-performing EGUs on the basis that these plants do not employ a FGD for SO2

control. The Commenter stated that this would only be relevant if FGDs consistently increased fPM 

emissions, which Commenter understands not to be the case. The Commenter stated that in many 

applications, the FGD is considered part of the PM control system as the wet spray captures a portion of 

the PM present in the exhaust stream. The Commenter stated that the Martin Drake plant does not have 

any SO2 control system and so, it is at least possible that the PM loading to the control device may be 

somewhat lower than if an FGD were in place. The Commenter stated that the Dunkirk plant employs 

low sulfur coal and dry spray and has the capability to use activated carbon injection (ACI) enabling it to 

meet its Hg limit of 0.6 lb/TBtu in 2015. The Commenter stated that each of these technologies adds to 

the load that the PM controls must be capable of addressing. The Commenter stated that the PM control 

system at this facility is a fabric filter system installed in 2009. The Commenter stated that there is 

nothing in the design of this system that would warrant disqualifying it as a best-performing EGU. 

Response: The EPA did not distinguish between sources based on the pollution control technology they 

employ. However, as noted in the final rule, the EPA believes it may consider both the types of EGUs 

likely to be built in the future and the regulations those EGUs would need to comply with in the 

selection of an EGU as the “best performing similar source” (see, e.g., 77 FR 9390; RTC, Vol. 1, pp. 

441 - 446, 446 - 448, 590 - 593, 622, 623 - 624). That is, the EPA determined it appropriate to select as 

the basis for the new source MACT limits an EGU that would be configured to comply with the NSPS 

(i.e., employ a full suite of controls). The highest performing EGU meeting these criteria was selected. 

Further, as discussed in the final MATS MACT Floor Memo (Docket ID EPA-HQ-OAR-2009-0234-

20132), there were situations for some pollutants where only a single test average and no individual runlevel data were available for the EGU identified as the best-controlled source. In these cases, no 

emission variability could be determined based on a single data point. Therefore, the next bestcontrolled similar source with sufficient data to account for variability was used to determine the new 

source MACT. With the exception of the Stanton data set noted elsewhere in this document, the EPA 

believes that all the other new source MACT floor analyses were based on the EGU with the lowest 

single 3-run average. The EPA believes that Commenter’s allegations that the EPA discarded sources 

without advanced scrubbers is misplaced as we did not eliminate from “consideration any best 

performing source” based on the fact that it did not employ an advanced scrubber. The data were sorted 

in the same manner as was done at MATS proposal and final and then the above criteria were applied. 

The Commenters have provided no additional information or rationale that would cause the EPA to 

change its approach. 

The data Commenter provided related to “at least two scrubbed EGUs” that are “achieving lower fPM 

emissions” than the EGU selected as the “best performer” was insufficient for the EPA to conduct an 

analysis to confirm that allegation. The Commenter provided no process data for the two EGUs for the 
24 

emission tests by which the input-based data (lb/MMBtu) could be converted to the output-based format 

(lb/GWh) of the new source MATS limits. 

The Dunkirk EGU may, as Commenter notes, have the ability to use dry spray injection and ACI but the 

information available to the EPA indicates that neither process was operational during the emission tests 

that were used for the 2010 ICR submittal and, thus, it could not be confirmed that this EGU was 

operating with the requisite full suite of controls. 

2.1.2 Hydrogen Chloride (1.0E-02 lb/MWh) 

Monitoring 

Comment: Commenter (20261) stated that they are currently evaluating continuous HCl monitoring 

technologies for their capabilities at or below the proposed emission limits for new coal plants. The 

Commenter described one of the most promising technologies, the in situ tunable diode laser (TDL). 

The Commenter stated that in a laboratory study conducted in 2011, detection limits of 1 ppm per meter 

of absorption path length were obtained, indicating that a cross-stack in situ TDL would likely have a 

detection level of 0.1 ppm (approximately 0.0002 lb/MMBtu or 0.002 lb/MWh), making the proposed 

limit for new coal EGUs of 0.01 lb/MWh measurable by these monitors. The Commenter listed similar 

studies of other technologies such as Fourier transform infrared (FTIR), non-dispersive infrared (NDIR), 

and Cavity Ring-Down Spectroscopy (CRDS) that are underway. The Commenter concludes that there 

are insufficient data to suggest that continuous HCl monitors are either capable or reliable enough for 

compliance measurements on coal-fired applications at the proposed new source limits. The Commenter 

noted that until EPA finalizes PS-18, it is unclear which technologies are viable candidates for 

application to coal-fired power plants. 

Response: The EPA appreciates the Commenter’s participation in HCl monitoring technology 

evaluation and shares the Commenter’s agreement that HCl CEMS based on one or more technology 

approaches will be able to measure emissions from coal-fired EGUs. Much ground has been covered 

since 2011, and while PS-18, the performance specification for HCl CEMS, remains on track to be 

promulgated well in advance of the compliance date for existing EGUs, other compliance options such 

as use of SO2 CEMS for EGUs equipped with flue gas desulfurization or quarterly HCl testing are viable 

now. Owners or operators who are concerned about the availability or reliability of HCl CEMS should 

choose from one of these other compliance approaches. In addition, if an owner or operator determines 

that a technology different from the promulgated CEMS performance specification PS-15 seems more 

appropriate for their HCl monitoring then application for an alternative HCl monitoring approach can be 

made under the general provisions for alternative test methods (see 40 CFR 63.7(f)). 

Calculation of Standards 

Comment: Commenter (20293) stated that EPA identified the Logan Generating plant as the bestperforming new EGU for HCl emissions on the basis of the single lowest test. The Commenter stated 

that the average tested emission rate at this EGU was 1.87 x 10-4 lb/MMBtu and the standard deviation 

of the test results is 1.4 x 10-4 lb/MMBtu. The Commenter stated that the Walter Scott Energy Center 

EGU, among others, showed better and less variable performance – the average tested emission rate for 

this EGU was 5.69 x 10-5 lb/MMBtu (5.14 x 10-4 lb/MWh) and the standard deviation of the test results 
25 

is 1.79 x 10-5 lb/MMBtu (1.6 x 10-4 lb/MWh). The Commenter stated that application of EPA’s 99th

percentile UPL to the Walter Scott Energy Center test results yields a MACT floor of 5.8 x 10-3

lb/MWh, substantially less than the proposed “beyond the floor” limit of 1.0 x 10-2 lb/MWh. 

Response: This issue is outside the scope of this rulemaking. The EPA specifically identified the issues 

being proposed for reconsideration, including use of all of the data when establishing the new source 

limits. The approach used in selecting the “best performing similar source” was not among the issues for 

which reconsideration was granted. As noted elsewhere in this document, the EPA used the same 

approach for selecting the “best performing similar source” in the proposed reconsideration as was used 

at proposal and final. 

CAA section 112(d)(3) requires EPA to establish the new source limits based on the performance of the 

best controlled “similar source.” The statute does not define the term “similar source” and, for that 

reason, the Agency has discretion to evaluate the sources for which the Agency has data and make a 

selection as long as the Agency has a reasoned basis for it selection. In this case, the EPA acknowledges 

that there are various approaches that can be used for selecting the “best performer,” including that 

noted by Commenter. However, the EPA determined its approach is reasonable and consistent with the 

statute and has used the same approach as was used at both proposal and final – i.e., ranking of sources 

based on their lowest 3-run average. The EPA decided upon this approach of selecting the “best 

performing” sources on the premise that the lowest 3-run average was indicative of the best the source 

could perform; the additional data from the sources in the MACT floor pool were then used to assess 

variability. Issues with this approach were not raised in comment on the proposed MATS rule. In 

addition, the EPA has not been able to recreate or identify in the MACT floor spreadsheets the emission 

rates cited by the Commenter. Those available to the EPA and used in the MACT floor analyses are 

identified in the MACT floor spreadsheet (see Docket ID EPA-HQ-OAR-2009-0234-20220, attachment 

“UPL_Coal_HCl_Logan_111612”).The Commenter has not provided sufficient information to resolve 

the differences. 

Comment: Commenter (20265) stated that the EPA appears to have corrected errors by using all the 

available test results in setting the HCl standard. The Commenter said, however, it is still important to 

point out that the data EPA relied on in setting the re-proposed standard was obtained under wellcontrolled conditions. The Commenter concluded, therefore, the re-proposed emission limit could still 

be difficult to meet “in practice,” that is, under real-world operating conditions. 

Response: The EPA appreciates the Commenter’s overall support. The issue of the use of short-term 

emission test data to establish 30-day rolling average emission limits was addressed in the final RTC 

(see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 500, 549 - 551) and is outside the scope of this 

rulemaking. This issue was not one of the issues being reconsidered and the EPA did not solicit 

comment in the reconsideration proposal regarding the use of short-term data. In addition, the Agency 

also explained why its variability analysis is valid and accounts for different real-world operating 

conditions (see, e.g., RTC, Vol. 1, pp. 493 - 496). The EPA explained its approach to assessing 

variability in the proposed MATS rule, and further discussion is provided elsewhere in this document. 

2.1.3 Sulfur dioxide (1.0 lb/MWh) 

Calculation of standards 
26 

Comment: Commenter (20246) stated the EPA needs to more fully account for operating and fuel 

variability in setting achievable new source emission limitations. The Commenter said, in particular, the 

EPA is proposing a sulfur dioxide (SO2) emission limit for controlling acid gases based on the emission 

rate achieved by a single plant demonstrating 98 percent control efficiency during a testing sequence. 

The Commenter stated, in applying 98 percent control, the EPA should account for all possible fuel and 

operating variability that may occur across all types of new coal-fired plants. 

Response: The EPA has accounted for variability to the extent the EPA determined was reasonable and 

sufficient consistent with the requirements of CAA §112. The incorporation of variability was addressed 

in the final rule (see, e.g., RTC, Vol. 1, pp. 457 - 463). The Commenter has provided no data or other 

information to support its contention that the variability analysis is incorrect and the EPA maintains that 

the approach to accounting for variability is valid for the reasons set forth in MATS record. The EPA 

explained its approach to assessing variability in the proposed MATS rule, and further discussion is 

provided elsewhere in this document. 

Comment: Commenter (20296) endorsed the EPA’s proposed revision of the SO2 limit because the asadopted MATS rule new source SO2 limit was based on a facility that was only 25 MW in capacity. 

Response: This comment requires no response. 

Available facility data 

Comment: Commenter (20305) stated that EPA erred in not using the available data it has for some of 

the best performing EGUs in setting the SO2 limit. The Commenter discussed as an example, the Stanton 

EGU. 

Response: Commenter is correct in that the EPA inadvertently overlooked the Stanton Unit 10 data. In 

this final action, the EPA used the Stanton data to calculate the MACT floor using the same statistical 

analyses used in the proposed rule (i.e., 99 percent upper predictive limit (UPL)), and the resulting 

MACT floor emission limit is 1.3 pounds per megawatt-hour (lb/MWh). Because this limit is less 

stringent than the new source performance standard (NSPS) finalized in the Utility NSPS (77 FR 9451; 

February 16, 2012), the EPA is finalizing a beyond-the-floor (BTF) MACT standard of 1.0 lb/MWh, 

which is the same level required by the CAA section 111 NSPS for these same sources.6

 See 40 CFR 

60.43Da(l)(1)(i). Cost is a required consideration in establishing CAA section 111 rules and in going 

BTF in establishing CAA section 112 rules. We evaluated cost in assessing whether to go BTF for this 

standard and concluded that it was appropriate to go BTF to a level of 1.0 lb/MWh. Moreover, the NSPS 

limit (also 1.0 lb/MWh) is in place and coal-fired EGUs are required to comply with that limit. As such, 

there is no additional cost to these sources.7 Furthermore, we have not identified any non-air quality 

health or environmental impacts or energy requirements associated with the final standard set at this 

 

6

 The CAA section 111 standard is based on the performance of EGUs with the best performing SO2

controls, a reasonable incremental cost effectiveness of less than $1,000 per ton of SO2 controlled, and 

controls that result in minimal secondary environmental and energy impacts. 

7

 The final Utility NSPS limit was not challenged and coal-fired EGUs constructed after May 3, 2011, 

must meet that limit. 
27 

level. In addition, in support of the proposed reconsideration rule, we evaluated an emissions level more 

stringent than 1.0 lb/MWh and found that level to not be cost effective.8 For these reasons, we are 

finalizing 1.0 lb/MWh as the new source MATS NESHAP limit.

Comment: Commenter (20293) stated that EPA set the new source SO2 limits based on the performance 

of an EGU, but received a comment that this EGU is rated at 25 MW, and the regulations only apply to 

EGUs whose capacity is greater than 25 MW. The Commenter stated that EPA then chose the Sandow 5 

Unit as its best performer, but that unit’s test results are highly variable and the new source performance 

limit is well above permitted limits for several existing EGUs and has been met by 40 percent of existing 

EGUs. The Commenter stated that there appear to be at least six EGUs that have demonstrated 

substantially better consistent performance than the Sandow Unit selected by EPA. The Commenter 

stated that these are the Gallagher, Coffeen, Stanton, AES Puerto Rico Units 1 and 2, Elm Road, and 

two Rio Bravo Poso units. The Commenter stated that the 99th percentile UPL of one Rio Bravo Unit is 

0.35 lb/MWh, whereas the other Rio Bravo unit’s 99th percentile UPL is 0.38 lb/MWh. The Commenter 

noted that EPA states that it does not have run-level data for several of these EGUs, but this information 

is presumably available to the agency. The Commenter noted that EPA Region 2 was the permitting 

agency for the AES Puerto Rico facility and presumably has the initial NSPS performance testing, 

additional ongoing CEM data, and other emissions information needed to determine the performance of 

this unit. 

 

Commenter (20293) stated that the two AES Puerto Rico EGUs are subject to an SO2 emission limit of 

0.022 lb/MMBtu (3-hour) limit, approximately equal to a 0.2 lb/MWh limit, whereas the Virginia City 

Hybrid Energy Center is subject to a 30-day limit at the same level. The Commenter stated that 

“individual test information” is at least as “available” as information obtained under EPA’s CAA §114 

information request and clearly “available” to the agency where (1) the agency is the permitting 

authority, (2) the permitting authority acts under a delegation from EPA, or (3) EPA has an interagency 

cooperative agreement. The Commenter stated that where individual run data are not available, the EPA 

must consider the performance of these EGUs in setting a new source MACT floor. 

 

The Commenter stated that the hourly CEM data in the record for the AES Puerto Rico EGUs show a 

30-day average SO2 emission rate of 0.011 and 0.012 lb/MMBtu and a standard deviation of 0.009 and 

0.007 lb/MMBtu. The Commenter stated that there are far more data available documenting the 

performance of these units than any other units in EPA’s data set and these units have complied with an 

SO2 limit for over 10 years that is one-fifth the level proposed by the EPA on reconsideration. 

Commenter (20305) stated that the proposed SO2 limit does not reflect the performance of the best 

controlled similar source. The Commenter stated that the EPA’s own data identifies six better 

performing EGUs that have achieved SO2 emission levels significantly below those achieved by the 

Sandow Unit 5 that EPA selected as the best performer. The Commenter stated that because CAA 

§112(d)(3) unambiguously requires floors for new EGUs to reflect the emission level achieved by the 

single best performing unit, the agency’s decision to exclude the top six EGUs from its floor analysis 

and base floors on the seventh best performing unit is unlawful. See Northeast Maryland, 358 F.3d at 

 

8

 See Docket ID EPA-HQ-OAR-2009-0234-20221 and National Emission Standards for Hazardous Air 

Pollutants (NESHAP) Beyond the Maximum Achievable Control Technology (MACT) Floor (‘Beyondthe-Floor’) Analysis for Revised Emission Standards for New Source Coal-and Oil-fired Electric Utility 

Steam Generating Units also in the rulemaking docket. 
28 

954-955; Sierra Club, 479 F.3d at 880. 

 

Commenter (20305) stated that the EPA’s rationale for excluding the Elm Road Generating Station is 

unlawful and arbitrary, because floors must reflect the emission level that the relevant best sources 

actually “achieved” not the levels EPA thinks are “achievable.” See, e.g., Sierra Club, 479 F.3d at 880. 

The Commenter stated that even if this approach was relevant to setting floors, which the Commenter 

disagreed with, the EPA has frequently used data for EGUs for which it has only one test to set floors 

and the agency uses its UPL analysis to account for variability in such situations. The Commenter stated 

that the EPA does not explain why it cannot use the data for the Elm Road unit even though it has not 

hesitated to base other floors on the performance of EGUs for which it has only one emissions test. The 

Commenter stated that by treating similar situations differently without explanation, the EPA acts 

arbitrarily. 

 

Commenter (20293) stated that in determining the new source MACT floor for SO2, the EPA rejected 

low-emitting EGUs (LEEs) at Gallagher and Coffeen plants, as well as CEM data for AES Puerto Rico, 

because it did not have run-level data for those plants. The Commenter stated that the run-level data for 

Springerville 3 yields a UPL of 0.009 lb/MWh, but EPA decided to include additional testing, where 

run-level data were not available in its calculation. The Commenter stated that this resulted in an order 

of magnitude increase in the calculated MACT floor. The Commenter stated that if one includes test 

results where run-level data are not available, this unit is not the best-performing unit. The Commenter 

stated that it appears that the Mercer 1 and 2 units are better performers. The Commenter stated that the 

EPA should include in its analysis all EGUs where reliable emissions data are available and determine 

the variability factor using a process that employs a sufficient number of data points. 

 

Commenter (20305) stated that the EPA’s exclusion of five out of the top six performing EGUs based 

on its claim to lack “run-level” data is also both unlawful and arbitrary. The Commenter provided five 

reasons: 

 

(1) CAA §112(d)(3) requires the EPA to base floors on the best performing unit, not the best performing 

unit for which EPA happens to have run-level data; 

 

(2) The EPA’s desire to use run-level data for variability analysis does not override the agency’s 

obligation to assure that its standards for new EGUs reflect the emission level actually achieved by the 

single best performer. The Commenter stated that CAA §112 requires floors to reflect the performance 

of the best performing unit, not the best performing unit for which the EPA can perform a UPL analysis. 

 

(3) The EPA does not provide any explanation for excluding the top performing EGUs from its analysis 

just because it lacks run-level data for them. CAA §112(d)(3) unambiguously requires floors for new 

EGUs to reflect the emission level achieved by the single best performing unit. The EPA cannot avoid 

this statutory duty just because it wishes to use a particular method to account for variability, UPL 

analysis, in setting floors. 

 

(4) The EPA has an obligation to make reasonable efforts to obtain emissions data for EGUs that are, by 

the agency’s own estimation, the best performing EGUs. If the EPA does not have the run-level data for 

the best performers and believes that run-level data is necessary, it is the EPA’s responsibility to obtain 

the run-level data for those EGUs. 
29 

 

(5) The EPA’s failure to provide a rational basis for not obtaining and considering run-level data from 

the six best performing EGUs identified by the EPA in setting the SO2 limit for new sources is arbitrary 

and capricious. 

 

Response: As noted elsewhere in this document, the EPA used the same approach for selecting the “best 

performing similar source” in the proposed reconsideration as was used at proposal and final. That is, 

the EPA selected the MACT floor pool of EGUs based on their lowest emission test result, ranking the 

EGUs on this lowest emission test result (the lowest emitting source becoming the basis for the new 

source limits provided the stated criteria were met), and then incorporated any other data from these 

floor EGUs (or single EGU in the case of the new source limits) into the variability analyses. This 

approach included rejection, for the new source analysis, of any EGU selected as the “best performer” 

where there was only a single data point that did not include run-level data and that did not have 

additional data sets for inclusion in the analyses (“For the new source MACT floors, the best-controlled 

source was identified for which there were individual source test run data in the ICR data set.”[1]). 

Variability analyses cannot be conducted on a single data point; therefore, if no individual run data were 

available, no variability analysis could be conducted on an EGU. The EPA used data that were provided 

to it by the companies through the 2010 ICR and data submitted during the comment periods if the data 

were certified or the Agency could independently assess the validity of the data (e.g., the test report was 

submitted with the data). 

The EPA also does not agree that the approach for selecting the best performing source suggested by the 

Commenter is mandated by the statute and the EPA maintains that its approach to selecting the best 

performing similar source is reasonable. CAA section 112(d)(3) requires the EPA to establish the new 

source limits based on the performance of the best controlled “similar source.” The statute does not 

define the term “similar source” and, for that reason, the Agency has discretion to evaluate the sources 

for which the Agency has data and make a selection as long as the Agency has a reasoned basis for it 

selection. In this case, the EPA acknowledges that there are various approaches that can be used for 

selecting the “best performer,” including that noted by Commenter. However, for consistency the EPA 

has used the same approach as was used at both proposal and final – i.e., ranking of sources based on 

their lowest 3-run average. The EPA decided upon this approach of selecting the “best performing” 

sources on the premise that the lowest 3-run average was indicative of the best the source could perform; 

the additional data from the best performing source in the MACT floor for each standard was then used 

to assess variability in the new source limit analyses. Issues with this approach were not raised in 

comments on the May 2011 proposed MATS rule. However, the Commenter questions why the Agency 

did not select other sources with a lower 3-run average. As discussed in the final MATS MACT Floor 

Memo (Docket ID EPA-HQ-OAR-2009-0234-20132), there were situations for some pollutants where 

only a single test average and no individual run-level data were available for the EGU identified as the 

best-controlled source (e.g., R. Gallagher Unit 2, Coffeen Unit 1). In these cases, as noted above, no 

emission variability could be determined based on a single data point. Therefore, the next bestcontrolled similar source with sufficient data to account for variability was used to determine the new 

source MACT. With the exception of the Stanton data set noted elsewhere in this document, the EPA 

knows of no instance where an EGU with a lower single 3-run average and meeting the above criteria 

was not considered the “best performing similar source” for the MACT floor analyses. 

 

As a part of the 2010 ICR, the EPA required all coal- and oil-fired EGUs to provide all emission data 
30 

gathered in the period January 1, 2005, to the issuance of the ICR itself. The data noted by Commenter 

were not submitted by the company and, thus, were not made available to the EPA. Furthermore, EPA 

does not agree with the Commenter’s unsupported assertion that EPA has an affirmative duty to seek 

additional data prior to establishing the MACT standards, and, in this case, EPA had a large amount of 

data from the Utility ICR and was under considerable time constraints such that additional time 

collecting data was not possible. Commenters have noted that the proposed limits are less stringent than 

the permitted limits for “several existing EGUs.” However, Commenters did not provide the permits. In 

addition, for one of the EGUs cited by Commenter (20293) (i.e., AES Puerto Rico) the limit is for a 3-

hour period rather than for a 30-day period and, thus, is not directly comparable. Commenter does not 

provide any process information with which the input-based limit (0.022 lb/MMBtu) can be converted to 

the requisite output basis for the new source standards (i.e., lb/MWh) and the EPA does not find 

Commenter’s statement that this input-based permit limit is “approximately equal to a 0.2 lb/MWh 

limit” convincing without supporting information. In addition, the two AES Puerto Rico EGUs fall at 

numbers 4 and 6 on the list of “best performers.” We have acknowledged elsewhere in this document 

that we are using Stanton Unit 10 as the basis for the new source limits; Stanton Unit 10 is number 3 on 

the list of “best performers” and, thus, takes precedence over the AES Puerto Rico EGUs in our 

analysis.[2] The other EGU cited (Virginia City Hybrid Energy Center) did not begin commercial 

operation until July 2012, and, thus, its data were not available to the EPA. 

The EPA notes that it may use permit information only if the permit information allows EPA to make a 

reasonable estimate of emissions. See Northeast Maryland Waste Disposal Authority v. EPA, 358 F.3d 

936, 953 (D.C. Cir. 2004). Moreover, in setting limits for EGUs, the only instance in which the EPA 

used permit data in lieu of actual measured data was when insufficient measured data existed. In the case 

of IGCC’s, the EPA only had data from IGCC’s that were built in the 1990’s. IGCC’s are becoming a 

much more common generation technology and advancements have been made in IGCC’s since the 

1990’s. One IGCC is scheduled to commence commercial construction imminently, another has almost 

completed construction and two others are in advanced stages of product development. Because this 

technology is becoming more common in the power sector and the EPA had no data that it believed 

were representative of what current state of the art IGCC technology could do, the EPA determined that 

it was appropriate in that limited case to use permit data. For non-IGCC coal burning technologies 

(including pulverized coal and fluidized bed combustors), the EPA had more data and data that the EPA 

believes are representative of what sources are achieving in practice. For this reason, the EPA believes it 

reasonably relied on the large amounts of emissions data collected to support this rulemaking effort in 

setting the new source standards for non-IGCC coal-fired EGUs. 

 

The data available to the EPA on Elm Road Unit 1 places it at number 5 on the list of “best performers.” 

As noted above, Stanton Unit 10 is number 3 on the list of “best performers” and, thus, takes precedence 

over Elm Road Unit 1 in our analysis. 

Comment: Commenter (20305) noted that the EPA has extensive continuously monitored data for SO2

in the Clean Air Markets Data-base (CAMD). The Commenter stated that with that data, the EPA cannot 

discard potential best-performers based on lack of data. The Commenter discussed several facilities that 

have emissions below the proposed standard, and attached emissions information for those facilities. 

The Commenter stated that the EPA does not need to limit analysis to the stack tests provided by 

industry. The Commenter concluded that in light of the availability of the CAMD data, the EPA 

proposed approach using a statistical sample and based on a constrained set of data is neither necessary 
31 

nor legally defensible. 

Response: The EPA opted to use the SO2 data obtained through the 2010 ICR rather than data gathered 

through other means (including data available through CAMD) so as to be better able to correlate such 

data with the concurrently acquired HCl data (the EPA has discussed the Stanton data elsewhere in this 

document). In developing the 2010 ICR, the EPA required EGUs to conduct concurrent HCl and SO2

testing so as to be better able to correlate the data acquired. Such a comparison would not be possible 

between HCl data acquired through the 2010 ICR and SO2 data acquired through the (e.g.) Acid Rain 

program. Therefore, the EPA opted not to use the Acid Rain database in its analyses. 

SO2 as a surrogate for HCl 

Comment: Commenter (20293) provided a graphic of the top 100 SO2 emissions rates for coal- and low 

rank virgin coal-fired EGU’s. The Commenter stated that this figure demonstrates the wide disparity 

between the emission rate achieved by the top 10 sources and the proposed rate on reconsideration. The 

Commenter stated that at the SO2 emission levels that are now being proposed, it is not clear that SO2 is 

a reliable surrogate for MACT level of control of hazardous acid gas emissions. The Commenter stated 

that EPA should provide an analysis documenting the relationship between the emission levels of the 

different pollutants at the proposed level of SO2 control. 

Commenter (20300) stated that the EPA has not demonstrated that SO2 is an adequate surrogate for 

inorganic acid gas HAP under the stringent standards set forth in Sierra Club v. EPA, 353 F.3d 976, 982-

85 (D.C. Cir. 2004). The Commenter referred to their comments for the proposed MATS rule submitted 

in 2011 for discussion of the topic. The Commenter stated that SO2 emissions from EGUs are poorly 

correlated with HCl, and are not correlated at all with hydrogen fluoride (HF) or cyanide (HCN); the 

precursors for acid gas emissions are not found in uniform proportions to sulfur in the coal used to fuel 

EGUs; and, as shown in the data EPA presented in the proposed MATS, FGD systems control emissions 

of HCl and HF at wildly inconsistent rates. The Commenter further noted that because the reaction 

chemistry that FGD systems employ for SO2 varies from that of HCl and other acid gases, a FGD 

system that is optimized for SO2 removal is unlikely to achieve maximum removal of acid gas HAP. 

Moreover, the Commenter stated, FGD systems are but one possible method for controlling acid gas 

HAP – other methods include the use of low-chlorine coal, chloride prescrubbers, and the use of 

reagents specifically targeted at neutralizing HCN. 

Commenter (20300) stated that the best-controlled EGU for SO2 (Sandow) is only the eighth-best 

controlled for HCl – and emits HCl at a rate almost twice that of the best-controlled EGU for HCl. The 

Commenter recommended that the EPA reconsider the use of SO2 as a surrogate for acid gas HAP. 

Response: This issue is outside the scope of this rulemaking. The issue of the use of SO2 as a surrogate 

for acid gas HAP was addressed in the final RTC (see, e.g., Vol. 1, pp. 715, 717, 718, 726 - 727, 758 - 

761). The EPA did not solicit comment in the reconsideration proposal regarding the use of SO2 as a 

surrogate. 

In addition, the Commenter maintains that the EPA must comply with a specific three-part test for 

surrogacy that the D.C. Circuit applied when evaluating whether PM was a valid surrogate for non-Hg 

metal HAP in another CAA section 112 standard. See Sierra Club v. EPA, 353 F.3d 976, 984 (D.C. Cir 
32 

2004) (“this court established a three-part analysis for determining whether the use of PM as a surrogate 

for HAP is reasonable...”). However, the EPA maintains that the only standard from that case that 

expressly applies to the EPA’s establishment of a surrogate standard for acid gas HAP is that the 

surrogate be reasonable. We maintain that HCl and SO2 are reasonable surrogates for all acid gas HAP 

when the EGU is using a flue gas desulfurization technology to comply with the surrogate standard. 

The EPA maintains in the MATS rule that the control of the surrogate (in this case HCl or SO2) also 

indiscriminately captures the air toxic acid gases along with the surrogate (see, e.g., 76 FR 25014, 

25023, 25039, 25040). The EPA explained that, based on the known chemical and physical properties of 

the compounds, typical flue gas desulfurization systems (e.g., wet scrubbers, dry scrubbers, dry alkaline 

sorbent injection) will effectively reduce the emissions of the acidic gas HAP. The emissions of all of 

the acid gas HAP will be reduced due to their solubility or their acidity (or both) (see, e.g., 76 FR 25014, 

25017; RTC, Vol. 1, p. 717, 758 – 761). 

2.1.4 Lead (3.0E-02 lb/GWh) 

Comment: Commenter (20293) stated that in determining the new source lead (Pb) limit for coal- or 

low rank virgin coal-fired EGUs, the EPA had selected the Weston EGU as the best-performing EGU. 

The Commenter stated that on reconsideration, the EPA has included a test result that is 60 times greater 

than the test that it used to identify this EGU as a best-performing EGU. The Commenter stated that it 

appears that the Dallman EGU is a far better performer in that data set because its average emission rate 

is close to that of the Weston EGU, but the test-to-test variability is far less. The Commenter stated that 

these data also show that a number of other sources have apparently identified highly differing test 

results. The Commenter stated that Figure 4 (refer to Docket ID EPA-HQ-OAR-2009-0234-20293-A2) 

sets out the lowest emission rate for each of the EGUs in EPA’s data set and also shows the additional 

test results for the EGU. The Commenter stated that the Logan Unit, is the #11 source in this figure. The 

Commenter stated that the 75-fold increase in fPM emissions during a 2005 stack test was accompanied 

by a 238-fold increase in Pb emissions. The Commenter stated that these results are of concern as they 

may suggest that (1) even EPA’s proposed reconsidered limit cannot be consistently met by wellcontrolled EGUs or (2) annual Reference Method testing will not provide a reasonable assurance of 

compliance with (any) limit. The Commenter stated that these results may reflect the fact that permitted 

PM control limits often provide a substantial compliance margin for such EGUs and the higher emission 

levels may not reflect the full performance of the EGU. The Commenter recommended that EPA 

examine this issue in more detail before acting on its proposed reconsideration limits. 

Response: As noted elsewhere in this document, the EPA used the same approach for selecting the “best 

performing similar source” in the proposed reconsideration as was used at proposal and final. That is, 

the EPA selected the MACT floor pool of EGUs based on their lowest emission test result and then 

incorporated any other data from these floor EGUs into the variability analyses. The EPA used the data 

provided by the companies through the 2010 ICR in conducting the analyses. The EPA notes that the 

individual HAP metal limits are an alternative compliance option and we do not expect many EGUs to 

use that approach to demonstrate compliance given that the costs of measuring individual metal will far 

exceed the other compliance options (e.g., total HAP metals, fPM). 

The EPA acknowledges that there are various approaches that can be used for selecting the “best 

performer,” including that noted by Commenter. However, in part for consistency with the initial MATS 
33 

rulemaking, the EPA has used the same approach as was used at both proposal and final – i.e., ranking 

of sources based on their lowest 3-run average. The EPA decided upon this approach of selecting the 

“best performing” sources on the premise that the lowest 3-run average was indicative of the best the 

source could perform; the additional data from the sources in the MACT floor pool were then used to 

assess variability. Issues with this approach were not raised in comment on the proposed MATS rule 

even though the issue could have been raised. 

Comment: Commenter (20293) stated that EPA’s proposed new source MACT limit for Pb for coaland low rank virgin coal-fired EGUs (3.0 x 10-2 lb/GWh) is higher than the adopted existing source limit 

for this category (2.0 x 10-2 lb/GWh) and remains unchanged by this proposal. The Commenter stated 

that in the past, the EPA has used the agency’s “beyond the floor authority” to establish a new source 

limit that is at least as stringent as the limit applicable to existing sources, but does not propose to do so 

in this rulemaking. 

Commenter (20298) stated that the Pb limit for coal-fired EGU and the filterable PM limit for liquid oil 

(continental)-fired EGU are too lenient and less stringent that the applicable limits on the existing EGUs. 

The Commenter stated that the problem is that EPA uses the variability in performance of each 

individual EGU where sufficient data do not exist. According to the Commenter, the EPA’s approach 

estimates the variability of the EGU that is a function of the limited number of tests rather than the 

variability that one would expect from the combustion technology and fuel, which leads to erroneous 

results such as the calculation of new source MACT floor that are higher than the existing source MACT 

floor. The Commenter recommended that EPA develop a variability factor based on the variability in 

performance of a larger data set comprised of EGUs employing similar designs. Such an evaluation 

would be based on all relevant information, including engineering information, continuous emissions 

monitoring data and the variability in performance of EGUs of similar design. 

Response: The EPA has adjusted the limit proposed in the reconsideration notice to the more stringent 

level of the existing-source limit in this final rule for the reasons set forth in the record (see, e.g., final 

MATS MACT Floor Memo, Docket ID EPA-HQ-OAR-2009-0234-20132 – “Additionally, similar to 

the approach used in the HMIWI rulemaking, if the emission limit for new sources was less stringent 

than the emission limit for existing sources in the same subcategory, the EPA decided to use existingsource limits for new sources.”). Although CAA section 112(d)(3) allows existing source MACT floor 

limits to be less stringent than new source limits, the EPA interprets this provision as precluding new 

source limits from being less stringent than existing source limits. See CAA section 112(d)(3). Thus, the 

EPA is finalizing new source limits that are equivalent to the final existing-source limits. The new 

source limit for Pb from coal-fired EGUs has been corrected to the existing-source limit of 2.0 x 10-2

lb/GWh. 

2.1.5 Selenium (5.0E-02 lb/GWh) 

Comment: Commenter (20293) stated that EPA had selected the Logan Generating Station as its bestperforming EGU for selenium on the basis of the lowest single run even though other EGUs in its data 

set had lower average emissions. The Commenter stated that EPA was then informed of an earlier test 

result reporting an emission rate 75 times higher than the testing conducted in response to the agency’s 

survey. The Commenter stated that such variations in performance are not expected in properly 

functioning PM control systems, and so, the EPA should contact the source and the appropriate 
34 

permitting authority to determine the circumstances surrounding this test. The Commenter stated that if 

the earlier test result is representative of the current controls and operations at the Logan Generating 

Station, it would be appropriate for EPA to consider this data and determine that the emissions 

performance of this EGU is not as good as it had previously appeared. The Commenter stated that this 

should also be accompanied by a determination that this EGU is not the best-performing EGU in the set. 

Commenter (20293) stated that the average emission test result for this EGU now ranks 70th out of 

approximately 200 test results in EPA’s data set. The Commenter stated that because the newly 

considered test result is so much greater than the initial result considered, the EPA’s 99th percentile UPL 

calculation generates a result that is exceedingly high – substantially higher than the top 100 test results 

in the data set. The Commenter stated that a single test run is not the appropriate measure of the bestperforming EGU. The Commenter stated that where EPA receives credible information that a particular 

EGU is not the best-performing EGU, the EPA should look to other well performing EGUs rather than 

simply recalculating the emission rate for the EGU it had thought to be the best-performing EGU. 

Commenter (20293) stated that Figure 3 (refer to Docket ID EPA-HQ-OAR-2009-0234-20293-A2) sets 

out the emission rate in lb/MWh for each of the top 100 results in EPA’s data set, the final limit and the 

limit as proposed on reconsideration. The Commenter stated that these data show how much higher the 

added Logan test result is than what was routinely demonstrated by the better performing EGUs and that 

the proposed increase is unwarranted. The Commenter stated that 135 of the 260 EGUs in EPA’s data 

set have demonstrated that they can meet EPA’s proposed limit for new sources 

Response: As noted elsewhere in this document, the EPA used the same approach for selecting the “best 

performing similar source” in the proposed reconsideration as was used at proposal and final. The EPA 

acknowledges that there are various approaches that can be used for selecting the “best performer.” In 

addition, the EPA conducted standard outlier analyses on the data in the MACT floor pool (see, e.g., 

Docket ID EPA-HQ-OAR-2009-0234-20132). That is, the EPA selected the MACT floor pool of EGUs 

based on their lowest emission test result and then incorporated any other data from these floor EGUs 

into the variability analyses. 

CAA section 112(d)(3) requires EPA to establish the new source limits based on the performance of the 

best controlled “similar source.” The statute does not define the term “similar source” and, for that 

reason, the Agency has discretion to evaluate the sources for which the Agency has data and make a 

selection as long as the Agency has a reasoned basis for it selection. In this case, the EPA acknowledges 

that there are various approaches that can be used for selecting the “best performer,” including that 

noted by Commenter. However, for consistency the EPA has used the same approach as was used at 

both proposal and final – i.e., ranking of sources based on their lowest 3-run average. The EPA decided 

upon this approach of selecting the “best performing” sources on the premise that the lowest 3-run 

average was indicative of the best the source could perform; the additional data from the sources in the 

MACT floor pool were then used to assess variability. Issues with this approach were not raised in 

comment on the proposed MATS rule. Further, the EPA would note that the data submitted by each 

2010 ICR respondent were certified and did not violate the standard outlier analyses performed during 

the MACT floor analyses. 

2.2 New coal-fired EGU, not low rank virgin coal 
35 

2.2.1 Mercury (3.0E-03 lb/GWh) 

Monitoring 

Comment: Commenter (20261) stated that they conducted two evaluations of continuous Hg monitors 

(CMMs) on a pilot combustor to quantify low level Hg measurement capabilities. The Commenter 

discussed the results of these tests. The Commenter stated that the results of the study showed that 

depending on the instrument used, the quantitation level may be slightly above or below the proposed 

limit for new coal EGUs > 8,300 Btu/lb of 0.003 lb/GWh. The Commenter observed that due to the 

proximity of these quantitation levels to the proposed limit, facilities are likely to choose sorbent tubes 

rather than CMMs for compliance monitoring purposes. The Commenter expressed concern over the 

ability to maintain the certification of CMMs at such low levels given the lack at this time of NISTtraceable standards at that level. The Commenter concluded that at present, due to instrument drift, lack 

of low-level standards, and the need to maintain a safety margin between emissions and the limit, 

CMMs are not sensitive enough for monitoring compliance at the proposed limits for coal EGUs > 8,300 

Btu/lb or at the MATS rule limits for liquid oil. The Commenter stated that sorbent tubes have the 

sensitivity required for coal EGUs (with a higher flow rate as discussed earlier), but cannot provide the 

real-time process control feedback that facilities need to adjust operating conditions for compliance with 

emissions limits. The Commenter stated that for effective process control using a CMM, the emissions 

limit would have to rise above the currently proposed 0.003 lb/GWh. 

Commenter (20265) stated that the EPA’s methodology for setting the Hg standard appears to be a step 

in the right direction to the extent a sorbent trap monitoring system is used to determine compliance. The 

Commenter noted that although EPA states that utilities also have the option to determine compliance 

with the Hg limit using a CEMS, CEMS technology is not capable of reliably measuring Hg emissions 

at the level of the re-proposed standard, as other comments show The Commenter stated that the level of 

the Hg standard would need to be increased for sources to realistically use CEMS to measure emissions 

and adjust emission controls to maintain compliance with a standard. 

Response: If for a particular EGU, an owner or operator believes that a Hg CEMS cannot achieve the 

performance requirements needed to satisfy the final standards, the owner or operator may elect to 

install and use a sorbent trap monitoring system to monitor for continuous compliance. Moreover, in 

order to better track emissions and allow process control during transitional periods, such as load 

swings, an owner or operator may choose to use a more frequent sampling period, e.g., 30 minutes, 

instead of several days, over short periods. An owner or operator is also free to use a Hg CEMS for 

control operations and use the sorbent trap monitoring for compliance if he feels that such operational 

data is sufficiently critical to the EGU’s control operations. As noted in the Reconsideration proposal, 

the EPA believes the proposed change in the non-low rank virgin coal Hg limit for new EGUs will also 

allow the option of using a Hg CEMS for process control and for determining compliance based on 

information provided by the Commenters, our experience, and the National Institute of Standards and 

Technology’s (NIST) recently confirmed capability to certify Hg calibration gas generators down to 0.2 

micrograms per cubic meter (μg/ m3

).9

 

9

 See Status 0.2 μg/m3 Hg Reference Gas for Compliance Monitoring in rulemaking docket EPA-HQOAR-2009-0234. 
36 

Comment: Commenter (20268) expressed support of a shorter sampling period. 

Response: The EPA is finalizing the allowance for shorter sampling periods. 

Comment: Commenter (20268) expressed support for the option of using CEMS for monitoring Hg 

compliance. The Commenter noted that for process control and optimization of Hg control, only a 

certified electronic (i.e., real-time) Hg CEMS can provide the feedback information quickly enough to 

respond to critical changes impacting Hg emissions. 

Response: As noted in response to other comments, an EGU owner or operator can use an Hg CEMS 

for compliance, or an EGU owner or operator is free to use a Hg CEMS for control operations and use 

the sorbent trap monitoring for compliance or the sorbent trap monitoring alone for shorter time periods 

if it feels that such operational data is sufficiently critical to its control operations. The EPA maintains 

that these shorter sampling periods will allow sources to obtain the information quickly enough to 

respond to changes that may affect Hg emissions, contrary to the Commenter’s statements. 

Comment: Commenters (20258 and 20293) stated that EPA’s calculation of the Hg MACT floor is 

based on several assumptions about how sources in the future may choose to monitor the ongoing 

performance of their EGUs in lieu of the actual documented performance of the best EGUs. The 

Commenters stated that these assumptions are unsupported and unrealistic and bear no relationship to 

the performance of the EGU. The Commenters also suggested that these assumptions concerning which 

type of Hg monitoring approach – Hg CEMS or sorbent trap monitoring systems – would be used are 

unrelated to the compliance demonstration required by the final rule. The Commenters asserted that 

EPA’s assumptions result in a proposed limit that is 100 times greater than the measured performance of 

the best EGU and 15 times greater than would be calculated using EPA’s procedure for assigning 

variability to the performance of that EGU. 

Response: The EPA disagrees with the Commenters’ assertions that an EGU owner or operator may 

choose either Hg CEMS or sorbent trap monitoring system without regard as to how frequently reliable 

data can be provided seem incorrect. As explained in the Segall and Parker memo,10 the EPA agreed 

with the concerns of other Commenters who wanted to be able to use sorbent trap monitoring systems to 

provide data on a more frequent basis, so that issues with emissions control equipment or plant operation 

could be adjusted more quickly than under traditional uses which involved longer sampling periods. 

Such frequent monitoring sample collection and analysis, coupled with EGU owner or operation action 

to return equipment or processes to normal operation, would minimize Hg emissions and is consistent 

with the EPA’s goals of vigilance and quick corrective action when necessary. The EPA notes that that 

memo has been revised based on comments received to clarify that the calculation relies on 30 minutes 

of sampling time. The memo continues to explain how the shortest reasonable amount of time for 

sample collection using a Hg sorbent trap monitoring system was determined. Namely, that the 3XRDL 

value is calculated using the average of the method detection levels (MDL) identified from the best 

performing EGUs, and that 3XRDL value is then included in calculations using the shortest reasonable 

amount of time – 40 minutes - available for collecting and changing sorbent tubes. This amount of time 

addresses industry concerns that quick, reliable feedback may be needed for brief durations to ensure 

 

10 Determination of Representative Detection Level (RDL) and 3 X RDL Values for Mercury Using 

Sorbent Trap Technology” (Docket ID EPA-HQ-OAR-2009-0234-20222). 
37 

proper control device operation during certain operational periods. Rather than being unsupported, 

unrealistic, and unrelated, the emissions limit determined from the 3XRDL value and a 30-minute 

sample collection time, coupled with recently confirmed calibration gas generator capability, will allow 

companies not only to provide commercial guarantees but also to provide a value whose estimated 

measurement imprecision is comparable to that documented in ASME’s ReMAP study.11

Support for proposed standard 

Comment: Commenter (20268) expressed full support of the proposed Hg standard for new coal fired 

EGUs burning non-low rank coal. The Commenter discussed the standard, and agreed that a change 

from the final rule will not change the air pollution control equipment configurations and choices that 

will be made to comply with the revised standard as Hg reductions will still be greater than 97 percent. 

The Commenter supplied a table showing the emissions control equipment being used for recently-built 

coal-fired power plants to show that these configurations represent essentially all of the commercially 

available equipment and technologies available for limiting Hg emissions. The Commenter stated that 

the proposed revised limit combined with the recently confirmed capability of NIST to certify Hg 

calibration gas generators down to 0.2 μg/m3

 will allow its member companies to provide commercial 

guarantees, and allow sources to continuously monitor emissions which is necessary to ensure 

compliance with the 30-day rolling average Hg emission limit. 

Commenter (20279) supported the proposed increase in the emission limit for Hg for new coal-fired 

EGUs designed for non-low rank virgin coal. The Commenter stated that the original limit, as finalized, 

was too low for emissions to be reliably measured. The Commenter noted that the increased limit would 

improve owners’ and operators’ ability to track emissions and ensure compliance. 

Commenter (20269) supported the increase in the Hg emission limit for new coal-fired EGUs designed 

for non-low rank virgin coal. The Commenter noted that the original limit was too low for emissions to 

be reliably measured. 

Response: The EPA acknowledges the Commenter’s support. Please see section IV of the preamble to 

the final reconsideration rule for further discussion of EPA’s basis for finalizing these limits. 

Comment: Commenter (20284) was pleased that EPA has proposed to reconsider certain new source 

MATS limits. The Commenter appreciated that EPA has recognized the need to consider all of the data 

collected in the Information Collection Request as a basis for determining the appropriate level of the 

emissions standards for the regulated pollutants. The Commenter noted that it now appears there are 

several sources that have demonstrated, through short-term emissions testing, that they are able to 

achieve the emission rates that have been proposed. However, the Commenter stated these sources 

achieved the proposed emission rates under the best operating conditions possible and that long term ongoing compliance will still prove to be challenging during regular operation of the EGUs. 

Commenter (20284) supported the proposed revisions to the emission standards for new EGUs because 

they are more achievable and may allow new EGU developers to better consider the construction of new 

coal-fueled EGUs. However, the Commenter urged EPA to fully consider the ability of these new 

 

11 Docket ID EPA- HQ-OAR-2011-0817-0225. 
38 

sources to continuously demonstrate compliance with the proposed emission limits over the long period 

of time that they will operate. The Commenter discussed the limitations of CEMS and carbon (i.e., 

sorbent) trap systems. The Commenter noted that CEMS cannot reliably measure Hg emissions at the 

3.0 x 10-3 lb/GWh level of the proposed standard, and a carbon trap system does not provide real-time 

feedback on a EGU’s level of Hg emissions, which the Commenter believes it is important for Hg 

control. The Commenter stated it is impractical to conduct 30-minute sorbent trap runs as EPA assumed 

in setting the new source Hg limit. The Commenter stated that the Hg standard for new EGUs should be 

adjusted to provide EGUs with the true option of demonstrating compliance using either a Hg carbon 

trap system or a Hg CEMS. The Commenter stated that increasing the new source Hg limit would allow 

EGUs flexibility in showing continuous compliance with the standard in real time and improve the longterm viability of construct well controlled, high efficiency and high technology coal EGUs. 

Commenter (5803) expressed concern regarding the ability to accurately measure emissions (specifically 

Hg) at the Reconsideration’s proposed levels. 

Response: As mentioned earlier, if for a particular EGU, an owner or operator believes that a Hg CEMS 

cannot achieve the performance requirements needed to satisfy the final standards, the owner or operator 

may elect to install and use a sorbent trap monitoring system to monitor for continuous compliance. 

Moreover, in order to better track emissions and allow process control during transitional periods, such 

as load swings, an owner or operator may choose to use a more frequent sampling period, e.g., 30 

minutes, instead of several days, over short periods. The EPA notes that a 30 minute sample collection 

period, coupled with a 10 minute period for sorbent tube insertion and removal, is the shortest 

reasonable period for sorbent tube cycling, especially for brief durations lasting fewer than one or two 

days; such a collection frequency may prove arduous, but achievable, by persons desirous of such 

information. Although sampling over such brief periods may provide relevant information, it is not 

necessary to meet the 30- (or 90-) boiler operating day rolling average contained in the rule. An owner 

or operator is also 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 the EGU’s control operations. 

As noted in the Reconsideration proposal, the EPA believes the proposed change in the non-low rank 

virgin coal Hg limit for new EGUs will also allow the option of using a Hg CEMS for process control 

and for determining compliance based on information provided by the Commenters, our experience, and 

the NIST’s recently confirmed capability to certify Hg calibration gas generators down to 0.2 μg/ m3

. 

The Commenters have provided no data or information to suggest that the available compliance 

demonstration methodologies are inadequate. 

Calculation of standards 

Comment: Commenter (20286) expressed concerns about this emission standard’s feasibility. The 

Commenter stated that although the EPA’s MACT analysis data for the proposed revision to the Hg 

emission standard for new coal-fired EGUs designed to burn coal with ≥ 8,300 Btu/lb indicates that 62 

EGUs would be able to comply with the proposed Hg standard of 0.0030 lb/GWh, the Hg emissions data 

that the EPA is relying upon is based on relatively short-term testing. The Commenter stated that in 

many cases (approximately 70 percent of the EGUs), the results are based on a single test series. The 

Commenter is concerned that even a newly constructed EGU and in particular a reconstructed EGU may 

not be able to reliably meet the proposed Hg emission standard given the significant variability that can 

occur in Hg emissions from a coal-fired EGUs, and the Commenter stated that EPA’s own test data 
39 

demonstrates the variability that can occur in Hg emissions. The Commenter stated that the EPA 

excluded many EGUs from the EGUs considered to meet the proposed standard due to this variability. 

The Commenter provided examples of the variability in Hg emissions from EPA’s data. 

Response: This issue is outside the scope of this rulemaking. The issue of the use of short-term emission 

test data to establish 30-boiler operating day rolling average emission limits was addressed in the final 

RTC (see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 500, 549 - 551). This issue was not one of 

the issues being reconsidered and the EPA did not solicit comment in the reconsideration proposal 

regarding the use of short-term data. In any case, the Agency maintains that the approach to accounting 

for variability is valid for the reasons set forth in MATS record. The EPA explained its approach to 

assessing variability in the proposed MATS rule, and further discussion is provided elsewhere in this 

document. 

Further, the EPA believes Commenter is misguided in focusing on any “alleged” exclusions from the 

analyses. By statute, the new source MACT is to be based on the “best performing similar source” 

(singular) and, thus, may in fact be met by only one source within the population of sources. The fact 

that 62 EGUs have demonstrated the ability to achieve the level of the standard indicates that the limit 

has adequately addressed consistent with the statute. In addition, the proposed limit is based on use of 

the 3XRDL approach (see, e.g., 77 FR 71326) which is a higher (less stringent) number than the 

calculated limit and, therefore, we maintain the final limit provides a sufficient margin to address 

variability of the emissions. 

Comment: Commenter (20286) stated that an analysis of the EPA’s Hg MACT analysis data for coalfired EGUs indicates an inherent bias towards FBC EGUs. The Commenter stated that of the 38 FBC 

EGUs included in the entire data set, 58 percent (22 EGUs) are in the group that the EPA considers as 

meeting the proposed standard. The Commenter stated that approximately 90 percent of those 22 FBC 

EGUS are less than 25 percent of the proposed standard. 

The Commenter stated that of the 347 conventional boilers in the data set, only 12 percent (40 EGUs) 

are in the group considered to be meeting the standard. The Commenter stated that the Hg emission 

performance of coal-fired FBC EGUs is in contrast to the emission performance of FBC EGUs for acid 

gases. The Commenter stated that approximately 20 percent of the FBC EGUS in the respective data 

sets would be considered as possibly meeting the HCl and SO2 standards for coal-fired EGUs. 

The Commenter also stated that this analysis indicates a performance difference in Hg emissions 

between FBC EGUs and conventional boilers. The Commenter stated that the EPA should reanalyze the 

Hg MACT floor for coal-fired EGUs with separate categories for FBC EGUs and conventional boilers 

to ensure that the standard is achievable as required by CAA §112. 

Response: This issue is outside the scope of this rulemaking. Subcategorization was addressed in the 

final rule (see, e.g., 77 FR 9378 - 9379, 9394 - 9402). The EPA did not solicit comment in the proposed 

reconsideration rule on additional subcategories, including subcategorizing FBC EGUs. The specific 

issue of alleged “overrepresentation” of FBC EGUs in the database was also addressed at final (see, e.g., 

RTC, Vol. 1, pp. 358 - 365). 

Commenter asserts that FBC EGUs are disproportionately represented among the best performers for 
40 

Hg. However, FBC EGUs were not specifically selected in the 2010 ICR as best performers for Hg, as 

the EPA did not select any EGUs based on a determination that they were best performers for Hg, and to 

the extent CFB EGUs were selected in the 2010 ICR, they were selected because we determined they 

were best performers for non-mercury metallic HAP, acid gas HAP, or organic HAP or because they 

were randomly selected among the non-best performers for those three HAP groupings. Thus, the FBCs 

were selected for testing under the 2010 ICR based not on their boiler design but, rather, based on the 

age and on their PM and FGD control systems. As many FBC EGUs are relatively new, they were 

included in the non-mercury metallic HAP group selected for testing (because their PM controls were 

among the 175 newest) and the acid gas HAP group selected for testing (because FBC was considered to 

be an FGD system and the EGUs were among the 175 newest). 

Although FBC EGUs may be found among the better performers (among the top 10 EGUs) on the Hg 

MACT floor spreadsheet, they are also found in the range of 221 to 226 EGUs (of 393 data points). 

Thus, the EPA disagrees that FBC EGUs are disproportionately represented in the Hg floor and that 

their inclusion is somehow inappropriate or leads to skewing of the analysis. FBC EGUs are not an 

exception and such EGUs are found across the range of top performing EGUs for all of the HAP 

categories. 

Comment: Commenter (20286) stated that the EPA indicates that “at least eight existing non-low rank 

virgin coal-fired EGUs and one low rank virgin coal-fired EGUs have reported short-term stack test data 

that demonstrate that these EGUs have in practice achieved the new source limits proposed” (77 FR 

71329). The Commenter stated that the EPA does not identify these EGUs to allow Commenters to 

evaluate the validity of this claim nor does the EPA explain whether these EGUs literally meet all of the 

emission standards applicable to the EGU including the primary pollutants and surrogate standards (e.g., 

meet the fPM standard, total non-mercury metal HAP standard, and each speciated non-mercury metal 

HAP standard) or if the EGUs would only be able to meet the rule requirements via surrogate standards. 

Response: As Commenter has indicated, we note in the reconsideration proposal that there are a number 

of existing coal-fired EGUs whose test data available to the EPA at the time of rule development 

demonstrate that these EGUs have in practice achieved the new source limits proposed in this notice 

(considering all of their submitted data). In the reconsideration proposal notice, the EPA indicated that 

“based on our review of the data EPA collected as part of the 2010 Information Collection Request 

(ICR) process, at least eight existing non-low rank virgin coal-fired EGUs and one low rank virgin coalfired EGU” in this category meet the new source limits for Hg, PM, and HCl (see 77 FR 71329). 

Because this analysis was based on a review of the same 2010 ICR data available to the public (and, 

thus, the analysis could also have been done by the public), the EPA did not identify these EGUs. 

Further, the statute does require that any source be able to achieve the level of all the new source limits 

as the Commenters imply. However, the EPA conducted the analysis as one means of indicating that the 

new source limits are reasonable. The nine EGUs that have short-term stack test data that demonstrate 

that these EGUs have in practice achieved the new source limits for Hg, PM, and HCl are: 

Logan Unit 1 

Elm Road Unit 1 

Clover Units 1 and 2 

Chambers Units 1 and 2 

Mount Tom Unit 1 
41 

H.L. Spurlock Unit 3 

Sandow Unit 5A 

These EGUs all meet the Hg, fPM, and HCl or SO2 limits with all of the data available to the EPA at the 

time of rule development. Sources meeting these limits or alternate limits are meeting the standards so 

there is no need to evaluate the other alternate standards.

Comment: Commenter (20293) stated that in the EPA’s memorandum describing how it arrived at the 

proposed Hg limit for new coal- and low rank virgin coal-fired EGUs, the EPA sets out the formula and 

each of the values that it employs to calculate the MACT floor. The Commenter stated that the EPA 

does not report the actual results of the calculation, rather that “when rounded,” this calculation results 

in a limit of 3.0 x 10-3 lb/GWh. The Commenter stated that when the calculation is performed using each 

of the EPA’s assumptions, the result is 2.103 x 10-3 lb/GWh, which properly rounds to 2.1 x 10-3

lb/GWh. The Commenter stated that the EPA’s guidance requires that standards be established at no less 

than two significant digits. The Commenter stated that the result of the EPA’s calculation is no higher 

than 2.2 x 10-3 lb/GWh, not the 3.0 x 10-3 lb/GWh that it reports and proposes as the reconsidered Hg 

emission rate for new coal-fired EGUs. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding the rounding convention used in determining the final emission 

limits. The EPA used the same rounding convention as was used at final (see, e.g., RTC, Vol. 1, pp. 463 

- 465). The full equation is presented in the subject memo; the equation is carried out to the result in the 

revised memo in the rulemaking docket.12 Two significant digits have been used in the limit. 

Comment: Commenter (20293) stated that in the course of case-by-case new source MACT permitting, 

it was recently determined based on reference testing of similar sources and the application of a 

reasonable compliance margin, that a limit of 0.00088 lb/GWh, was appropriate. The Commenter stated 

that this rate is approximately 4.5 times higher than the EPA final limit. The Commenter stated that they 

do not believe that the Hg limit in the final rule is technically feasible, but they also believe that EPA’s 

proposed limit of 0.003 lb/GWh is not based on a robust consideration of all the data. The Commenter 

recommended that EPA examine the emissions data reviewed in that permitting process as well as for 

the Logan, Nucla, Seward, AES Greenidge, and Roanoke Valley I EGUs to determine which of those 

EGUs represents the best-performing EGU and set an appropriate limit – on the basis of all available 

data, not just the single lowest run. 

Response: The EPA disagrees with Commenter’s assertion. As noted elsewhere in this document, the 

EPA used the same approach for selecting the “best performing similar source” and establishing the 

MACT limits in the proposed reconsideration as was used at proposal and final. The EPA maintains that 

it has conducted a robust analysis of all of the data available to it (see, e.g., RTC, Vol. 1, pp. 460 - 463). 

To the extent the Commenter is asserting that the EPA did not consider all of the available data for the 

EGUs selected as the best performers, that assertion is incorrect. The Agency used all the data available 

for the best performing sources when determining variability. 

 

12 Determination of Representative Detection Level (RDL) and 3 X RDL Values for Mercury Measured 

Using Sorbent Trap Technologies, February 8, 2013, in rulemaking docket EPA-HQ-OAR-2009-0234.
42 

Three-times-RDL (3XRDL) approach and detection levels 

Comment: Commenter (20286) stated that in technical support documents (TSDs) for the proposed 

reconsideration of the MATS rule as well as other recent rulemaking, the EPA has attempted to use the 

2001 ASME ReMAP study to support the use of the 3XRDL approach. The Commenter stated that for 

the Portland Cement NESHAP reconsideration, the EPA claimed that using the 3XRDL approach would 

result in “a standard where the method would produce measurement accuracy on the order of 10 to 20 

percent, similar to other EPA test methods and the results found in the ASME ReMAP study” (Docket 

ID EPA-HQ-OAR-2011-0817-0225). 

Commenter (20286) stated that for the MATS rule reconsideration proposal, the EPA makes similar 

claims regarding precision of the methods at a level 3XRDL of the method in the TSD Determination of 

Representative Detection Level (RDL) and 3 X RDL Values for Mercury Using Sorbent Trap Technology

(Docket ID EPA-HQ- OAR-2009-0234-20222). The Commenter stated that the ReMAP study only 

evaluated a limited set of EPA reference methods. The Commenter stated that although the ReMAP 

study included some methods for Hg measurement, these methods are impinger-based methods and 

significantly different from the sorbent trap-based methodology of Method 30B which is the basis of the 

EPA’s analysis and the 3XRDL-based Hg emission standard for coal-fired EGUs designed to burn coal 

with ≥ 8,300 Btu/lb. The Commenter stated that the EPA is extrapolating the results of the ReMAP 

study to apply to all EPA reference methods, yet the EPA has provided no technical basis for making 

such an extrapolation. 

Commenter (20286) stated that even for methods that were included in the ReMAP or are similar to 

those methods, the data presented in the study shows no indication that the study evaluated the methods 

at concentration levels near 3XRDL. The Commenter stated that the EPA TSD on determining the 

3XRDL values shows the 3XRDL value for a Method 26 test to be between 83 - 250 micrograms per 

dry standard cubic meter (ug/dscm). 

Commenter (20286) stated that the EPA’s approach of setting MACT emission standards based on 

3XRDL of the reference methods is arbitrary and capricious. The Commenter stated that the EPA has 

failed to consider the practical enforceability of emission standards set at levels so close to the MDL. 

The Commenter stated that the EPA has not adequately demonstrated the reliability and accuracy of the 

EPA test methods at such a narrow margin above the MDL of the methods. 

Commenter (20286) stated that the 3XRDL approach can set the emission standards close to or even 

significantly less than the practical quantitation limit (PQL) and that the EPA’s own technical experts 

recognize the need for an additional margin between an emission standard and the PQL of methods used 

to demonstrate compliance. The Commenter stated that the EPA should determine the PQL of the 

required methods before assuming that the methods are sufficiently accurate to demonstrate compliance 

with an emission standard established using the 3XRDL approach. The Commenter stated that the EPA 

cannot ensure that an arbitrary factor of three will establish an emission standard greater than the PQL of 

such methods. 

Commenter (20286) stated that the TSDs contained in the docket for the recently proposed 

reconsideration of the Portland Cement NESHAP rule indicated that the margin between an emission 

standard and the MDL of the method should be greater than the factor of three that the EPA is using in 
43 

the 3XRDL approach to set MACT limits. The Commenter referred to EPA’s technical memorandum 

regarding the capabilities of PM CEMS and Method 5 (Docket ID EPA-HQ-OAR-2011-0817-0187, 

Particulate Matter Continuous Emissions Monitoring System (PM CEMS) Capabilities, dated June 13, 

2012). The Commenter stated (and cites data from) the analysis in the EPA technical memorandum 

indicates that the overall recommended margin between the Method 5 MDL and the emission standard 

should be at least a factor of 6 - 9 and not an arbitrary factor of 3 that the EPA is using in the MATS 

rule, Portland cement NESHAP, and other NESHAP rulemakings. 

Commenter (20286) stated that the EPA is relying upon the 3XRDL approach for setting some of the 

other emission standards and the statements made by EPA technical staff regarding the margin necessary 

between emission standards and method PQL are relevant to other EPA test methods. 

Response: The EPA believes the Commenter may misunderstand the 3XRDL approach as described in 

the December 13, 2011, memorandum from Peter Westlin and Ray Merrill (Docket ID EPA-HQ-OAR2011-0817-0142). 

When the EPA set an emission limit using the 3XRDL process, it is because the UPL calculation, which 

is designed to assess source and operational variability, has provided a value which is below the level of 

quantitation reasonably measured in practice by the test method. By using the 3XRDL value when the 

calculated MACT floor is below that level, the EPA provides a value that can be quantified on a 

practical basis, or, in other words, reliably measured. Such a value is suitable since it accommodates 

source and operational variability, as well as measurement precision. Given that a value measured above 

the MDL but below the 3XRDL could provide useful qualitative information about source performance, 

the EPA believes that such a measured values could be useful; however, not for compliance 

demonstrations, emissions limit setting, or other program purposes. Measurements at or above the 

3XRDL value provide quantitative, as well as qualitative information about source performance. The 

EPA does not believe a level greater than 3XRDL is necessary because, as mentioned elsewhere, at 

those levels the measurement imprecision is comparable to the imprecision in EPA’s approved test 

methods. 

Guidance to respondents for reporting pollutant emissions used to support the data collection specified 

the criteria for determining test-specific MDLs. Those criteria insure that there is only about a 1 percent 

probability of an error in deciding that the pollutant measured at the MDL is present when in fact it was 

absent (per the ReMAP Study). Such a probability is also called a false positive or the alpha, Type I, 

error. This means specifically that for a normally distributed set of measurement data, 99 out of 100 

single measurements will fall within ±2.54 σ of the true concentration. The anticipated range for the 

average of repeated measurements comes progressively closer to the true concentration. More precisely, 

the anticipated range varies inversely with the square root of the number of measurements. Thus, if σ is 

the standard deviation of anticipated single measurements, the anticipated range for 99 out of 100 future 

triplicate measurements will fall within ± 2.54 σ/√3 of the true concentration. This relationship translates 

to an expected measurement imprecision for an emissions value occurring at or near the MDL of about 

40 to 50 percent (per the ReMAP Study). 

Given that the MDL can also be expressed as a value equivalent to 3 times the standard deviation of 7 

measurements of a sample blank,13 and that a widely accepted definition of a practical quantitation limit 

 

13 See 40 CFR 136, Appendix B 
44 

(PQL) being 10 times the standard deviation of 7 measurements of a sample blank, one can determine 

the PQL in terms of the MDL to be 3 times the MDL, when rounded 

(seehttp://www.epa.gov/fem/pdfs/Env_Measurement_Glossary_Final_Jan_2010.pdf). As the EPA used 

the average MDL of best performing sources to determine an RDL, one can replace the MDL with an 

RDL and by holding the measurement distribution constant and raising the mean to the PQL (which for 

EPA purposes is a value equivalent with 3XRDL), one can calculate the imprecision of the 3XRDL 

value to be on the order of 10 to 20 percent. This level of imprecision is consistent with the levels of 

imprecision determined in ASME’s ReMAP study of EPA test methods. Therefore, the EPA finds 

measurements made at the 3XRDL value are appropriate for program purposes. 

The EPA acknowledges that the Commenter makes the point that the ReMAP study did not specifically 

address Method 30B. Although this is true, Method 30B performance criteria assure the test data 1) have 

a precision of less than 10 percent for Hg concentrations of less than one μg/m3 and less than 20 percent 

for Hg concentrations less than or equivalent to one μg/m3

, and 2) have an accuracy in terms of spike 

recovery of ± 15 percent. The EPA believes these criteria address the quality of data at the low levels. 

Also, as such, these test methods are considered to be self-validating and limited by the QA and QC 

information determined through the individual sample analysis, not by independent study such as 

ReMAP.

Comment: Commenter (20305) stated that setting new source Hg floors at 3XRDL contravenes CAA 

§112(d)(3). The Commenter stated that from the text of CAA §112(d)(3) and well established in binding 

D.C. Circuit precedent, floors for new sources must reflect the emission level achieved by the single best 

performing source in the category or subcategory. The Commenter cited court cases to support its point. 

The Commenter stated that the floors set at 3XRDL do not purport to reflect the emission level actually 

achieved by the single best performing source, and that the EPA must demonstrate that floors set at 

3XRDL reflect the emission level achieved by the single best performing source. 

Commenter (20305) noted that the EPA does not even claim that the new source Hg floor it proposes to 

set at 3XRDL reflects or even estimates the emission level achieved in practice by the single best 

performing coal-fired EGU designed for coal with greater than 8,300 Btu/pound. The EPA has estimated 

the uncertainties for an emissions value occurring at or near the MDL at about 40 to 50 percent, and at 

30 percent, at different places. The Commenter stated that taking the higher number, the maximum 

actual emissions of a plant whose pollution is measured at or below the detection level would be 1.5 

times the detection level. 

Response: The EPA disagrees with the Commenter and has established the RDL and 3XRDL evaluation 

process as part of MACT floor development to address measurement variability and reliability. The 

RDL is determined from the average of MDL’s reported in the MACT floor data set. This is not the best 

MDL reported for the MACT floor. The EPA believes that the outcome should minimize the effect of a 

test(s) with an inordinately high MDL (e.g., the sample volume was too small, the laboratory technique 

was insufficiently sensitive, or the procedure for determining the minimum value for reporting was other 

than the detection level). The EPA then calls the resulting mean of the MDLs the RDL because it is 

characteristic of accepted source emissions measurement performance. The RDL process was developed 

in this way in part to promote better MDLs moving forward by not considering the higher half, and in 

part to provide the flexibility for sources to select testers and labs that are competitive and local rather 

than forcing the selection of the single best performing laboratory and/or tester. MDL is commonly 
45 

defined as 3x the standard deviation of 7 measurements of a sample blank. The 3XRDL process is based 

on the widely accepted definition of quantitation limit being 10 times the standard deviation of 7 

measurements of a sample blank or 3.33 times the MDL. Refer to: 

http://www.epa.gov/fem/pdfs/Env_Measurement_Glossary_Final_Jan_2010.pdf. 

As mentioned in the RTC for Portland cement (see response to comment 3.22, pp. 45 - 46; Docket ID 

EPA-HQ-OAR-2011-0817-0846),14 when the EPA set an emission limit using 3XRDL it is because the 

UPL calculation, designed to assess source and operational variability, has determined that the floor 

would otherwise be set below the level of quantitation reasonably achieved in practice by the 

compliance test method. By using the 3XRDL value the EPA has determined that a level of quantitation 

reliably measured by the test method is the suitable emission floor as that test method is the 

determination of compliance necessary to write and enforce the rule. 

Comment: Commenter (20305) stated that the detection level used to set the 3x detection level emission 

standard does not reflect readily available methods. The Commenter noted that the rule requires 

compliance, first, over emissions averaged over 30 days. The Commenter stated that the EPA has 

selected standards that the best performing EGU would never exceed. The Commenter observed that 

monitoring requirements elsewhere in the rule bely any assertion that the rules’ standards are dependent 

upon hourly variations in “process and operational” characteristics; for most pollutants, the Agency 

requires a single quarterly stack test, with no monitoring of process and operational characteristics at all 

between tests. The Commenter stated that stack testing of such infrequency could not ensure compliance 

if hourly process and operational characteristics threaten emissions sufficient to push the 30-operatingday average above the applicable limit. 

The Commenter stated that neither the EPA nor industry has demonstrated any reasonable basis for 

feedback on a 30-minute basis, and the proposed rule’s emissions calculations require hourly 

measurements. The Commenter cited the EPA’s Reconsideration Beyond the Floor Memorandum to 

assert that plant-operators cannot adjust operations to make use of half-hourly sampling. The 

Commenter discussed the logistical difficulties of processing sorbent tubes at 30-minute intervals. The 

Commenter concluded that absent a requirement to use continuous emissions monitors, as well as a 

short-term averaging period sufficient to demand fine-grained emissions control, the Agency has failed 

to demonstrate any rational basis for its 20-minute testing period. 

Response: As explained above, the EPA determined the RDL (and the 3XRDL) value based on data 

submitted to the EPA by the best performing EGUs. As the average of those individual detection levels, 

the RDL (and the 3XRDL) certainly reflect readily available methods. The EPA finds the Commenter’s 

allegations concerning standards other than those identified as issues in the Reconsideration irrelevant; 

no response is necessary. With respect to the issue of concern – the non-low rank virgin coal-fired EGU 

Hg emission limit – either Hg CEMS or sorbent trap monitoring systems, both of which collect a 

continuous sample, are compliance options, whereas quarterly testing is not a compliance option. 

The EPA has determined that a short-term sorbent trap monitoring sampling approach involving 30-

minute sample collection periods is a feasible option for evaluating process and operational controls 

 

14 See also National Emissions Standards For Hazardous Air Pollutants: Portland Cement Summary Of 

Public Comments And Responses in rulemaking docket EPA-HQ-OAR-2009-0234. 
46 

during different operating levels to ensure compliance, and represents the shortest interval at which such 

measurements can occur to obtain data relatively comparable to a Hg CEMS. Having determined this 

monitoring approach as an option that is permissible under the rule, the rule sets the emission standard 

on the same basis in this Reconsideration rulemaking as the EPA used in setting standards for the 

proposed and final rules. That standard setting methodology is fully explained and supported in the 

rulemaking record. In evaluating detection levels over shorter sorbent trap sampling periods, the EPA 

shared Commenters’ concerns with source owners or operators having the ability to identify and react to 

emission problems in as expeditious a time frame as possible, and providing the ability to demonstrate 

compliance with the emission limit on a short-term basis. 

Comment: Commenter (20305) stated that the detection level used in the 3XRDL emission standard 

does not reflect the level at which Hg can be reliably detected by available test methods. The 

Commenter stated that the EPA’s average of 24 EGU-level results from the 43 EGUs used does not 

reflect a reasonable estimate of the level at which Hg emissions can be reliably detected. The 

Commenter questioned why the analysis was limited to the EGUs that were used, and stated that the 

record does not support that the measurements were from the best performing testing companies and 

laboratories using the most sensitive analytical procedures. The Commenter stated that the most 

sensitive analytic procedures are those with the lowest detection limits provided in response the 

Agency’s information collection request, which is not the sample used by the EPA. 

Commenter (20305) stated that by counting each EGU, used to determine the average detection limit, 

rather than each laboratory-specific detection level, the EPA has biased its “representative” average. The 

Commenter stated that by including outlying detection levels, and counting them repeatedly (once for 

each EGU), the Agency has failed to produce a number that is the mean value of the available reported 

pollutant-specific MDLs from the best performing testing companies. 

Commenter (20305) stated that the EPA underestimates the performance of sorbent tube technology 

used for the 3XRDL emission standard. The Commenter stated that the EPA assumes a MDL of 1 

ng/section under Method 30B but vendors report much lower detection levels. 

Response: The EPA did not assume an MDL, but determined the RDL from the average of MDLs 

reported in the MACT floor data set that used Method 30B. The EPA believes that by using MDLs 

reported for best performing EGUs, the outcome should minimize the effect of a test with an 

inordinately high MDL (e.g., the sample volume was too small, the laboratory technique was 

insufficiently sensitive, or the procedure for determining the minimum value for reporting was other 

than the detection level). The EPA then calls the resulting mean of the MDLs the RDL because it is 

characteristic of accepted source emissions measurement performance. The 3XRDL process was 

developed in lieu of the 3XMDL in this way in part to promote better MDLs moving forward by not 

considering the higher half, and in part to provide the flexibility for sources to select testers and labs that 

are competitive and local rather than forcing the selection of the single best performing laboratory 

and/or tester. 

Comment: Commenters (20258 and 20293) stated that EPA’s 3XRDL calculation should have no 

impact on the determination of the standard for this subcategory. The Commenters’ Chart No. 5 [see 

originals for figure] showed the lowest emission test result for the 158 EGUs in EPA’s data set. The 

Commenters stated that these data demonstrate that EPA’s calculation leads to a result that is not 
47 

consistent with the ongoing improvement in control technologies – a limit for Hg for new sources that is 

less than the measured emission rates of about one-third of existing EGUs. 

Commenters (20258 and 20293) stated that the proposed Reconsideration will relax the final standard 

for Hg emissions from coal-fired EGUs by a factor of 15. The Commenters said that this proposal is not 

based on any new information concerning the emissions performance of the best-performing EGU, but 

is in response to petitions received from industry members that they need to be able to determine 

compliance on an ongoing basis. The Commenters noted that in its initial testing request, the EPA had 

advised sources that it anticipated that the sampling period might need to be extended to up to two 

weeks to obtain the required precision. The Commenters stated that because EPA has multiplied the 

results from the best-performing EGU by a factor of 3.5, that length of sampling should no longer be 

required to ascertain compliance with the standard. The Commenters noted that because of QA 

requirements, most users replace sorbent traps every four to seven days, which limits the amount of data 

lost if a sample is rejected for QA reasons. The Commenters noted in response to Petitioners’ 

representations, the EPA has proposed to assume that the time for sorbent trap sampling is reduced from 

the normal period of several days to a week to just 30 minutes. The Commenters stated that the selection 

of 30 minutes is intended by EPA to reflect the sampling time available with the use of Hg CEMs. The 

Commenters stated that EPA then makes a number of assumptions about the use of sorbent traps to 

calculate its 3XRDL “alternate” approach to setting standards. The Commenters stated that this 

approach leads the agency to propose a limit that may be higher than would have resulted from 

Petitioners’ suggestion to raise the emission limit to facilitate the use of Hg CEMs. 

Commenters (20258 and 20293) noted, in the first instance, that it may be possible for new EGUs to 

employ Hg CEMs that have sufficiently low detection levels to allow their use in ascertaining 

compliance. The Commenters stated that tests conducted on the newest generation of Hg CEMs 

demonstrate an ability to detect and to quantify Hg emissions at or below the final Hg emission limit for 

coal-fired EGUs. The Commenters noted that the manufacturers of the Tekran Hg CEM assert that their 

system has a quantification level of approximately 0.033μg/m3. The Commenters noted that for internal 

compliance assurance purposes a measurement greater than the detection level, but less than the 

quantification level, should be sufficient to alert the operator that corrective action is required. The 

Commenters noted further, there is no reason why sampling times in Hg CEMs cannot be extended 

beyond 15 minutes and sampling volumes increased to provide for lower detection levels as desired. 

Commenters (20258 and 20293) stated secondly, that it is reasonable to assume that over the next 

several years operators can develop and implement continuous parametric operating plans to assure 

compliance with operating limits. The Commenters added that these plans are in addition to, and not in 

lieu of, the enforceable compliance demonstration requirements. 

Commenters (20258 and 20293) stated thirdly, there is no documentation that the performance of 

affected EGUs is so variable that sources must be able to determine emission levels on either a 15 

minute or 30 minute basis to maintain compliance with a 30 operating-day average. The Commenters 

stated that the scenario posed by EPA is economically unrealistic. The Commenters continued, that 

given the available alternatives, they find it difficult to believe that sources will routinely volunteer to 

change sorbent traps every half hour and then pay for laboratory analyses of the 17,520 samples per year 

that would result from such an exercise and with the short-term turnarounds that would be required to 

use such samples as a short-term monitoring system. The Commenters stated that the EPA has selected 
48 

30 minutes in an attempt to duplicate the frequency of measurement of Hg CEMs, but Hg CEMs have 

much higher sampling flow rates than cited by EPA for sorbent traps. The Commenters concluded, for 

this reason, the EPA’s assumption of extremely short sampling times and low flow sampling rates for 

sorbent traps leads to levels of quantification far higher (less precise) than ordinarily achieved by either 

Hg CEMs or sorbent traps. 

Commenters (20258 and 20293) asserted that EPA has not explained why a determination of ongoing 

emission rates 5 to 10 times per month – or 100 times per month – will not suffice to complement 

ongoing parametric monitoring. The Commenters stated that sources are, of course, free to conduct 

additional monitoring as they see fit, and can generate hourly updates to the rolling monthly average by 

employing more than one trap at a time and staggering the start times of the sampling by different traps. 

Commenters (20258 and 20293) stated that the EPA’s 3XRDL calculation contains several key errors 

and incorrect assumptions. The Commenters noted that this calculation employs four factors: (1) the 

MDL of the test, (2) the sample collection time, (3) the sample collection rate and (4) the heat rate of the 

EGU. The Commenters stated, that with respect to the MDL, the EPA asserts that it has calculated the 

average MDL for measuring mass from a number of tests of the best-performing EGUs, included 

multiple results from three sources owned by a single operator that are several times higher than other 

values in the set. The Commenters stated there is no reason why EPA should base its determination of 

the detection level that can be achieved by new sources in the future on the basis of the choice of MDL 

where there was no obligation or incentive to employ more accurate methods to determine the mass of 

the sample in the sorbent trap. The Commenters stated that the EPA should use either the best, or at least 

one of the best MDLs reported by a lab in the group. The Commenters stated that if EPA were to do this, 

the applicable limit would be unaffected by the 3XRDL test. 

Commenters (20258 and 20293) stated that EPA uses a sample collection time of 30 minutes and noted 

that the EPA intended to use a sample collection time of 20 minutes, but erred. The Commenters stated, 

as explained above, this choice is arbitrary and unrealistic. The Commenters stated that if EPA assumes 

a sample collection time of 360 minutes (6 hours) and makes no other change to its assumed values, the 

3XRDL level is less than the final standard and so the applicable limit would not affected by the 3XRDL 

test. The Commenters stated that sources that employed sample collection times of six hours would be 

able to determine their compliance status 120 times per month. The Commenters stated that this should 

be more than sufficient to assure compliance with applicable standards, especially because sources 

should be assumed to establish a baseline emission rate that takes into account the level of emissions 

variation shown by EPA’s 99th percentile UPL procedure. 

Commenters (20258 and 20293) stated that EPA assumes a sample collection rate of 0.5 liters per 

minute, based on “an informal survey on the normal sampling rates.” The Commenters stated this rate of 

sample collection may be the practice today, but there is no reason why, if the final rule remains in 

place, sources cannot elect to sample at the rates available with commercially available equipment. The 

Commenters stated that if the EPA assumes that the source samples at the maximum rate of 

commercially available EGUs, and makes no other change to its assumed values, the final limit is not 

affected by the 3XRDL test. 

Response: One Commenter’s concern appears to arise not from the 3XRDL calculation, but from the 

calculation used to express the 3XRDL value into its corresponding electrical output rate (in lb/MWh). 
49 

With respect to the Commenter’s claims that data it submitted demonstrate an emission limit that is not 

consistent with the ongoing improvement in control technologies, the EPA is unable to assess the data’s 

relevance, particularly with respect to the sampling periods over which the data were collected. In order 

to make a reasoned comparison between the limit and the data, if indeed that were necessary, the 

Commenter’s data sample collection period would need to be consistent with that of the rule – 30 

minutes. As the Commenter has not provided this critical piece of information, the EPA finds the 

comment not relevant. 

The EPA agrees with Commenters that the EPA developed the revised Hg limit in response to EGU 

owner or operator concerns about having the ability to identify and react to emission problems in as 

expeditious a time frame as possible, and providing the ability to demonstrate compliance with the 

emission limit on a short-term basis, yet the EPA disagrees with the Commenters’ implication that the 

revised Hg limit does not represent the ability of best-performers over the reduced sampling period. 

Although the EPA agrees that compliance is to be determined over 30 days, the EPA does not believe it 

prudent to bar an EGU owner or operator from conducting more frequent sampling on his own, 

particularly when the EGU owner or operator is monitoring control devices more carefully via the more 

frequent monitoring. 

With respect to the Commenter’s concerns over a shorter sampling period than 4 to 7 days, as mentioned 

earlier, the EPA has determined that a short-term sorbent trap monitoring sampling approach involving 

30-minute sampling periods is a feasible option for evaluating process and operational controls during 

operational changes to ensure compliance, and represents the shortest interval at which such 

measurements can occur to obtain data relatively comparable to a Hg CEMS. Having determined this 

monitoring approach as an option that is permissible under the rule, the rule sets the emission standard 

on the same basis in this Reconsideration rulemaking as the EPA used in setting standards for the 

proposed and final rules. That standard setting methodology is fully explained and supported in the 

rulemaking record (see, e.g., MATS MACT Floor Memos - Docket ID EPA-HQ-OAR-2009-0234-9858, 

Docket ID EPA-HQ-OAR-2009-0234-20132). 

The EPA agrees with the Commenter who asserts that it may be possible to employ Hg CEMS as a 

compliance option, and the rule continues to allow Hg CEMS use. The EPA agrees with the Commenter 

that Hg CEMS could be used in a corrective action, not compliance, mode as long as a compliance 

determination method for Hg emissions is selected and used. 

The EPA disagrees with the Commenter’s assertion regarding extending Hg CEMS sampling times or 

increasing sampling volumes, as neither the sampling time nor the sampling volume appear problematic 

for Hg CEMS, especially based on the aforementioned information from other Commenters, our 

experience, and NIST’s confirmed Hg calibration gas generation capability. 

With respect to the Commenter’s second assertion, although the EPA agrees such continuous parametric 

operating plans could be developed and used by EGU owners or operators for their ongoing, internal 

operations, the rule does not require their development or use. For the reasons given above, the EPA 

disagrees with the Commenter’s third assertion, noting that the sampling period identified and used 

represents the shortest interval at which such measurements can occur to obtain data relatively 

comparable to a Hg CEMS. 
50 

With respect to the Commenters’ concerns that longer sampling periods could complement ongoing 

monitoring, the EPA does not disagree, but, such longer sampling periods are not consistent with the 

shortest reasonable period determined to be sufficient for compliance purposes. 

The EPA disagrees with the Commenter who suggests key errors and incorrect assumptions regarding 

the newly-calculated non-low rank virgin coal-fired Hg emission limit. As mentioned elsewhere, the 

RDL is the average of individual MDLs of the best-performing EGUs that provided data; the sample 

collection time represents the shortest reasonable interval over which measurements can occur; the 

sample collection rate represents a typical value observed and available today; and the heat rate is the 

same value used for other Hg floor calculations. 

As explained in the preamble, the EPA acknowledged the sample collection time error in the 

Determination of Representative Detection Level (RDL) and 3 X RDL Values for Mercury Measured 

Using Sorbent Trap Technologies memorandum and revised the memorandum to make the sample 

collection period a consistent 30 minutes. As mentioned earlier, the EPA found that 30 minutes - not 360 

minutes, as suggested by the Commenter – to be the shortest interval at which such measurements can 

occur to obtain data relatively comparable to a Hg CEMS. 

Although the EPA agrees with the Commenter that nothing prevents sample collection rates in excess of 

0.5 liters per minute in the future, nothing in today’s rule requires a change in this normal sorbent trap 

monitoring sampling rate. 

Comment: Commenters (20258 and 20293) stated that EPA assumes that the heat rate of new coal-fired 

boilers using high Btu coal will be 11,180 Btu/kWh. The Commenters said that the Agency argues that 

this number represents the average of the EGUs that it selected for evaluation for this purpose. The 

Commenters stated that this rate is substantially greater than one would anticipate for a new coal-fired 

plant burning high Btu coal and is higher than the average of all coal-fired EGUs in EPA’s data set 

(10,478 Btu/kWh). The Commenters stated it is also somewhat higher than the average of the top 29 

EGUs in EPA’s data set (8,449 Btu/kWh). The Commenters noted that these somewhat smaller 

differences turn out to be more significant than might be apparent. 

Commenter (20305) also stated that the EPA used a very high and inefficient heat-rate of 11,180 

Btu/kWh in its calculation of detection levels to create an output-based standard. The Commenter 

disagreed with having the detection level depend upon the “average heat rate of the EGUs used to 

determine the RDL value.” The Commenter noted that the testing laboratories would have reported the 

same detection levels regardless of the heat rate. The Commenter stated that the EPA used a heat rate 

that is non-representative of the heat rates likely at a newly constructed coal-fired power plant, and by 

doing so, inflated its detection level well beyond what could be reasonably described as 

“representative.” 

Response: The EPA disagrees with the Commenters with respect to the use of more efficient heat rates 

for Hg. Similar concerns with the heat rate were raised by Commenters in the MATS rulemaking and 

addressed in the RTC (Vol. 1, pp 466 - 467). As mentioned there, the EPA utilized the average heat rate 

because of the antagonistic relationship between low Hg emissions and high thermal efficiency in coal 

combustion. This antagonistic relationship is attributable to the high carbon content (i.e., high loss on 

ignition (LOI)) typical of inefficient combustion EGUs and the affinity of this high-carbon flue gas 
51 

stream for Hg. 

For the conversion of the Hg emission rates for the best performing (lowest emitting) sources, the EPA 

utilized the average heat rate for the sources in the input based floor pool (i.e., the 47 sources used to set 

the lb Hg/MMBtu standard) and maintained the same EGUs and their rankings between the input- and 

output-based standards. The numerical value of this average heat rate is 11.18 MMBtu/MWh. These are 

the same EGUs that were used to determine the RDL value and, thus, the use of the average heat rate is 

appropriate. 

2.3 New coal-fired EGU, low rank virgin coal 

Existing coal refuse-fired EGUs 

Comment: Commenters (20285 and 20302) stated that in the final MATS Rule, the EPA did not 

consider the effects of the MATS HCl emission limit on existing coal refuse-fired circulating fluidized 

bed (CFB) boilers, also known as FBC. 

Commenter (20285) stated that because the EPA has decided to reconsider the HCl limit for new coalfired EGUs, and because EPA has also concluded that FBC EGUs should be regulated differently from 

traditional coal-fired EGUs under the MATS rule, the EPA should also revise, through the current 

reconsideration process, the HCl limit for coal refuse-fired FBC EGUs. 

Commenter (20302) noted that facilities using this technology serve as a remedy to abandoned coal 

mines and coal refuse piles. The Commenter stated that the final Utility MATS rule should not establish 

HCl limits that would adversely impact the environmental beneficial use of waste coal. The Commenter 

discussed the difficulties for well-controlled CFB EGUs in meeting the HCl limits in the final MATS 

Rule. The Commenter urged the EPA to reconsider the proposed HCl and surrogate SO2 limits, which 

are not achievable for certain EGUs including EGUs operating with acid gas controls. 

Commenter (20302) stated that fuel switching is not an option for coal refuse-fired CFB boilers. 

Commenter (20285) asked that the EPA create a subcategory-specific HCl emission limit for coal 

refuse-fired FBC boilers that is technically and economically achievable in consideration of the distinct 

characteristics of this source category. 

Commenter (20285) provided discussion regarding the determination of a MACT floor for HCl 

emissions from coal refuse-fired CFBs, including an attachment deriving an example HCl limit based on 

existing EGUs, and attachments that list the costs for HCl control using SDA for an existing EGU, and 

ash generation at multiple facilities. 

Commenter (20285) stated that existing coal refuse-fired FBC EGUs injecting limestone to control SO2

and other acid gases are not capable of yielding the HCI emission reductions necessary to comply with 

the applicable limit under the Final MATS Rule. The Commenter provided discussion of available 

controls that could be used by existing EGUs, and a discussion of the Final Rule’s approach to setting 

standards for existing coal refuse-fired FBC EGUs. 
52 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding the existing-source emission limits. 

The issue of establishing a separate subcategory for coal refuse-fired CFB EGUs, essentially 

Commenter’s main point, was addressed in the final rule (see, e.g., 77 FR 9378 - 9379, 9394 - 9402; 

RTC, Vol. 1, pp. 358 - 365). The issue of a separate HCl limit for coal refuse-fired EGUs was also 

addressed in the final rule (see, e.g., RTC, Vol. 1, pp. 584 - 587). The issue relating to the alleged 

inability of coal refuse-fired EGUs to add on additional controls was also addressed in the final rule (see, 

e.g., RTC, Vol. 1, p. 761). The issue of the impact of sodium-based sorbents on the ability of coal 

refuse-fired EGUs to reuse their ash was also addressed in the final rule (see, e.g., RTC, Vol. 2, pp. 509 - 

511). 

As noted in the RTC (Vol. 1, p. 761), the EPA is aware of at least two coal refuse-fired CFB EGUs that 

reported add-on “polishing” technologies for SO2 (or, at least, technologies beyond the CFB itself) in 

their responses to the 2010 ICR. One of these EGUs had the additional equipment installed during initial 

construction; however, the other EGU retrofitted the equipment. Thus, the EPA does not believe (as 

Commenter implies) that the cost of such add on (or additional) “polishing” equipment is prohibitive for 

coal refuse-fired EGUs. The EPA has found that at least one control device vendor markets such 

technology (including installations on a coal refuse-fired CFB EGU, on CFB EGUs using other coal 

ranks, and on retrofit applications) that will lower HCl (and HF) emissions to the 1 part per million 

level.15,16,17 Therefore, the EPA does not agree, as Commenter also implies, that the HCl limit in the 

final rule is unachievable for such EGUs. One unique feature of the technology when employed on CFB 

EGUs is the “ability to use the ash (which contains surplus lime) supplied by the CFB (via the flue gas 

stream)” for enhanced SO2 control.18,19 The EPA believes that this “left over” lime in the ash will lessen 

or eliminate the need to add lime, thus lessening the overall cost of the technology. Although not 

specifically installed for HCl control, the EPA believes that the humidification step inherent in the 

process will further remove HCl. 

Further, such coal refuse-fired EGUs are eligible for the alternate SO2 emission limit in lieu of the HCl 

limit. The EPA does not believe that there is any confusion in the definition of “dry flue gas 

desulfurization technology, or dry FGD, or spray dryer adsorber (SDA), or spray dryer, or dry scrubber” 

and that the definition clearly indicates that FBC and CFB boilers qualify the respective EGU for the 

alternate SO2 emission limit. At least four coal refuse-fired EGUs have demonstrated the ability to 

achieve the level of the alternate SO2 limit based on data available to the EPA (i.e., Northampton, Mt. 

Carmel Cogen, Panther Creek Partners, and WPS Westwood Generation; see Docket ID EPA-HQ-OAR-

 

15 Gatton, Lawrence, Principal Engineer, Alstom Power ECS. Next Generation NID for PC Market. 

Presented at Coal-Gen Conference and Exposition, Columbus, Ohio. August 17 - 19, 2011.

16 Alstom. NID Flue Gas Desulphurization System for the Power Industry. 

17 Alstom. NID Flue Gas Desulphurisation. 

18 Morin, Jean-Xavier, Alstom. Recent Alstom Power Large CFB and Scale up aspects including steps to 

Supercritical. Presented at 47th International Energy Agency Workshop on Large Scale CFB, Zlotnicki, 

Poland. October 13, 2003 

19 Ahman, Stefan, et al. Alston Power’s Flash Dryer Absorber For Flue Gas Desulfurization. 

Proceedings of the 2002 International Joint Power Generation Conference. Phoenix, Arizona. June 24 - 

26, 2002. 
53 

2009-0234-20132, “AcidGas_coal” tab on spreadsheet 

“a3_acid_gases_mact_floor_analyses_121611.xlsx”). In addition, the EPA has reviewed a number of 

Title V permits for coal refuse-fired EGUs and, based on those permits, believes that the alternate SO2

emission limit is achievable by such EGUs if they believe that they cannot achieve the HCl emission 

limit.20

Comment: Commenter (20285) requested that the language of the Final MATS Rule be revised to 

clearly reflect that limestone injection within the FBC combustion zone qualities as DSI, and therefore 

would allow plants with existing coal refuse-fired FBC EGUs to utilize the SO2 emission surrogate as a 

compliance demonstration method. The Commenter noted that the Commenter’s coal refuse-fired FBC 

EGUs would be no more able to demonstrate compliance with the surrogate SO2 emission limit under 

MATS than the stringent HCl emission limitation in the same regulation. 

Response: This issue is outside the scope of this rulemaking. The issue of clarifying the definitions of 

FGD was raised in public comments submitted in response to the May 3, 2011, proposed MATS rule (76 

FR 24976). The EPA’s responses to the comments are in the RTC (see, e.g., Vol. 2, p. 715). As noted in 

the RTC, the definition in 40 CFR 63.10042 for “Dry flue gas desulfurization technology, or dry FGD, 

or spray dryer, or dry scrubber” indicates that CFB technology is considered to be an “FGD system” 

(“[a]kaline sorbent injection systems in FBC or CFB boilers are included in this definition”). The EPA 

believes that the definition, when taken as a whole, adequately addresses Commenter’s concerns. 

Comment: Commenter (20285) stated that establishing an HCl emission limit of 0.034 lb/MMBtu for 

coal refuse-fired FBCs would not result in unacceptable adverse health impacts. The Commenter 

provided an attachment reviewing the health impact of an example EGU, using EPA methods. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding additional health impacts. 

2.3.1 Mercury (possible revision) 

Existing EGUs 

Comment: Commenter (20275) was concerned with the impact that the Final MATS Rule and the 

proposed MATS Rule Reconsideration will have on low rank virgin coal-fired power plants. The 

Commenter referred to previously filed comments outlining its position on the MATS Rule during the 

proposal phase, including their comments on the burdensome emissions limitations placed on existing 

and new low-rank virgin coal EGUs, particularly the establishment of a BTF limit for Hg emissions 

from existing EGUs. The Commenter referred to comments to the proposed MATS rule: Docket ID 

EPA-HQ-OAR-2009-0234-17930; Docket ID EPA-HQ-OAR-2011-0044-5240. 

 

20 The permit limits for SO2 emissions from Mt. Carmel Cogen, Panther Creek Partners, Scrubgrass 

Generating Company, Wheelabrator-Frackville Energy, and WPS Westwood Generation are all based 

on a 24-hour average whereas the MATS alternate SO2 limit is on a 30-day rolling average. The EPA 

believes that the 24-hour permitted limits are such that the 30-day average alternate limit would be 

achievable. The permits for each of these EGUs may be found in rulemaking docket EPA-HQ-OAR2009-0234. 
54 

Commenter (20275) stated that the limits cannot be met by new EGUs, thus, for the reasons in the 

referenced data and comments, the BTF limit for existing low-rank virgin coal EGUs, established at 4.0 

lb/TBtu in the rulemaking, cannot be attained by existing EGUs. The Commenter said, in violation of 

CAA §112(d)(3), the limit was based on the lowest data point from a single EGU rather than the group 

of EGUs required by the CAA. The Commenter added that the one newest EGU used for the limit could 

not consistently meet the proposed 4.0 lb/TBtu limit. The Commenter concluded that the Hg BTF limit 

for low-rank virgin coal EGUs should be struck from the rule. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding the existing-source emission limits. 

New EGUs 

Comment: Commenter (20275) stated that the data and comments filed by affected parties during this 

rulemaking clearly demonstrate that the MATS Rule’s Hg limits for new low-rank virgin coal EGUs are 

not consistently achievable at the newest existing low-rank virgin coal EGU nor do the limits account 

for low rank virgin coal variability The Commenter stated the Hg limit should therefore be set at a 

higher level, one consistently achievable by the newest existing low-rank virgin coal EGUs. 

Commenter (20303) stated that the MATS Hg limits for new low-rank virgin coal EGUs are not 

consistently achievable at the newest existing low-rank virgin coal EGU nor do the limits account for 

low rank virgin coal variability. The Commenter stated that the Hg limit should therefore be set at a 

higher level, one consistently achievable by the newest existing low-rank virgin coal EGUs. 

Response: The EPA disagrees with Commenters’ allegation that the subject emission limit is not 

achievable or being achieved in practice. Based on data in the record (Docket ID EPA-HQ-OAR-2009-

0234) and available to Commenters, the EPA has determined that three of the four low rank virgin coal 

EGUs tested that had mercury-specific controls were meeting the BTF limit established (see 77 FR 

9393). As the final new- and existing-source Hg limits for low rank virgin coal-fired EGUs are the same, 

the EPA believes the new source limit to be reasonable and achievable. 

Comment: Commenter (20285) stated that reduction of chlorine through the use of DSI for coal refusefired EGUs could also result in a reduction in the amount of Hg oxidized and, in turn, cause a 

corresponding increase in Hg emissions. The Commenter suggested that to the extent that EPA 

determines to continue to impose a numeric emission limit for HCl on coal refuse-fired FBC boilers 

through the MATS rule, the EPA should establish a revised emission limit for HCl that applies only to 

coal refuse-fired FBC EGUs. 

Response: The EPA understands that flue gas halogens will promote the oxidation of Hg which 

enhances its control. The EPA also understands that DSI can be used to capture HCl and thus make it 

relatively unavailable for reaction with gas phase Hg. However, the EPA is also aware of several 

commercially available control options that have been specifically developed to control Hg that is 

present in the flue gas stream as elemental Hg vapor. Those technologies – which may include injection 

of halogen or halogenated activated carbon – assist in the oxidation of elemental Hg. The location of the 

halogen or halogenated-AC injection can be optimized to avoid interference by the DSI system. Western 
55 

subbituminous and many low rank virgin coals have inherently low chlorine levels and tend to produce 

elemental Hg vapor in the post combustion flue gas. Facilities burning those fuels may need to use those 

technologies (e.g., bromine injection, halogenated activated carbon, etc.) to control Hg emissions. 

Comment: Commenter (20286) stated that revisions to the Hg emission standard for new low rank 

virgin coal-fired EGUs are not clearly explained in the preamble discussion in the Federal Register or 

the TSD. The Commenter stated that if the EPA is considering making an emission standard more 

stringent with this proposal, it must be clearly presented, explained, and justified so that interested 

parties have full opportunity to comment on such a change. The Commenter stated that the TSD only 

includes a footnote for the revised MACT analysis results for Hg, which appears to indicate that the 

EPA is considering reducing the Hg emission standard for Subcategory 2 from 0.040 lb/GWh to 0.030 

lb/GWh. 

Response: The EPA did not propose to revise the Hg limit for low-rank virgin coal-fired EGUs. Instead, 

as Commenter notes, the EPA referenced a potential data availability issue for such EGUs. The fact that 

Commenter has identified the information indicates that it was clearly presented and fully available for 

comment. Further, as the EPA received no comments supporting a revision to the low rank virgin coal 

Hg limit, the limit will remain as promulgated in the final MATS rule. 

Comment: Commenter (20286) stated that the EPA indicates that the proposed new source limits for 

Hg are consistent with the levels suggested by a number of control vendors (77 FR 71329), yet the EPA 

does not provide the vendor information with the proposed rule or provide a comparative analysis to 

support its claim. The Commenter stated that the vague discussion regarding vendor “suggestions” does 

not provide adequate justification to support achievability as required by CAA §112. 

Response: The EPA is not using vendor “suggestions” as a justification supporting its rulemaking as 

suggested by Commenter. Rather, the EPA is noting that its independent analysis (see Docket ID EPAHQ-OAR-2009-0234-20222) happens to also be in the same range as indicated by vendors (see, e.g., 

Docket ID EPA-HQ-OAR-2009-0234-20176), one indication of the reasonableness of the analysis. 

2.4 IGCC EGU 

Calculation of standards 

Comment: Commenter (20293) stated that the EPA established the MACT limits for Integrated Gas 

Combined Cycle (IGCC) EGUs on the basis of the permitted EPA emission limits for new EGUs. The 

Commenter recommended that EPA consider permitted emission levels for all subcategories and all 

pollutants, not just IGCCs. The Commenter stated that the EPA is obliged to set MACT standards on the 

basis of all of the information that is available to it, including permit determinations, specifically those 

in the RBL Clearinghouse. The Commenter stated that pre-construction permitting is based on 

conservative engineering assumptions and such limits should be considered an upper bound on the 

actual performance of the EGU and should be considered in determining the performance of the EGU. 

The Commenter stated that EPA seeks to rely solely on permitted limits in establishing MACT limits for 

IGCCs, yet EPA proposes to set MACT limits for Hg, SO2 and other pollutants that are higher than 

permitted levels that sources have complied with for many years. 
56 

Response: The EPA has stated earlier that generally where sufficient emissions data are available, it 

believes it appropriate to use such data instead of permit data (see, e.g., RTC, Vol. 1, pp. 460 - 463). As 

Commenter notes, the EPA followed this practice for all subcategories except for the new source limits 

for IGCC EGUs where we had very limited data (and none from current generation IGCC EGUs). The 

EPA has provided its rationale for the use of permits for IGCC EGUs under construction in the record 

(see, e.g., 77 FR 9394). For other subcategories, the EPA is not aware of a universal set of permits that 

contain consistent information and/or data that could be used to set nationwide emission limits. For 

example, many Hg permits contain provisions whereby the source may return to the permitting agency 

after a period of time and renegotiate the permit level if the original level was determined to be 

unachievable. Other permits only required the use of a certain level of ACI injection with no emission 

limit stipulated. For other HAP, there are only a limited set of permits (e.g., HCl). Thus, the EPA 

determined to only use permits for the new source IGCC limits. 

Comment: Commenter (20308) stated that EPA’s use of data from the only two IGCC EGUs operating 

in the United States misrepresents the design and potential performance of future IGCC EGUs. The 

Commenter stated that if the final reconsideration rule remains applicable to IGCC EGUs, then EPA 

should consider a broader scope of IGCC technologies, the inherent uncertainties with technology 

development, and the use of first-of-a-kind technologies for new IGCC EGUs. The Commenter noted 

that the air permits used for proposed MATS standards for IGCC EGUs are for facilities that have not 

begun operation. 

Response: In response to comments on the proposed MATS rule that application of emission limits for 

IGCC EGUs based on those of pulverized coal EGUs was inappropriate and that the use of permit levels 

from IGCC EGUs was preferable, the EPA followed this new approach at final. The reconsideration of 

the IGCC EGU limits served to address a notice-and-comment issue. The Commenter has not provided 

any information to suggest where outside the subcategory (i.e., the two existing IGCC EGUs or permits 

for IGCC EGUs under construction) the EPA should look to consider “a broader scope of IGCC 

technologies” in establishing IGCC EGU emission limits or how the EPA’s use of permits for IGCC 

EGUs under construction is not “representative of both current technologies and of IGCC EGUs that 

will be built in the near-term future” (77 FR 9394). The Commenter has not provided any new 

information that was not available at final. The issue of the use of only two data points for existing 

IGCC EGUs was addressed at final (see, e.g., RTC, Vol. 1, pp. 482 - 483) and was not an issue subject 

to reconsideration. 

2.4.1 Sulfur dioxide (4.0E-01 lb/MWh) 

Comment: Commenter (20299) asked that the MATS eligibility requirement for IGCC to use SO2 as an 

alternative for HCl be clarified. The Commenter stated that IGCC EGUs do not employ flue gas 

desulfurization (FGD) as flue gas strictly pertains to the final product of combustion which for an IGCC, 

is that at the HRSG stack following the gas turbine. The Commenter noted that an IGCC EGU is the 

combined cycle gas turbine using solids derived fuel (syngas). The Commenter stated that for IGCC, 

acid gas control is outside of the scope of the EGU with all of the scrubbing of acid gas species (SO2, 

HCl) performed prior to the EGU. The Commenter stated that requiring the use of an FGD would 

essentially constitute a polishing step which is neither practical nor economically justified because the 

primary control is designed to be adequate to meet the HCl and corresponding alternative SO2

performance standard. 
57 

Commenter (20299) recommended that the proposed provision be modified to read as follows: 

For coal-fired and solid oil-derived fuel-fired units that employ FGD technology and new 

or reconstructed IGCC units that employ FGD technology and elect to meet the 

alternative SO2 limit in place of the HCl limit, you need not conduct an initial stack test 

for HCl or SO2. Instead, the 30 boiler operating days of data collected with the certified 

SO2 CEMS by the initial compliance demonstration date specified in § 63.10005 are used 

to determine initial compliance, and the SO2 CEMS is used thereafter to demonstrate 

continuous compliance. 

Response: The EPA agrees that some clarification is warranted and has included the appropriate 

language in footnote 3 of table 1 to subpart UUUUU of Part 63. 

2.5 Solid oil-derived fuel-fired EGU 

Other pollutant standards 

Comment: Commenter (20286) stated that although the EPA has not proposed revisions to the HCl 

emission standard for new petroleum coke-fired EGUs, the Commenter questioned the EPA’s HCl 

MACT floor analysis for the petroleum coke-fired subcategory. The Commenter stated that the new 

EGU floor for HCl was set by AES Deepwater in Houston, Texas (the only conventional boiler included 

in the data set for the MACT floor analysis of petroleum coke-fired EGUs), whereas the other seven 

EGUs included in the data set are FBC EGUs. 

Commenter (20286) stated that AES Deepwater’s HCl emission performance does not appear 

representative of the petroleum coke-fired EGU category because of its design and the low chlorine 

content in its fuel. The Commenter urged the EPA to reevaluate the petroleum coke-fired EGU MACT 

analysis for HCl and select an EGU that is more representative of the category. The Commenter stated 

that the EPA excluded certain EGUs for similar reasons from the Hg MACT analysis for coal-fired 

EGUs and the fPM MACT analysis for petroleum coke-fired EGUs. 

Response: This issue is outside the scope of this rulemaking. Subcategorization was addressed in the 

final rule (see, e.g., 77 FR 9378 - 9379, 9394 - 9402). This issue was not one of the issues being 

reconsidered and the EPA did not solicit comment in the reconsideration proposal on additional 

subcategories, including subcategorizing solid oil-derived fuel-fired EGUs. 

Calculation of standards 

Comment: Commenter (20273) stated that EPA’s reliance on limited short-term testing data has not 

been adequately corrected in the reconsidered MATS for solid oil-derived fuel EGUs. The Commenter 

stated that although EPA has reconsidered the promulgated MATS and proposed slightly less stringent 

limits for solid oil-derived fuel EGUs based on additional data, the EPA has not corrected the flaws in 

its methodology stemming from an inadequate data set and unsupported extrapolation of its limited data. 

The Commenter noted that the EPA’s upper prediction limit (“UPL”) analysis cannot predict a facility’s 

continuous emissions performance based on an hours-long emissions test, unless that test is 
58 

representative of continuous performance. The Commenter continued that because EPA continues to 

exclude data from its calculations of standards, the revised solid oil-derived fuel limits are still too low. 

The Commenter said it is axiomatic that EPA’s statistical analysis is only as valid as the data that 

supports it and EPA does not have sufficient data available from 100 percent solid oil-derived fuel-fired 

EGUs across varying operational conditions to form a basis for MATS for these facilities. The 

Commenter stated if EPA is determined to set limits for solid oil-derived fuel EGUs, the EPA should set 

the solid oil-derived fuel standards at the same reconsidered limits as it has proposed for new coal EGUs 

not designed for low rank coal (hereinafter referred to as “coal”) because the same considerations 

expressed by EPA in setting the coal standards, including fuel content variability, control performance, 

measurement constraints, and operating condition variations are present for EGUs using only solid oilderived fuel. The Commenter said, in short, the EPA’s failure to give equal consideration to solid oilderived fuel-fired EGUs as coal EGUs is arbitrary and EPA should adjust the standards applicable to 

petroleum coke fueled EGUs, such as the LBEC, to the reconsidered MATS applicable to coal EGUs. 

The Commenter stated that there is no reasoned justification for disparate treatment. 

Response: The issue of the use of short-term emission test data to establish 30-day rolling average 

emission limits was addressed in the final RTC (see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 

500, and 549 - 551). Further, the Commenter has not identified the data alleged to have been excluded 

so the EPA cannot address that comment. In any case, the Agency maintains that the approach to 

accounting for variability is valid for the reasons set forth in MATS record. The Commenter has also 

failed to explain how solid oil-derived fuel fired EGUs are sufficiently similar to low-rank virgin coalfired EGUs and, in any case, the EPA did not open this issue for reconsideration. 

Comment: Commenter (20273) disagreed with the EPA’s accounting for variability through the RDL 

multiplier. 

Response: This issue is outside the scope of this rulemaking. Comments concerning EPA’s accounting 

for variability through the RDL multiplier were raised in public comments submitted in response to the 

May 3, 2011, proposed MATS rule (76 FR 24976). The EPA’s responses to the comments are in the 

RTC (see, e.g., Vol. 1, p.523). 

2.5.1 Filterable PM (3.0E-02 lb/MWh) 

Comment: Commenter (20273) stated the reconsidered MATS for solid oil-derived fuel for fPM is too 

stringent. The Commenter stated that although the new proposed fPM emission limit for new solid oilderived fuel-fired EGUs is higher than the limit of 2.0x10-2 lb/MWh in the promulgated MATS, it is still 

much lower than what has been guaranteed by qualified vendors in practice. The Commenter noted that 

once EPA reconsidered the fPM limit for coal, it proposed a limit that is three times higher (9.0x10-2

lb/MWh) than the newly proposed limit for solid oil-derived fuel-fired EGUs. The Commenter stated 

that because the same technology (i.e., fabric filtration) is accepted as the best technology for control of 

fPM emissions for both types of EGUs, the difference in the standards cannot be justified on a 

technological level and evidences that EPA has not taken into consideration that the control technology 

functions with essentially the same level of control for both coal and solid oil-derived fuel. 

Commenter (20273) stated that the reconsidered MATS coal fPM proposed limit has been guaranteed by 

equipment manufacturers and has been achieved in practice. The Commenter stated that in discussions 
59 

with equipment vendors, vendors explained that they are providing operator-acceptable guarantees for 

fPM at levels at approximating the reconsidered coal MATS of 0.01 lb/MMBtu and could provide a 

similar operator-acceptable guarantee in that range for a petroleum coke fueled EGU. The Commenter 

added that given the relative difference in the number of coal EGUs likely to be proposed versus the 

number of solid oil-derived fuel-fired EGUs, it is unlikely that vendors will be incentivized to develop a 

different performance level for 100 percent petroleum coke fueled EGUs. 

Commenter (20273) said that even if a vendor were to offer an initial performance warranty, typically 

12 to 18 months, the challenges in maintaining the proposed fPM limit to an operator that come later in 

the life of an EGU as the controls wear and the EGU degrades are significant. The Commenter stated 

that the proposed solid oil-derived fuel-fired EGU reconsidered fPM MATS would effectively preclude 

new 100 percent petroleum coke fired EGUs from being proposed and constructed. 

Response: The EPA disagrees with the Commenter’s assertions. The revised fPM limit was based on 

review of the performance of solid oil-fired EGUs and their control devices, and is independent of the 

review of the performance of coal-fired EGUs or their control devices. The statute does not allow 

emissions limits to be established based on perceived control capabilities or EGU market share. The 

EPA agrees with the Commenter that EGU owners or operators need to be cognizant of potential control 

device and process degradation and ensure that the EGU continues to meet emissions limitations. 

2.5.2 Sulfur dioxide (1.0 lb/MWh) 

Comment: Commenter (20273) stated that with the alternative limit for SO2 emissions as a surrogate 

for compliance with the HCl MATS appropriately raised from 0.4 to 1.0 lb/MWh in the proposed 

reconsidered MATS for solid oil-derived fuel-fired EGUs, the Commenter stated that compliance with 

the reconsidered MATS is possible. The Commenter stated that one vendor contacted explained that 

using compliance with the revised SO2 standard as a surrogate for compliance with the HCl MATS is 

feasible and can be guaranteed. The Commenter consequently stated that the reconsidered MATS for 

SO2 emissions as a surrogate for compliance with HCl emissions standard can be supported by vendor 

guarantees. 

Response: This comment requires no response. 

2.6 Liquid oil-fired EGU – continental 

2.6.1 Filterable PM (4.0E-01 lb/MWh) 

Comment: Commenter (20293) stated that EPA’s proposed new source MACT limit for fPM for liquid 

oil-fired EGUs (4.0 x 10-1 lb/MWh) is higher than the adopted existing source limit for this category (3.0 

x 10-1 lb/MWh) and which remains unchanged by this proposal. The Commenter stated that an error of 

this magnitude demonstrates once again that EPA’s statistical methodology is flawed as described in this 

and earlier comments. The Commenter stated that in the past, the EPA has attempted to use the agency’s 

“beyond the floor authority” to establish a new source limit that is at least as stringent as the limit 

applicable to existing sources, but does not propose to do so in this rulemaking. 

Response: The EPA has adjusted the limit proposed in the reconsideration notice to the more stringent 
60 

level of the existing-source limit in this final rule for the reasons set forth in the record (see, e.g., final 

MATS MACT Floor Memo, Docket ID EPA-HQ-OAR-2009-0234-20132 – “Additionally, similar to 

the approach used in the HMIWI rulemaking, if the emission limit for new sources was less stringent 

than the emission limit for existing sources in the same subcategory, the EPA decided to use existingsource limits for new sources.”). Although CAA section 112(d)(3) allows existing source MACT floor 

limits to be less stringent than new source limits, the EPA interprets this provision as precluding new 

source limits from being less stringent than existing source limits. See CAA section 112(d)(3). Thus, the 

EPA is finalizing new source limits that are equivalent to the final existing-source limits. The new 

source limit for fPM from liquid oil-fired EGUs in the continental subcategory has been corrected to the 

existing-source limit of 3.0 x 10-1 lb/MWh. 

2.7 Other 

Support for new limits 

Comment: Commenter (20241) expressed support for the revised standards for Hg, fPM and HCl. 

Commenter (20281, 5803) expressed support for the revised new source limits. 

Commenter (20296) expressed support for the new Hg limits. 

Commenters (29281 and 20282) stated that the revised new source limits make it likely that properly 

designed and equipped new EGUs will be able to meet the limits with at least one of the compliance 

monitoring options currently provided under the rule. 

Commenter (20282) expressed support for the new source limits in the proposed reconsideration rule as 

long as EPA provides appropriate compliance methods. 

Commenter (20265) stated that the EPA’s re-proposed new source limits appropriately reflect the use of 

the best control technology equipment available on the market. The Commenter agreed with EPA that 

these reconsidered limits do not represent a relaxation of the emissions control requirements originally 

promulgated in the MATS rule. The Commenter noted that as the EPA states, the same control 

equipment will be required to meet the reconsidered limits as would have been required to meet the 

limits promulgated in the MATS rule. However, the Commenter observed, the EPA has now estimated 

more accurately the emissions reductions the same emissions control equipment can actually achieve in 

practice. 

Commenter (20276) stated that in the final April 2012 MATS Rule, the EPA established limits for new 

EGUs that were too stringent. The Commenter said the limits could not be achieved by new EGUs and 

would not have been able to be measured adequately because the limits were set below the detection 

limits of monitoring devices/methods. The Commenter agreed with lowering the standards as EPA has 

done in this rule revision, to the extent that these limits can be achieved and measured consistently with 

current technologies. 

Response: The EPA understands that Commenter 20276 is referring to the February 16, 2012 (77 FR 

9304) final MATS rule and notes that the Commenters’ support for the reconsidered limits requires no 
61 

response. Comments on the ability to measure the limits are addressed elsewhere in this document. 

Compliance demonstration – Hg limits 

Comment: Commenters (20281, 20282, and 20296) expressed concern that the proposed Hg limits are 

not achievable in all circumstances. The Commenters stated that Hg sorbent trap monitoring systems can 

reliably demonstrate compliance, but the proposed Hg limits are too low for Hg CEMS. 

Commenters (20281 and 20282) cited Hg CEMS research supported by the EPRI and the U.S. DOE, and 

stated that the two most prominent Hg CEMS monitors have level of quantifications of 0.3 and 0.5 

μg/m3

, which are values at or above the proposed limit. Commenter (20282) provided an attachment that 

stated that these levels of quantification are sufficient to disqualify Hg CEMS from consideration as a 

continuous compliance option. 

Commenter (20282) noted in Attachment 1 of their comment that the Hg emission limit is too low to use 

a Hg CEMS for compliance, but some owner/operators may choose to install a Hg CEMS to provide 

near real time feedback or process control information. 

Response: As mentioned earlier, if for a particular EGU, an owner or operator believes that a Hg CEMS 

cannot achieve the performance requirements needed to satisfy the final standards, the owner or operator 

may elect to install and use a sorbent trap monitoring system to monitor for continuous compliance. 

Moreover, in order to better track emissions and allow process control during transitional periods, such 

as load swings, an owner or operator may choose to use a more frequent sampling period, e.g., 30 

minutes, instead of several days, over short periods. An owner or operator is also free to use a Hg CEMS 

for control operations and use the sorbent trap monitoring for compliance if he feels that such 

operational data is sufficiently critical to the EGU’s control operations. As noted in the Reconsideration 

proposal, the EPA believes the proposed change in the non-low rank virgin Hg limit for new EGUs will 

also allow the option of using a Hg CEMS for process control and for determining compliance based on 

information provided by the Commenters, our experience, and the NIST’s recently confirmed capability 

to certify Hg calibration gas generators down to 0.2 μg/m3

. 

Comment: Commenters (20281 and 20282) noted that the EPA has set the performance criteria for the 

permissible inaccuracy of a RATA and the quarterly linearity check at levels several times higher than 

the 0.3 μg/m3

 limit for Hg emissions. The Commenters concluded that one of the two methods 

designated by EPA for demonstrating compliance with the new source Hg limits is unable to measure 

emissions accurately at the proposed limit. The Commenters discussed the differences between a Hg 

carbon trap system and a Hg CEMS. The Commenters stated that a carbon trap system does not provide 

real-time feedback on an EGU’s level of Hg emissions, and that it is impractical to conduct 30-minute 

sorbent trap runs as EPA assumed in setting the new source Hg limit. 

Commenter (20282) cited in Attachment 1 of their comment a power plant study, in which it was 

observed that the 24-hour zero drift of the Hg CEMS monitors could commonly be 0.2 μg/m3

. The 

Commenter noted the difficulty of a 24-hour zero drift that is two-thirds of the emission limit. They also 

noted that the allowable Hg CEMS error of the quarterly linearity check is greater than the proposed 

new-EGU limit of approximately 0.3 μg/m3

. 
62 

Response: The EPA recognizes the concerns with the performance criteria for Hg CEMS identified by 

the Commenters, and will consider tightening the criteria in the future. Based on information provided 

by the Commenters, our experience, and the NIST’s recently confirmed capability to certify Hg 

calibration gas generators down to 0.2 μg/m3

, the EPA believes some Hg CEMS may be used for 

determining compliance with the final new source Hg limit. 

Comment: Commenters (20281 and 20282) recommended that the Hg standard for new EGUs of 5 x 

10-3 lb/GWh would allow EGUs flexibility in demonstrating compliance using either a Hg carbon trap 

system or a Hg CEMS to show continuous compliance with the MACT limit. 

Response: As mentioned earlier, based on information provided by the Commenters, our experience, 

and the NIST’s recently confirmed capability to certify Hg calibration gas generators down to 0.2 μg/m3, 

the EPA believes some Hg CEMS may be used for determining compliance. Should a particular EGU, 

an owner or operator believe that a Hg CEMS cannot achieve the performance requirements needed to 

satisfy the final standards, the owner or operator may elect to install and use a sorbent trap monitoring 

system to monitor for continuous compliance. Moreover, in order to better track emissions and allow 

process control during transitional periods, such as load swings, an owner or operator may choose to use 

a more frequent sampling period, e.g., 30 minutes, instead of several days, over short periods. An owner 

or operator is also free to use a Hg CEMS for control operations and use the sorbent trap monitoring for 

compliance if he feels that such operational data is sufficiently critical to the EGU’s control operations 

and shorter sorbent trap sampling times are not practical. 

Comment: Commenter (20296) stated that the sorbent trap monitoring system can provide a reasonable 

measure of compliance and should continue to be an option in the final rule; however, the sorbent trap 

monitoring system does not necessarily provide the type of process control feedback that some operators 

will need to actively manage their Hg emissions to the very low levels required under MATS. The 

Commenter stated that the final rule should ensure that CEMS will be a feasible option for 

demonstrating compliance with the new source Hg limits. The Commenter stated that the Hg limit 

should be further adjusted to allow the use of CEMS and should not delay the issuance of a final rule. 

Commenter (20296) stated that if EPA does not increase the Hg limit and instead promulgates a limit 

that cannot be reliably detected with a CEMS, the final rule should provide that sources electing to 

demonstrate compliance with that limit using a sorbent trap cannot be held to violate the MATS rule 

based on CEMS data that they may generate. The Commenter noted that this is an important point 

because even those electing to demonstrate compliance with a sorbent trap may nevertheless elect to 

install a CEMS to monitor emissions or may be required to do so by permit terms or other rule 

requirements that set higher Hg limits. The Commenter stated that without this qualification, these 

sources’ CEMS emissions data could conceivably be argued to constitute “credible evidence” of a 

violation. 

Response: The EPA agrees with the Commenter that sorbent trap monitoring can be a useful means of 

demonstrating compliance, but as mentioned earlier, disagree that sorbent trap monitoring does not 

necessarily provide the type of process control feedback that some Commenters desire, particularly over 

the short-term. The EPA notes that Hg CEMS or any other type of data relevant to compliance with the 

emissions limit may or may not be found to be credible evidence of compliance or violation, as the 

determination of whether data provide credible evidence of a violation of a standard is an issue beyond 
63 

the scope of this rulemaking, and is a matter for a court to determine in a specific proceeding. Generally, 

under the CAA, the EPA (and other agencies with enforcement authorities) has the authority and the 

ability to determine whether any data constitutes credible evidence of a violation. Also, responsible 

officials that certify compliance must make that certification on the basis of all available information. 

Nothing in this rule affects those underlying provisions. 

Compliance demonstration – other pollutants 

Comment: Commenter (20255) stated that EPA should retain the quarterly testing option for HCl as 

CEMS for HCl are not viable for all EGUs and data are lacking on the reliability and accuracy of CEMS 

at the established emission limits. Given that EPA acknowledges that HCl monitors are not currently 

commercially available but are expected within 3 years, the Commenter stated that EPA should not issue 

rules with the expectation that industry and vendors will find a way to develop technology to meet 

compliance deadlines. The Commenter stated that quarterly testing may be the most economic 

compliance demonstration method for many EGU at an annual cost, on average, of $50,000. 

Response: The subject of this comment is not within the scope of this rulemaking; therefore, no 

response is necessary. That said, the EPA disagrees with the Commenters’ contention that continuous 

HCl monitoring is premature or not available for the measurement at the limits set in the proposed 

standard; however, the rule provides several options for HCl monitoring including: 1) using HCl CEMS 

for compliance, 2) seeking approval for an alternative HCl monitoring procedure through section 

63.7(f), 3) monitoring SO2 continuously as a surrogate for HCl at facilities equipped with wet scrubber 

control technology for SO2, 4) quarterly reference method testing, and for certain liquid oil-fired EGUs, 

5) use of fuel moisture measurements as an alternative to HCl monitoring. Including these options in the 

rule provides flexibility to adopt CEMS monitoring options as the technology continues to mature and 

EPA performance specifications become available. 

Comment: Commenter (20254) stated that the lack of reliable HCl CEMS will necessitate that EGUs 

without SO2 controls perform quarterly stack testing to show compliance with the HCl limit. 

Response: The subject of this comment is not within the scope of this rulemaking; therefore, no 

response is necessary. As mentioned earlier, however, the EPA disagrees with the Commenters’ 

contention that continuous HCl monitoring is premature or not available for the measurement at the 

limits set in the proposed standard. As the Commenter notes, the rule allows the compliance 

determination option of quarterly performance testing, and that provides flexibility to initially comply in 

that manner and to adopt CEMS monitoring options as the technology continues to mature and EPA 

performance specifications become available if the source determines it is appropriate. 

Comment: Commenter (20295) stated that the reconsideration proposal would revise many of the new 

source standards to levels that are more in line with what is achievable by some of the newest coal-fired 

EGUs. But, the Commenter stated that there are concerns that all existing measurement technology 

options may not be adequate to demonstrate continuous compliance with the MATS for new EGUs, 

particularly the revised Hg standards. 

Commenter (20282) expressed concern that the proposed limits are not achievable in all circumstances, 

stating that demonstrating actual compliance may not be achievable. The Commenter cited discussion in 
64 

an attachment in their comment (20282, Attachment 1) regarding compliance issues. 

Response: The first Commenter expresses specific concerns about the Hg emission limit and mentions 

repeating its generic concerns over emissions limits provided in comments on the proposed rule. The 

second Commenter expresses specific concerns about the Hg and PM emissions limits. As mentioned in 

the Preamble to the final rule and RTC (see 77 FR 9389/3, February 16, 2012; 77 FR 9390/1,2, 77 FR 

9391/3; and RTC, Vol.1, pp. 522 - 524), the EPA believes every emissions limit has been designed so 

that it can be measured with an acceptable level of accuracy with at least one compliance approach. As 

mentioned earlier, if for a particular EGU, an owner or operator believes that a Hg CEMS cannot 

achieve the performance requirements needed to satisfy the final standards, the owner or operator may 

elect to install and use a sorbent trap monitoring system to monitor for continuous compliance. As 

mentioned later, an EGU owner or operator who believes PM CEMS may not be sufficient to 

demonstrate compliance for his EGUs may choose to use a PM CPMS instead. The EPA notes that the 

latter Commenter analyzed about 6 months of data from three PM CEMS, all of which had successful 

correlations according to PS-11, found no exceedances of the new EGU emission limit, thus showing for 

that EGU, PM CEMS worked very well (see EPA-HQ-OAR-2009-0234-20282, Attachment 8, page 3).

Comment: Commenter (20286) claims that the EPA has made significant errors in determining the 

method RDL values in the TSD entitled Data and procedure for handling below detection limit data in 

analyzing various pollutant emissions databases for MACT and RTR emission limits (Docket ID EPAHQ-OAR-2009-0234-20062) by failing to consider the effect of additional moisture vapor condensation 

that occurs when Method 26A test runs collecting 3 to 4 dry standard cubic meters (dscm) of sample gas 

are conducted to demonstrate compliance with the new petroleum coke HCl standard. The Commenter 

asserts that in the RDL determination for Method 26A for HCl and chlorine (Cl2), the EPA assumed a 

total mass RDL for a Method 26A test of 60 micrograms (μg), which the Commenter presumes is 

calculated using the documented analytical detection limit in Method 26A of 0.2 μg/ml and the impinger 

volume of 300 milliliters (ml) assumed in Section 13.3 of Method 26A. This impinger volume appears 

to be based on a relative gain of approximately 100 ml of liquid from moisture vapor condensation in the 

impingers, occurring over a sample collection volume of 1 dscm. The Commenter believes that 

significantly more liquid will be gained from moisture vapor condensation for test runs collecting 3 or 4 

dscm of sample gas necessary for demonstrating compliance with the new petroleum coke-fired EGU 

standard and that because the analytical procedures of Method 26A do not allow concentration or 

extraction of the impinger solution before analysis as some other EPA methods (e.g., Method 29), the 

RDL value assumed by the EPA is biased low. 

Commenter (20261) claims the volume of moisture data submitted by a liquid oil-fired EGU in response 

to the Information Collection Request (ICR) is not consistent with the volume that the Commenter 

believes should have been reported, and the Commenter recommends the EPA follow up on the data. 

The Commenter also suggests the use of Method 26A on wet stacks is problematic, in that the increased 

stack gas moisture leads to greater capture of condensed water and to elevated detection levels for HCl 

and HF. 

Response: Neither the HCl nor the HF limit for solid oil-derived fuel-fired EGUs was among the limits 

revised and proposed for comment in the reconsideration notice. As such, the issue falls outside the 

scope of this rulemaking and no response is required. In any event, the EPA cannot ascertain that the 

RDL value was determined in error based on the information provided by the Commenters. Moreover, 
65 

the EPA disagrees with the Commenter that additional investigation of the data need occur: the EPA 

used the data collected, submitted, and certified by EGU owners or operators as being accurate for their 

EGUs. Should a solid oil-derived fuel-fired EGU owner or operator believe HCl or HF CEMS incapable 

of providing accurate measurements for compliance purposes, the owner or operator can choose to use 

quarterly testing, along with continuous monitoring of one or more parameters. Further, as Commenter 

notes, EGUs with add-on SO2 controls and SO2 CEMS are eligible for the alternate SO2 emission limit. 

 

Comment: Commenter (20308) stated that the Reconsideration Rule limits will require an operator to 

test below a limit one time and then test above the limit the next without knowing what actions to take to 

change the emission rate. The Commenter stated that when emission limits become so stringent that they 

are below the levels that can be measured with current testing methodologies (as the proposed limits 

are), the ability to effectively manage known and controllable variables in operating conditions and fuel 

quality is effectively eliminated. The Commenter stated that the risk of non-compliance due to unknown 

and uncontrollable variables, especially for elements present in trace quantities for which no detailed 

operational history exists, is significantly increased. The Commenter stated that the new source emission 

limits in the proposed rule are so low that they do not accommodate the full range of EGU operating 

conditions, and currently available monitoring methods lack the precision and accuracy necessary to 

confidently assure compliance. 

Commenter (20308) stated that 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. The Commenter stated that the EPA should give greater consideration to the diversity of 

issues that impact the emissions from coal-based generation and to the process that state agencies have 

undertaken to issue air permit limits so that the final rule contains MACT standards that are practical 

and achievable. The Commenter suggested that the resulting new source limits in the final 

Reconsideration Rule should be designed with greater flexibility so that sources can have reasonable 

assurance that compliance can be achieved across the entire range of operations an EGU would 

experience. 

Response: The EPA disagrees with the Commenter’s assertions regarding emission limits being so 

stringent that they are below the levels than can be measured with current testing methodologies and 

emission limits not providing sufficient operational flexibility. As mentioned in the preamble to the final 

rule and in the RTC, the emission limits have been designed so that the higher of the 3XRDL approach, 

which ensures values can be measured accurately, or the 99 UPL approach, which takes operational 

variability into account, is used. Therefore, the emissions limit accounts for both measurement and 

operational uncertainty. The EPA notes that responses to similar comments on our approach to 

developing the MACT standards were prepared and can be found in Section VII.A., MACT Floor 

Analysis of the final MATS preamble, and the RTC (see 77 FR 9389/3, February 16, 2012; 77 FR 

9390/1,2; 77 FR 9391/3; RTC, Vol. 1, pp. 522 - 524). The Commenter presents no new information that 

requires further response. 

Calculation of standards 

Comment: Commenter (20293) recommended that EPA provide a more transparent and robust 

explanation for its methodology and data used in determining applicable MACT floor, which is 

particularly crucial in instances where the new source floor is higher than the existing source floors. The 
66 

Commenter stated that based on their general experience with existing facilities, that some increase in 

several of the final limits for new facilities may be warranted, any such increase should be based on the 

performance of the best facilities and control devices. The Commenter stated that due to the short 

comment period, the Commenter has not attempted to examine either the engineering or the long-term 

emission test results of specific “best-performing plants” in each of the subcategories to determine the 

extent to which the reported test results are consistent with the long-term performance of those plants or 

the technologies that have been employed. The Commenter recommended that EPA undertake such an 

effort before making a final decision on the proposed reconsideration of the standard. 

Commenter (20293) stated that EPA has not provided a rationale that can be evaluated to determine 

whether the proposed MACT levels are appropriate. The Commenter stated that the approach utilized by 

EPA several years ago (where it evaluated the performance of the best available technology) produced a 

more reliable result than the agency’s current reliance on a method that is overly sensitive to a small 

number of statistics. The Commenter stated that the Court rejected the earlier EPA approach, not 

because of its consideration of technology, but because the agency did not consider best-performing 

EGUs that did not employ a technology. The Commenter stated that in this source category all of the 

best-performing EGUs employ technologies; some also use cleaner fuels. The Commenter urges EPA to 

evaluate in detail the plants that show the best, consistent performance and determine the factors that led 

to this performance. The Commenter stated that EPA should then evaluate whether those factors are 

unique to that plant, or are of general applicability. The Commenter stated that EPA should then use 

year-over-year data of better performing plants to apply an objectively determined compliance margin 

for those plants. The Commenter stated that this compliance margin should then be applied to the best 

performing plant to establish the new source MACT. 

Response: The EPA disagrees with Commenter’s assertion that an adequate explanation of its 

methodology and data used was not provided for the proposed reconsideration. The EPA believes the 

discussion in the reconsideration proposal preamble (77 FR 71323) and reconsideration MACT floor 

memo (Docket ID EPA-HQ-OAR-2009-0234-20220) adequately describe and explain its methodology. 

Further, the EPA disagrees with Commenter’s assessment of the Court’s decision and believes it has 

followed both the statute and the Court’s mandate in its approach. The approach suggested by the 

Commenter is not compelled by either the statute or applicable case law. The EPA maintains that its 

approach to establishing MACT standards is reasonable as explained in the rulemaking record. 

Comment: Commenter (20296) stated that the EPA has not rectified all of the flaws of the final MATS 

standards. The Commenter stated that EPA continues to use short-term “snap shot” test results to 

establish standards that must be met continuously and over the long-term. The Commenter attached a 

court brief in the White Stallion case explaining that these short-term data are not representative of longterm performance. The Commenter stated that on reconsideration, although EPA uses data from 

different EGUs than it used to establish the limits in the initial MATS rule, that data still comes from the 

short-term ICR stack tests, and the Commenter reasserted their argument that the EPA is relying on 

unrepresentative data that results in overly stringent standards. 

Response: The issue of the use of short-term emission test data to establish 30-day rolling average 

emission limits was addressed in the final RTC (see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 

500, 549 - 551). The EPA maintains that its approach is reasonable and adequately accounts for 

variability for the reasons set forth in MATS record. 
67 

Comment: Commenter (20305) stated that the reconsidered standards are unlawful and arbitrary. The 

Commenter provided discussion with citations to court cases, supporting the assertion that CAA 

§112(d)(3) requires that EPA’s standards for new sources be “no less stringent than the emission control 

that is achieved in practice by the best controlled similar source,” the EPA’s proposed floors do not 

reflect the emission levels achieved by the best performing EGU, and the EPA has not demonstrated that 

they are reasonable estimates of such emissions levels. 

Response: The EPA does not agree that the approach for selecting the best performing source suggested 

by the Commenter is mandated under the statute and EPA maintains that its approach is reasonable. 

CAA section 112(d)(3) requires the EPA to establish the new source limits based on the performance of 

the best controlled “similar source.” The statute does not define the term “similar source” and, for that 

reason, the Agency has discretion to evaluate the sources for which the Agency has data and make a 

selection as long as the Agency has a reasoned basis for it selection. The EPA acknowledges that there 

are various approaches that can be used for selecting the “best performer.” However, for consistency the 

EPA has used the same approach as was used at both proposal and final – i.e., ranking of sources based 

on their lowest 3-run average. The EPA decided upon this approach of selecting the “best performing” 

sources on the premise that the lowest 3-run average was indicative of the best the source could perform; 

the additional data from the sources in the MACT floor pool were then used to assess variability. Issues 

with this approach were not raised in comment on the proposed MATS rule. 

Comment: Commenter (20293) stated that EPA has not to date provided an objective rationale for the 

99th percentile, as opposed to the 99.9th percentile, the 90th percentile or any other choice and they urge 

EPA to do so in the final rule. 

Response: The use of the 99th percentile was addressed in the RTC document (Docket ID EPA-HQOAR-2009-0234-20126; see, e.g., Vol. 1, pp. 490 - 491, 508). This issue was not one of the issues being 

reconsidered and the EPA did not solicit comment in the reconsideration proposal regarding the use of 

the 99th percentile in the analyses, but maintains that it is reasonable for the reasons set forth in the 

MATS record. 

Best performing 

Comment: Commenter (20293) stated that the procedure used by EPA to identify the best-performing 

sources that are the subject of the Reconsideration notice uses inconsistent definitions of the 

performance of the EGU. The Commenter stated that EPA uses the single best run to identify what it 

calls the best-performing EGU, but then uses all test runs, including test runs from tests conducted at 

other times, to determine the performance of the EGU. The Commenter stated that the best-performing 

plant is not the plant that has a single low test run because a single test run does not constitute an 

acceptable reference method test and provides no measure of the consistency in the performance of that 

plant that is then employed in the standard-setting process. 

The Commenter stated that the best-performing source is the plant that demonstrates the lowest 

consistent performance on the basis of all available testing, which should include at least one full 

Federal Reference Method (FRM) test with the three test runs that are required for such testing. The 

Commenter stated that new source MACT floor calculations are particularly susceptible to high 
68 

statistical variability under the procedure employed by EPA because there may only be one or two FRM 

tests of the better performing EGUs. The Commenter stated that EPA’s inconsistent process for (1) 

identifying the best-performing EGU and (2) calculating the performance of that EGU leads to selection 

of EGUs whose emissions are variable and, on average, high, rather than the EGU that demonstrates the 

best consistent performance. 

Commenter (20305) stated that the EPA was inconsistent in its approaches to calculating the revised 

standards and to selecting the best performing plants for its floors. The Commenter stated that if, as the 

Agency claims, the “emission control...achieved in practice by the best controlled similar source” is best 

estimated by a UPL applied to all stack tests in the Agency’s record, the “best controlled similar source” 

must be the plant with the lowest emissions, by that measure of “emission control.” The Commenter 

added that by that measure of emission control, the Agency’s proposed “best performers” are not the 

plants with the lowest emissions. The Commenter cited the November 15, 2012 Reconsideration Floor 

Memorandum. The Commenter discussed how specific plants’ emissions determined by the EPA’s 

UPL-adjusted, all-tests method, that are lower than the Agency’s proposed standard, and provided 

summaries of UPL calculations in several attachments. The Commenter stated that if the “emission 

control achieved in practice” by the best performing plant is best estimated by that plant’s single, lowest 

stack test, its standards must, in turn, be based on that measure of emission control (rather than the 

“pooled UPL variance” used by the Agency to generate its standards). 

The Commenter concluded that the EPA has not met CAA §112’s requirements; by its measure of the 

emission control achieved in practice – an Upper Prediction Limit of all stack tests in EPA’s data-set – 

its limits do not reflect the emission control of the best performing source. 

Response: As noted elsewhere in this document, the EPA used the same approach for selecting the “best 

performing similar source” in the proposed reconsideration as was used at proposal and final. That is, 

the EPA selected the MACT floor pool of EGUs based on their lowest 3-run emission test result and 

then incorporated any other data from these floor EGUs into the variability analyses. Where only a 

single 3-run average data point was available, the individual run data were used. 

CAA section 112(d)(3) requires the EPA to establish the new source limits based on the performance of 

the best controlled “similar source.” The statute does not define the term “similar source” and, for that 

reason, the Agency has discretion to evaluate the sources for which the Agency has data and make a 

selection as long as the Agency has a reasoned basis for it selection. In this case, the EPA acknowledges 

that there are various approaches that can be used for selecting the “best performer,” including that 

noted by the Commenter. However, for consistency the EPA has used the same approach as was used at 

both proposal and final – i.e., ranking of sources based on their lowest 3-run average. The EPA decided 

upon this approach of selecting the “best performing” sources on the premise that the lowest 3-run 

average was indicative of the best the source could perform; the additional data from the sources in the 

MACT floor pool were then used to assess variability. Issues with this approach were not raised in 

comment on the proposed MATS rule. As discussed in the final MATS MACT Floor Memo (Docket ID 

EPA-HQ-OAR-2009-0234-20132), there were situations for some pollutants where only a single test 

average and no individual run-level data were available for the EGU identified as the best-controlled 

source. In these cases, no emission variability could be determined based on a single data point. 

Therefore, the next best-controlled similar source with sufficient data to account for variability was used 

to determine the new source MACT. 
69 

Achievability 

Comment: Commenter (20308) stated that the proposed standards erroneously rely on short-term test 

results that are not representative of what has been or can be achieved in practice for the range of 

reasonably expected operating conditions experienced over the life of the EGU. The Commenter 

suggested that the EPA obtain additional data to establish standards that can be achieved on an ongoing 

basis by the best performing EGUs, or revise the standards to address the full range of operating 

conditions, especially when attempting to regulate substances present in trace quantities and for which 

control performance can more strongly be influenced by unknown and uncontrollable factors. 

Commenter (20308) stated that the revised new source standards in the proposed Reconsideration Rule, 

although at a level that a modern well-controlled EGU could potentially achieve for certain periods, 

have not been demonstrated to be achievable across the range of operating scenarios expected over the 

life of an EGU. The Commenter referenced earlier comments for the proposed MATS rule for 

discussion of this issue. 

Commenter (20308) stated that a coal-based generating EGU is not a steady-state operation, and 

efficiency, performance, and emissions profile vary with operating conditions. Factors such as ambient 

conditions, the age of equipment, and changes in coal characteristics also influence operations. The 

Commenter stated that there is little operating data to base the HAP standards, and the ICR data was 

collected during stable full-load operations. 

Response: The issue of the use of short-term emission test data to establish 30-day rolling average 

emission limits was addressed in the final RTC (see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 

500, 549 - 551). This issue was not one of the issues being reconsidered and the EPA did not solicit 

comment in the reconsideration proposal regarding the use of short-term data. As mandated by CAA 

§112, the EPA has used the data available to it with which to establish the emission limits. These data 

reflect EGUs, and controls, of varying ambient conditions, age of equipment, and coal characteristics; 

thus, the EPA continues to believe that variability has been accounted for to the extent necessary and 

consistent with the statute. The Agency maintains that the approach to accounting for variability is valid 

for the reasons set forth in MATS record. 

Comment: Commenter (20308) stated that the most advanced controlled and the most stringently 

regulated existing coal-based EGUs have not been demonstrated to meet the proposed new source 

Reconsideration Rule limits across the range of operating scenarios expected over the life of an EGU. 

The Commenter stated that in prior comments, the Commenter included an analysis of 40 new coalbased generation projects which would be significantly challenged to meet all the proposed new source 

MACT standards based on the existing requirements in their air permits. The Commenter suggested that 

the EPA review CAA §112(g) case-by-case MACT determinations. 

Response: The Commenter’s repetition of comments it submitted in response to the proposed rule on 

emissions limits not subject to reconsideration are not relevant, and the EPA is not addressing them. 

Then, as now, the EPA disagreed with the Commenter, and responses to those comments can be found 

in the RTC to the proposed rule (see, e.g., Vol. 1, pp. 445, 451). Regarding the Commenter’s assertion 

that the proposed reconsidered emissions limits have yet to be demonstrated across the range of 
70 

operating scenarios expected over the life of an EGU, the EPA also disagrees. As explained elsewhere in 

this document, the EPA established emissions limits that take into account the potential variability, as 

expressed by these Commenters, such that the best-performing EGU is or EGUs are expected to be able 

to meet 99 times out of 100 times. The EPA has based the new source limits in the proposed MATS 

reconsideration on all of the data available to it; whereas many of the case-by-case determinations were 

based on a much more limited data set and in a different manner than required under section 112(d)(2) 

and (3), the EPA believes the reconsidered limits for new EGUs are achievable. 

Test methods 

Comment: Commenter (20261) stated that they reviewed the final MATS and proposed reconsideration 

emission limits for coal and liquid oil EGUs with respect to the capabilities of manual stack test 

methods. The methodology used in the review was the same as described in their comments on the 

proposed MATS rule. Considering only those limits that were revised in the reconsideration proposal, 

fPM, Hg, selenium, and Pb should be measurable for all coal EGUs with acceptable accuracy using 

standard EPA manual test methods. Hydrochloric acid (HCl) will be measurable at the beyond-the floor 

limit in most coal EGUs; however, it may not be measurable in wet stacks with very low emissions, due 

to dilution of the sample with condensed water. However, the Commenter asserts that the MATS rule 

includes limits on other substances and EGU types that were not addressed in the reconsideration 

proposal. Based on past work, the Commenter concluded that some of the regulated substances still may 

not be measured accurately at the proposed limits with present methods. The new EGU limits that are of 

concern are as follows: 

New Coal EGUs:

Non-Hg metals by EPA Method 29: arsenic, beryllium, cadmium 

New Continental Liquid Oil EGUs:

Mercury by EPA Method 30B 

Non-Hg metals by EPA Method 29: arsenic, beryllium, cadmium 

HCl and HF by EPA Method 26A 

New Non-continental Liquid Oil EGUs:

Mercury by EPA Method 30B 

HF by EPA Method 26A 

The Commenter (20261) stated that EPA attempted to account for method sensitivity by calculating 

RDLs and using those in some cases as MACT floors for the final Rule. However, for metals, the EPA 

derived the RDLs by multiplying published analytical detection limits for clean water samples by three. 

Based on the Commenter’s evaluation of the measurements performed for the ICR, reporting limits for 

the filter and impinger fractions of a Method 29 train are frequently much higher than the RDLs. 
71 

The Commenter (20261) stated that for Hg using Method 30B, the EPA adjusted the limit for new coal 

EGUs burning coal with a heating value > 8,300 Btu/lb to allow plant owners to collect half-hour 

samples with adequate method sensitivity. At the proposed emission limit, the amount of Hg collected 

on the first sorbent trap bed during a 30-minute sample with a 1 liter/minute flow rate will be 

approximately 10 ng. This amount can be measured accurately if the background Hg concentration in 

the sorbent is low. However, a footnote to the sampling requirements in the proposed rule (and in the 

Final MATS rule) states that the Method 30B estimated mass must be one-half of the target emission 

rate. The Commenter understands this to imply that the method must be capable of quantifying Hg at an 

emission rate of 0.0015 lb/GWh, or approximately 0.15 lb/TBtu. Assuming that Hg loading on the trap 

is proportional to sample volume, a longer sampling duration (e.g., 1 hour) or higher sampling rate (2 

liters/min) is required to achieve this level of sensitivity. The EPA should clarify this point in the final 

rule and consider allowing higher flow rates. 

The Commenter (20261) stated that EPA did not adjust Hg limits for other source types using the same 

approach; thus, very long sampling times will be required to measure accurately at the limits for new 

continental and offshore oil EGUs (approximately 3.5 and 14 hours, respectively). The Commenter 

recommends that EPA consider using the same approach to deriving the limit for all source types as was 

used for coal EGUs > 8,300 Btu/lb. 

The Commenter (20261) stated that for HCl measurements at liquid oil EGUs by EPA Method 26A, 

only one facility that participated in the ICR reported a detection limit below the limit for new 

continental oil EGUs, which is based on a calculated RDL of 4 x 10-5 lb/MMBtu. In fact, only one 

facility (East River, ORIS 2493) was represented in the EPA’s database as having HCl detection limits 

below the RDL. The Commenter reviewed the test report for that facility which the EPA did not have 

access to prior to the issuance of the Final Rule. The Commenter’s conclusion is that the data quality for 

those results is questionable. The tests were run at three times the normal sampling rate. The impinger 

volume collected (10-12 ml condensed moisture) is not consistent with the volume that should have 

been collected at the reported moisture content (7.5 percent) and sample volume (approximately 240 

dscf). The information in the test report is not sufficient to determine the reason for the discrepancy, but 

the Commenter recommends that EPA follow up on these data. The EPA did not report on the basis of 

the RDL calculation for HF; however, for measurements at both continental and non-continental liquid 

oil EGUs by EPA Method 26A, the same issue applies for HF as for HCl. 

As discussed in their previous comments, Commenter (20261) stated that the use of Method 26A on wet 

stacks is problematic for compliance monitoring, because, as observed in the ICR tests, increased stack 

gas moisture leads to greater capture of condensed water, and consequently to elevated detection limits. 

Another potential measurement issue is for EGUs that inject ammonia for flue gas conditioning or NOX

control; researchers have reported that ammonia salts formed in the stack gas can dissociate in the 

Method 26A impingers under some conditions to form HCl, thus creating a high bias for this parameter. 

This potential bias requires further investigation, and EPA should consider discussing it as a potential 

source of inaccuracy in the methods requirements in the final rule. 

Response: The EPA finds the Commenter agrees that the test methods are sufficient for the new coalfired EGU PM, Hg, Se, and Pb emission limits, the Commenter expresses concerns over the test method 

for new coal-fired HCl emission limits, and the Commenter acknowledges that its concerns over the test 
72 

methods for the other pollutant emission limits were not among the issues opened for reconsideration. 

The EPA also notes that it has reviewed and responded to similar concerns in the final rulemaking (see, 

e.g., RTC, Vol.1, Section 4A03, and Vol. 2, Section 5A). The EPA believes that our procedure for 

establishing the floor and the emissions limit ensures that the Methods identified in the rule, along with 

their requisite sampling times, are appropriate for determining compliance with the emissions limits. 

With respect to concerns about sampling rates or periods for Hg, the EPA notes that the value used 

represents what we believe can be achieved now; should an EGU owner or operator believe other 

sampling rates or periods are appropriate, he can increase the sampling period as desired and he should 

seek EPA approval before increasing the sampling rate. With respect to the concern about HCl detection 

levels, see the earlier response. 

Other 

Comment: Commenter (20305) disagreed with the EPA’s statement that new power plants would 

choose to install and operate the same or similar air pollution control technologies in order to meet the 

revised emission limits as would have been necessary to meet the previously finalized standards. The 

Commenter stated that emissions of toxic pollution depend not just on the control technology installed 

but also on the way the technology operated and maintained, the way the EGUs are operated and 

maintained, raw material inputs, and other factors. The Commenter stated that two sources with “the 

same or similar air pollution control technologies” can and often do emit different quantities of toxic air 

pollution at different rates. 

Response: The EPA disagrees with Commenter’s assertions and stands by its discussion in the 

reconsideration proposal preamble. Sources will have to be designed in a manner that assures 

compliance with the final rule and the Commenter has provided no data to support its assertions.
73 

3.0 BEYOND-THE-FLOOR (BTF) ANALYSIS 

Comment: Commenter (20305) stated that the EPA’s BTF analysis inexplicably and arbitrarily 

excludes reductions that the Agency already assumes facilities will be able to meet. The Commenter 

stated that the Agency has violated the Act. The Commenter disagreed with the EPA’s analysis of 

incremental cost effectiveness between 75 percent and 50 percent of the proposed floors, stating that 

industry’s statements that industry targets such emission levels to allow for a margin of error were 

unbinding and unenforceable. 

The Commenter stated that the effect of the EPA’s analysis creates an unlawful 25 percent “compliance 

margin” which ignores the achievability of BTF standards between 75 and 100 percent of the proposed 

floor. The Commenter stated that the EPA’s determination that a CAA §112(d)(3) standard 50 percent 

below the proposed floor was not achievable due to cost does not mean that such a standard at 75 

percent (or between 75 percent and 100 percent of the floor) is also not achievable. 

The Commenter stated that the EPA already accounted for sources’ variability in its floor calculations 

by applying the UPL to the best performers’ stack tests (November 30, 2012 Reconsideration MACT 

Floor Memorandum, and December 16, 2011 MACT Floor Memorandum). The Commenter stated that 

the UPL statistical formula and the 30 day averaging period provide for variability that new EGUs may 

experience as compared to the best performer. 

The Commenter concludes that the Agency’s use of a 25 percent compliance margin as yet another 

measure to account for variability is unlawful. The Commenter stated that by focusing only on the costeffectiveness of a standard between 75 and 50 percent of the proposed floor, the Agency ignored the 

achievability, or even the possibility, of a standard between 75 and 100 percent of the proposed floor. 

The Commenter stated that the EPA therefore violated its duty to determine the maximum reductions 

that are achievable under CAA §112(d)(2). 

Response: The EPA is confident in our approach for evaluating BTF emission limits for new sources in 

the reconsideration proposal. Because the BTF analyses for this reconsideration proposal were for 

emission limits for new, yet-to-be constructed, EGUs, the EPA had to make assumptions about such a 

new hypothetical plant. When setting MACT emission limits for the new source categories, the EPA 

determined the emission limitation achieved in practice by the best performing existing source within 

that category for each regulated HAP or HAP surrogate. The EPA then incorporated inherent variability 

(e.g., process, fuel, operational) using the “upper predictive limit” methodology that has been explained 

elsewhere. The EPA believes that it has appropriately considered variability in establishing standards 

that apply at all times. See Mossville Environmental Action Now v. EPA, 370 F.3d 1232, 1242 (D.C. Cir. 

2004) (holding that MACT floors may legitimately account for variability because “each [source] must 

meet the [specified] standard every day and under all operating conditions.”). The EPA believes that our 

methodology for incorporating inherent variability is consistent with past practice and with relevant case 

law. The control equipment associated with the best performing existing source is generally designed to 

meet an emission standard at optimum operating conditions. That level of performance at optimum 

conditions would be expected to be the highest level of performance – a level of performance that 

exceeds that necessary to meet the actual emission standard which the source would need to meet under 

all operating conditions. Industry has indicated that operators usually target emissions that are 50 to 75 

percent of the emission limitation to provide for a margin of error and unexpected spikes in emissions. 
74 

The Commenter indicates that this level is unbinding and unenforceable. The EPA agrees, but 

acknowledges that it represents the reality of how control technology equipment are designed and 

operated by sources that must comply at all times with the promulgated standard. In conducting the BTF 

analysis, the EPA assumed that the installed controls were designed to achieve a level of 75 percent of 

the floor emission standard at optimum conditions and to not exceed the floor emission standard during 

non-optimum conditions. The EPA then assumed that a BTF emission limit would require some level of 

investment in additional, larger, or better performing control technology (e.g., installation of 

downstream “polishing” baghouses for fPM). For our analysis, the EPA assumed a BTF level of 50 

percent of the floor emission level for the hypothetical new plant. Because these levels reflect current 

practices regarding how they plan compliance with emission limits, the EPA believes this is a realistic 

approach and feels confident in our conclusions drawn from the analysis. 

Comment: Commenter (20305) stated that the EPA’s rejection of various BTF standards because they 

are not “cost-effective” or their cost is not “reasonable” is unlawful. The Commenter stated that in these 

cases, the EPA has used the wrong legal test. The Commenter stated that CAA §112(d)(2) requires the 

“maximum” degree of reduction that can be achieved considering cost and the other statutory factors, 

but that the EPA’s rejection of BTF standards merely because it views their cost-effectiveness as 

unreasonable contravenes Congress’s plainly expressed intent. Chevron, U.S.A., Inc. v. Natural Res. Def. 

Council, Inc., 467 U.S. 837, 842-43 (1984); New Jersey v. EPA, 517 F.3d 574, 582 (D.C. Cir. 2008). 

The Commenter further stated that because EPA bases its rejection of BTF standards on costeffectiveness claims without making any effort to explain how its rationale comports with the statutory 

language, and because its reading of CAA §112 “diverges from any realistic meaning of the statute,” the 

agency’s reading is also unreasonable under Chevron step two. 

Response: CAA §112(d)(2) requires that the Agency promulgate standards that “shall require the 

maximum degree of reduction in emissions...that the Administrator, taking into consideration the cost of 

achieving such emission reduction, and any non-air quality health and environmental impacts and 

energy requirements, determines is achievable...” The EPA has, as directed by Congress, considered the 

cost of achieving “the maximum degree of reduction” and in all cases, except one, found the costs of 

achieving a BTF level of control to be not cost-effective or for the costs to be unreasonable. The 

Commenters believe that the EPA should have continued to examine, in detail, the “non-air quality 

health and environmental impacts” and “energy requirements” associated with the considered BTF 

emission limit. The EPA did consider these factors but agrees with the Commenter that it was not 

adequately described in the BTF TSD. The final BTF TSD has been edited to more completely describe 

the full range of factors considered in the BTF analysis. In any case, the Agency maintains that a 

decision to deny a BTF level of control on costs alone would be valid if the conclusion reached (i.e., that 

the BTF level of control is not cost effective) is valid because even assuming no non-air quality health or 

environmental impacts or adverse energy requirement, the costs will remain unreasonable. 

3.1 New coal-fired EGU 

3.1.1 Filterable PM 

Comment: Commenter (20305) stated that the EPA’s standards must reflect the maximum degree of 

reduction of emissions of HAP achievable, as stated in CAA §112. The Commenter stated that the CAA 

§112 language demands consideration of all available methods of reducing pollution, including 
75 

alternative “size[s] and [c]onfiguration[s]” of various pollution-control technologies. In re. Knauf Fiber 

Glass, GmbH, 8 E.A.D. 121, 141(E.A.B. 1999). The Commenter stated that the EPA has not followed 

that command in its BTF analysis for fPM, by failing to assess fabric filters providing superior 

pollution-control than EPA’s floor-based limit. The Commenter provided as an attachment examples of 

EGUs with fabric filters and emissions below the EPA’s limit. 

Response: The EPA believes that it has adequately conducted a BTF analysis for fPM for new coalfired EGUs using all available information. In setting the MACT floor (the emission standard), the 

Agency selected the best performing source for fPM. The Agency had insufficient information on the 

specific filter material used by the best performing source and, therefore, the EPA was unable to assess 

whether or not additional reductions could have been possible with better performing filters. However, 

the EPA stated in the BTF TSD (Docket ID EPA-HQ-OAR-2009-0234-20221) that “it is reasonable to 

expect that the very best performing source is achieving that level of control through the application of 

well-performing control technologies, by following a disciplined and routine maintenance schedule, and 

by operating in an efficient manner.” And, as with the floor emission standard, any BTF emission 

standard would need to be one that is achievable “under all operating conditions,” not just under 

optimum conditions. In addition, the Environmental Appeals Board case cited by the Commenter 

concerns development of a Prevention of Significant Deterioration permit applicable to a specific EGUs, 

and not development of a nationally applicable MACT standards under section 112; thus, we do not find 

the analysis in that case to be applicable to development of the new source standards. 

3.1.2 Hydrogen chloride 

Comment: Commenter (20249) does not support the establishment of a BTF standard for HCl of 1.0E02 lb/MWh. The Commenter stated the analysis performed is based on chlorine content of the fuel and 

control efficiencies of a high efficiency spray dryer absorber or wet-flue gas desulfurization scrubber. 

The Commenter said that the EPA believes a BTF emission HCl limit is cost-effective because it does 

not involve additional cost. The Commenter stated EPA did not evaluate the impact of additional 

controls on the cost of HCl control. The Commenter said, when controlling Hg emissions, the chlorine 

content of the coal can impact the removal efficiency of sorbent injection. It is the Commenters’ 

understanding that one option to improve Hg control is to inject chloride, which may increase HCl 

emissions. The Commenter stated that improving the efficiency of one emission control while adversely 

impacting another isn’t limited to just Hg and HCl, it is also true of sorbent injection and PM emissions. 

The Commenter stated, often the collateral increases in one pollutant are trivial when compared to the 

beneficial reduction in another. The Commenter concluded, nonetheless, the EPA should consider the 

impact of Hg control when establishing a BTF standard for HCl. 

Response: The EPA believes that is has adequately and correctly performed the BTF analysis for HCl 

and stands by the conclusion described in the BTF TSD and in the reconsideration preamble. As stated 

in the BTF TSD, the EPA believes that is it reasonable to assume that a new coal-fired EGU will install 

either a wet flue gas desulfurization (wet-FGD) scrubber or a high-efficiency spray drier absorber (SDA) 

for SO2 control and the EPA believes that the level of HCl control that can be achieved by these 

equipment exceeds the calculated MACT floor emission limit. Because the FGD is installed for SO2

control and the increased HCl control is achieved as a “co-benefit,” there are not additional costs for the 

BTF HCl control. Regarding the interactions affecting HCl and Hg control, the EPA is aware of these 

interactions as has been discussed in great length in the rule proposal and in response to comments on 
76 

the rule proposal (see, e.g., 76 FR 25014; RTC, Vol. 1, pp. 315, 588; RTC, Vol. 2, pp. 526 - 527). The 

EPA understands that flue gas halogens will promote the oxidation of Hg which enhances its control. 

However, the EPA is also aware of several commercially available control options that have been 

specifically developed to control Hg that is present in the flue gas stream as elemental Hg vapor. 

Western subbituminous and many low rank virgin coals have inherently low chlorine levels and tend to 

produce elemental Hg vapor in the post combustion flue gas. Facilities burning those fuels may also use 

those technologies (e.g., bromine injection, halogenated activated carbon, etc.). Although injection of 

chloride for Hg control is an option (injection of bromide is the more likely option), it would be unlikely 

to increase HCl emissions for a new coal-fired EGU with a high-efficiency SDA or a wet-FGD scrubber. 

Both of these acid gas removal technologies are very efficient for removal of HCl, which is both a 

strong acid and is highly water soluble, which means its removal in those controls is greater than SO2. 

Comment: Commenter (20305) stated that the EPA’s failure to consider further measures for HCl 

controls, such as requiring the use of low-chlorine coal, violates the Act. The Commenter stated that 42 

U.S.C. §7412(d)(2)(A) requires the EPA to consider the “application of measures, processes, methods, 

systems or techniques including...process changes [or] substitution of materials....” The Commenter 

stated that the EPA did not consider low-chlorine coal or coal blending, and did not offer any rationale 

as to why it did not do so, or why it would be infeasible for facilities to use low-chlorine coal. 

Response: As stated in the BTF TSD, the EPA believes that is it reasonable to assume that a new coalfired power plant will install either a wet-FGD scrubber or a high-efficiency SDA for SO2 control and 

the EPA believes that the level of HCl control that can be achieved by these equipment exceeds the 

calculated MACT floor emission limit. The EPA did not consider a requirement to use low-chlorine coal 

because, when applying these FGD control technologies, the chlorine content of the coal does not affect 

the emission level. Coals containing very high chlorine levels can see greater than 99+ percent control 

and very low emission levels while coal containing inherently very low chlorine levels (and usually high 

alkalinity) can see a relatively low HCl control percentage, but a very similar emission level. HCl is very 

easily removed in these control technologies due to its strong acidity and its high solubility. 

3.2 Other beyond-the-floor 

Comment: Commenter (20253) stated that the EPA should consider fuel switching from coal and oil to 

natural gas at new EGUs as a beyond the floor option, which is an option that relies upon cleaner fuels 

to lower emissions beyond the baseline that can be achieved by applying the best pollution controls to 

existing fuels. The Commenter stated that, if necessary, the EPA should re-propose the MATS rule for 

new EGUs to incorporate fuel switching as such a beyond the floor option. The Commenter stated that 

by not considering fuel switching as a beyond the floor option, the EPA will not achieve the health and 

environmental benefits required by the CAA. The Commenter stated EPA can correct its failure to 

achieve its statutory mandate by requiring emission limits consistent with fuel switching using natural 

gas because the reconsideration proposal requested comments on all aspects of EPA’s beyond the floor 

analysis including any technologies or practices demonstrated to consistently reduce HAP emissions 

below the standards proposed and in a cost-effective manner. 

Specifically, the Commenter (20253) stated that EPA erred in the reconsideration by not basing 

emission limits on fuel switching to natural gas as a beyond the floor requirement for new sources. The 

Commenter referred to clear legal precedent and applicable statutory criteria that mandate the EPA set 
77 

emission limits based on fuel switching to natural gas as a beyond the floor requirement for new EGUs 

as a means of reducing HAP to the maximum extent possible. The Commenter stated that EPA is 

correctly reconsidering the BTF provisions as CAA §112(d)(2) (the BTF provision) provides that EPA 

must require the “maximum degree of reduction” in HAP. Furthermore, CAA §112(d)(2) specifies that 

eligible compliance options include process changes, substitution of materials or other modifications, 

which clearly include changes to cleaner fuels such as natural gas. Furthermore, fuel switching has been 

identified as a means of reducing emissions that EPA must consider in reaching the “maximum degree 

of reduction” in emissions. See Nat’l Lime Ass’n v. EPA, 233 F.3d 625,635 (D.C. Cir. 2000). 

The Commenter (20253) stated that in the original MATS proposed rule, the EPA recognized that 

emissions from natural gas power plants are negligible and offers a greater degree of reduction than 

other compliance options and, therefore, offers the maximum degree of reduction and must be selected 

as the beyond the floor technology unless some other statutory criterion rules it out. The Commenter 

stated that this analysis is consistent with other EPA rulemakings such as the Power Plant GHG NSPS, 

which set emission levels for fossil-fueled new power plants consistent with natural gas combined cycle 

(NGCC) EGUs as these gas EGUs are the best system of emission reduction. 

According to the Commenter (20253), natural gas combined cycle plants are less expensive than coal 

plants with lower capital and annual operating costs. The Commenter also stated that EPA’s argument 

that natural gas is not widely available is inaccurate and unsupported and inconsistent with EPA’s 

pronouncements in other rules. For example, the Power Plant GHG NSPS recognized that NGCC EGUs 

will be the predominant choice for new fossil fuel-fired generation. Citing non-air quality health and 

environmental benefits, the Commenter stated that modern NGCC plants use less water for cooling than 

coal fired power plant and do not generate coal ash for disposal. 

The Commenter (20253) cited current litigation over the MATS rule’s failure to properly assess natural 

gas as a beyond the floor requirement. 

The Commenter (20253) stated that the beyond the floor requirements for new sources need not be 

burdensome. For example, the Commenter observed, emission limits consistent with use of natural gas 

would be required unless a permit applicant can demonstrate that natural gas is unavailable. The 

Commenter stated that another option would be to consider natural gas on a case by case basis for all 

new coal and oil-fired EGUs whereby each potential emission control technology would be analyzed 

with EPA determining what the maximum emission reductions should be for that EGU. The Commenter 

suggested that fossil fuel plants where natural gas is available could be considered as a “subcategory” 

for MACT standard-setting purposes. The Commenter stated that in this subcategory of EGUs (where 

natural gas is available), the MACT BTF limits would be based on the emissions of NGCC EGUs. The 

Commenter stated that none of these approaches is a prohibition on new coal plants. The Commenter 

stated that if natural gas is available and cost effective in a particular location, then a new EGU at that 

location must meet the emission standard achieved by a NGCC EGU. Otherwise, stated that 

Commenter, the standard for the new EGU could be set based on MACT floor separately established for 

the particular subcategory of EGU. 

Response: We rejected mandating fuel switching to natural gas in the February 2012 final rule for new 

coal-fired EGUs, and we continue to maintain that such a requirement is not appropriate because 
78 

mandating fuel switching would prohibit new construction of coal-fired EGUs. See 76 FR 25049/1.21,22

We disagree with the Commenter’s assertion that the EPA’s position is inconsistent with the proposed 

NSPS for GHG emissions from new EGUs issued pursuant to CAA section 111 (the Carbon Pollution 

Rule). There, the EPA proposed that new coal-fired EGUs meet the same emission standard as natural 

gas combined cycle (NGCC) plants for GHG emissions only, because such coal-fired EGUs could 

install a control technology – carbon capture and storage – that “is technically feasible and sufficiently 

available” and can reduce emissions to levels emitted by NGCC EGUs. See 77 FR 22392, 22414 (April 

13, 2012). 

Importantly, however, in the Carbon Pollution Rule proposal, the EPA did not propose to require new 

coal-fired EGUs to meet the same standards as natural gas plants for any pollutants other than CO2. See 

77 FR 22411/3. For example, coal-fired boilers and NGCC EGUs have separate NSPS emission limits 

for criteria pollutants. In fact, in the Carbon Pollution Rule proposal, the EPA explained – 

[A]t this time, we do not consider it appropriate to [apply the same §111 standards for 

conventional pollutants emitted by NGCC EGUs to criteria and air toxic pollutants 

emitted by coal-fired EGUs]. This is because although coal-fired EGUs have an array of 

control options for criteria and air toxic air pollutants to choose from, those controls 

generally do not reduce their criteria and air toxic emissions to the level of conventional 

emissions from natural gas-fired EGUs. 

Id. Accordingly, the EPA’s actions in the GHG (and criteria pollutant) NSPS context retain a viable path 

for construction of new coal-fired EGUs. Current control options for coal-fired EGUs do not reduce air 

toxics emissions to the level of air toxics emitted by natural gas-fired EGUs. Therefore, to mandate fuel 

switching to natural gas would prohibit new construction of coal-fired EGUs because such EGUs could 

not meet the limits. 

One Commenter offered potential approaches that allegedly would not prohibit new construction of 

coal-fired EGUs. We disagree with these approaches. First, the Commenter suggests that we set a 

national emission standard under CAA section 112 and that sources be required to comply with that 

standard unless an EGU can demonstrate to its permitting authority that natural gas is unavailable. As an 

initial matter, once we set a national emission standard under CAA section 112, sources must comply 

with that standard. Contrary to the Commenter’s suggestion, there are no waiver provisions under CAA 

section 112. Where the EPA sets a work practice standard, sources can petition the EPA to approve an 

alternative work practice that is at least as stringent as the standard contained in the CAA section 112 

rule, and the EPA must undergo notice and comment rulemaking with regard to any such request. CAA 

section 112(h)(3); 40 CFR 63.6(g). The Commenter is not, however, proposing a situation akin to EPA 

 

21 The numerical limits for existing EGUs are not at issue in this reconsideration action. Nevertheless, 

we note that in the final MATS rule we reasonably rejected a fuel switching standard for existing 

sources as not being “achievable” because natural gas supplies might be inadequate during peak 

demand, id. at 25046/2-3. The February 2012 final rule also concluded for existing sources that fuel 

switching would not be a cost-effective way to achieve HAP reductions. 

22 We note that although a new oil-fired EGU has not been constructed in the U.S. in decades, the 

argument against fuel switching to natural gas also applies to oil-fired EGUs.
79 

approval of an alternative work practice. Rather, the Commenter advocates an approach whereby we set 

a new source numerical limit (consistent with the use of natural gas), and only apply that national 

standard where there are adequate gas supplies.23 The Commenter’s approach is not consistent with the 

requirements of CAA section 112. We also disagree with the Commenter’s suggestion that we consider 

natural gas on a case-by-case basis for all new coal- and oil-fired EGUs. CAA section 112(d) requires 

the EPA to set a national emission standard for coal-and oil-fired EGUs once listed. We have done that 

here and cannot, at this time, proceed on a case-by-case basis. 

Moreover, the EPA believes that it would be very difficult to demonstrate that there are regions where 

natural gas is not available for new construction. With the ability to build both natural gas pipelines and 

transmission lines, developers of new power plants have the ability to consider a broad range of 

geographic locations to site new power plants even when they are being designed to meet load in a 

specific area. For instance, historically, Los Angeles has received significant amounts of power from a 

power plant located nearly 500 miles away in Delta Utah.

Further, such an approach could rule out some of the most viable locations for coal with carbon capture 

and storage (CCS). CCS for coal is an approach that has been used for over 10 years on a synthetic 

natural gas plant in North Dakota and that has been further demonstrated at a smaller scale on a number 

of EGUs including the Mountaineer Plant in West Virginia. A full-scale coal-fired EGU is currently 

under construction in Mississippi. Furthermore, two EGUs are in advanced stages of project 

development, one in Odessa, Texas, and one in Kern County, California. In at least the last two cases, 

the Commenters’ proposed suggestion of requiring natural gas-fired EGUs if natural gas was available 

would likely preclude the construction of these EGUs. Construction of these EGUs will likely result in 

improvements to CCS technology and further demonstrate the viability of this technology. This will 

allow for significantly less carbon dioxide intensive electricity, not just in the U.S., but also at EGUs 

around the world and could be an important element of addressing global warming. The Commenters 

proposed approach could greatly stifle further development of this important technology.

For the reasons stated above, we are not mandating fuel switching to natural gas as a beyond-the-floor 

measure because doing so would prohibit new construction of coal-fired EGUs. 

 

23 As a practical matter, the EPA did not collect any HAP data from natural gas fired EGUs on which it 

could establish CAA section 112(d) standards. 
80 

4.0 FILTERABLE PM MONITORING 

4.1 Quarterly stack testing 

Retain Quarterly Stack Testing 

Comment: Commenters (20242, 20246, 20247, 20248, 20249, 20250 20254, 20255, 20267, 20272, 

20275, 20280, 20281, 20282, 20285, 20290, 20291, 20294, 20295, 20303, 20304, 20308, and 5803) 

requested that the EPA retain the PM quarterly stack testing compliance option. 

Commenters (20242, 20246, 20248, 20249, 20255, 20276, 20281, 20282, 20290, and 20292) provided 

general comment that stated that there will be sources that will need to rely on stack testing for various 

reasons including cost-effectiveness, LEE qualification, a shortage of PM CEMS hardware or qualified 

installers, PM CEMS’ improper functioning or PM CEMS’ inability to pass performance specification 

testing. The Commenters stated that the quarterly testing option allows avoidance of the installation, 

operation, and maintenance concerns associated with PM CEMS and PM CPMS for sources that can 

demonstrates compliance with the standards using the same method – testing – that was used to set the 

standard. 

Commenters (20242, 20246, 20281, and 20294) stated that quarterly stack testing provides an essential 

fall-back option should PM CEMS or PM CPMS not meet source or agency expectations and provides 

flexibility for sources where one PM monitoring option may be difficult to implement due to sitespecific issues. 

Commenter (20285) stated that smaller facilities would be forced to incur significant costs, and would 

not yield any environmental benefit if they were expected to use either PM CEMS or PM CPMS.

Commenters (20254, 20267, 20272, 20282, and 20291) stated that EPA should retain the quarterly stack 

testing option because many facilities will have no interests in demonstrating compliance using CEMS, 

especially for EGUs with very low PM and Hg levels for which there is no need for the “frequent 

feedback” of PM CEMS. The Commenters stated that it is presumptuous for EPA to assert that because 

direct measurement of fPM or a correlated parameter is available, quarterly stack testing is not 

necessary. 

Commenters (20269, 20271, 20275, 20276, 20279, 20280, and 20303) stated that it appeared that the 

EPA asked for comment on the use of quarterly stack testing for new EGUs only. The Commenters 

believed that quarterly stack testing should be an option for both existing and new sources. The 

Commenters provided various reasons (economic, operational, and other considerations) for why 

existing EGUs should be allowed the use of quarterly stack testing. 

Commenter (20247) stated that EPA should retain the quarterly stack testing compliance option until 

PM CEMS technology advances and consistently provides reliable continuous emissions monitoring. 

Response: The EPA acknowledges the Commenters’ support for retaining quarterly testing. For the 

reasons set forth in the preamble to this final rule and below, the rule does not retain the quarterly PM 

performance testing option for new EGUs.
81 

Do not retain the quarterly stack testing option 

Comment: Commenters (20258 and 20293) stated that they do not support retaining quarterly stack 

testing in lieu of PM CEMs because this option reduces the quality of the information provided to 

operators of these sources and increases the risk of inadvertent excess emissions. The Commenter stated 

that it provides no meaningful cost savings or other benefit to operators of EGUs, but poses a significant 

resource burden on state and local permitting authorities. 

Commenter (20305) stated there is no reason to retain the quarterly stack testing option because the 

results provided by quarterly tests are not sufficient to ensure continuous compliance with the standards, 

if the variability assumed by the Agency in crafting its standards exists. The Commenter noted that the 

Agency’s rationale for the extended 30-day averaging period was to “provid[e] an additional allowance 

of variability for CEMS use.” See RTC, Vol. 1, p. 564. 

Response: Given that continuous, direct measurement of filterable PM (fPM) or a correlated parameter 

is available, is preferable to quarterly stack testing for determining compliance on a continuous basis, 

and is likely to be used by most new EGUs to monitor compliance with the proposed new source 

standards, the rule does not retain the quarterly PM stack testing option for new units. Commenters have 

not provided information that documents their claims of cost-ineffectiveness, a shortage of PM CEMS 

hardware or qualified installers, PM CEMS’ improper functioning or PM CEMS’ inability to pass 

performance specification testing. Commenters’ view on LEE qualification emissions testing are not 

relevant, as that provision of the rule was not opened for reconsideration. New EGUs can be designed to 

incorporate PM CEMS or PM CPMS from the outset, without being impeded by retrofit location 

installation constraints that could impact existing EGUs. This final action now requires new sources to 

use either PM CEMS or PM CPMS as options for determining compliance with the new source PM 

limits; data from the PM CEMS or PM CPMS are suitable to provide air operating permit compliance 

certifications. 

Other questions and concerns 

Comment: Commenter (20272) requested guidance on the obligation to perform the quarterly stack 

tests in the case of affected coal-fueled EGUs that do not operate or operates for de minimis periods of 

time during any particular calendar period. The Commenter stated that EPA has defined a Quality 

Assurance (QA) Operating Quarter as calendar quarter in which there are at least 168 EGU or stack 

operating hours for purposes of Hg CEMS. The Commenter stated that EPA should follow same 

approach with PM stack testing, and confirm that the quarterly stack test requirement does not apply to 

low-utilization EGUs that are below the Operating Quarter threshold as defined by the Hg CEMS 

regulations. 

Response: As the rule no longer contains quarterly PM testing for new EGUs, no response is necessary. 

Further, EPA did not propose to revise PM testing requirements for existing sources. However, in regard 

to existing EGUs which still have the option to conduct quarterly stack testing, the final MATS rule in 

40 CFR §63.10021(d)(1) allows EGU owners or operators not to conduct performance testing in those 

quarters during which less than 168 boiler operating hours occur, except that a performance test must be 

conducted at least once every calendar year.
82 

Comment: Commenter (20290) stated that quarterly stack testing is currently how sources determine if 

they qualify for Low Emitting EGUs and the relaxed requirements that come with that qualification. 

Commenter (20248) stated that the elimination of quarterly stack testing would also eliminate the LEE 

compliance option. The Commenter stated that if an EGU exceeds the LEE emission rate during the 

qualifying 3-year period, it is unclear what this EGU’s compliance status would be and how compliance 

would be demonstrated if the quarterly testing option were eliminated. 

Response: The subject of this comment is not within the scope of this rulemaking, as the LEE program 

does not apply to new EGUs. Therefore, no response is necessary.

Comment: Commenter (20262) stated that the requirement for quarterly performance tests to be 

conducted every 80 to 100 calendar days is restrictive and needs to be changed to “boiler operating 

days.” Commenter stated that in addition to normal scheduled plant outages, there are many 

uncontrollable factors that can prevent an EGU from operating on short notice for an extended period of 

time (storms that cause transmission line outages and loss of plant equipment). In absence of making 

this change to boiler operating days, the Commenter stated that the quarterly testing is not a realistic 

option for any EGU due to the uncertain factors outside of the owner or operator’s control. 

Commenter (20262) stated that unforeseen situations can arise at EGUs that derate an EGU, thus 

preventing it from being able to operate at a high load for a period of time. The Commenter noted that 

this may cause an EGU to have to reschedule the quarterly test and potentially miss the 20-day window 

that EPA requires. The Commenter stated that stack testing scheduling is typically done well in advance 

of the actual test date and coupled with the higher demand for stack testers because of the added testing 

requirements from MATS, it will be difficult to reschedule a tester on short notice and still be within the 

required 20-day window. To account for these situations, the Commenter recommends that a 10-day 

grace period needs to be added. Alternatively, the Commenter suggests that the 20-day window simply 

be expanded to 30 days. 

Response: As the rule no longer contains quarterly PM performance testing for new EGUs, no response 

is necessary. Further, EPA did not propose to revise the performance testing requirements for existing 

sources.

4.2 PM CEMS 

Comment: Commenter (20248) has concerns with certifying and operating PM monitors in accordance 

with PS-11 and Appendix F, Procedure 2 for EGUs where PM monitors are currently not installed and 

operating. The Commenter’s primary concern is relying on PM CEMS to demonstrate compliance with 

low PM standards. The Commenter stated that with low PM emission limits (<0.03 lb/MMBtu) the 

spread for the correlation curves will be small and the annual relative response audit (“RRA”) may fall 

outside of the acceptable range for the existing correlation curve. The Commenter stated that this result 

would require the development of a new correlation curve on an annual basis (minimum of 12, Method 5 

tests). The Commenter expects that a typical correlation curve would be based on filterable particulate 

concentrations of 0 - 20 mg/m3 in order to remain below the equivalent standard of 0.03 lb/MMBtu. The 

Commenter stated that this design presents enormous challenges for current control technologies and for 

maintaining emissions at set levels for the duration required to develop the PS-11 correlation curves. 
83 

The Commenter stated that they have explored the use of quantitative aerosol generator systems to 

produce NIST traceable particulate masses for correlation purposes but stated that they are not reliable 

in wet stacks and do not correlate well with currently used light scattering devices. 

Commenter (20290) stated that the inherent PM CEMS response variability and the uncertainty 

associated with the representative sampling at low emission levels make it problematic to satisfy the ±25 

percent of the applicable PS 11 acceptance threshold without extraordinarily long Method 5 test runs; 

and having to use increased Method 5 sampling runs to demonstrate compliance with PS 11 make it 

potentially far less economical than using the quarterly stack testing option.

Commenter (20261) stated that the accuracy of continuous PM monitors is limited by the sensitivity of 

EPA Method 5, which is used to establish a calibration curve under EPA’s PS-11. The Commenter 

stated that based on gravimetric precision alone, Method 5 should be able to quantify filterable 

particulate mass accurately at the new coal EGU limit of 0.09 lb/MWh; however, the overall accuracy of 

the method at these low levels needs to be evaluated further. The Commenter stated that currently 

installed PM monitors are used routinely to measure emissions in the range of 0.005 to 0.04 lb/MMBtu 

(approximately 0.05 to 0.4 lb/MWh for coal). The Commenter concluded that fPM can be measured 

accurately using continuous PM analyzers at the proposed new EGU limits. 

Commenters (20281 and 20282) provided discussion about the difficulties of correlating PM CEMS 

response to those that would be obtained with Method 5. 

Commenter (20282) noted that the PS 11 performance criteria become more difficult to meet as the 

emission limit gets lower, simply as a matter of application of the statistics. The Commenter stated that 

lower emission limits also mean greater influence of reference method measurement uncertainty and 

variability. The Commenter provided discussion about these topics, citing other EPA rules, an EPA 

memorandum, and permit determinations. 

Commenter (20242) discussed their evaluation of existing PM CEMS technologies, stating that these 

technologies either have significant field condition limitations or have only been deployed in limited 

utility scale applications. The Commenter stated concerns that if a beta gauge type PM CEMS were 

located in their CEMS building, there would be problems with sample moisture, transport distance and 

associated particulate fallout. The Commenter discussed the alternative, locating the PM CEMS at the 

stack sampling location half way up the 500 foot stack. The Commenter stated that at this time there 

appears to be no proven PM CEMS instrumentation that accurately and reliably measures PM and meet 

all the QA/QC testing requirements. 

Commenter (20282) discussed the uncertain accuracy of PM CEMS. The Commenter noted that an 

owner/operator choosing PM CEMS as the compliance method must bear any risk. 

Commenters (20282 and 20296) stated that PM CEMS technology is different from the test methods 

EPA used to set the subpart UUUUU standards. Commenter (20296) stated that the EPA erred in basing 

the requirement that sources demonstrate compliance with the revised PM standard using a PM CEMS 

on emission performance data gathered using an entirely different measurement method. The 

Commenter cited Portland Cement Ass’n v. Ruckelshaus, 486 F.2d 375, 396-97 (D.C. Cir. 1973). The 

Commenter concluded that the final rules should allow a source to undertake a demonstration of 
84 

compliance with the PM limits using the same measurements on which EPA bases the PM emissions 

limit. 

Commenter (20282) noted that a PM CEMS’ single sampling point may not provide representative 

concentrations across the stack of a stratified gas stream. 

Response: These comments concerning use of PM CEMS are not relevant. The EPA sought comment in 

the proposed reconsideration only on retaining quarterly testing as an option for performance testing and 

on approaches for establishing PM CPMS operating limits for new EGUs, and, as explicitly stated in the 

proposal, the EPA is not responding to any comments addressing any provisions of MATS beyond those 

identified as issues for reconsideration, including comments regarding the use of PM CEMS. Therefore, 

this comment is not addressed. The EPA notes that PM CEMS continue to be installed and operational at 

existing EGUs; moreover, they have also been installed in recently-completed existing EGUs that have 

emissions limits at levels near those contained in the standards. In addition, as mentioned in the Portland 

cement source rule preamble, fossil-fueled EGUs may be more suited to use PM CEMS than Portland 

cement plants, as EGU emissions have more uniform particle characteristics. See 77 FR 42375/2, July 

18, 2012. The EPA agrees with the comment from the Electric Power Research Institute that PM can be 

measured accurately using continuous PM analyzers at the proposed new unit limits. The EPA notes that 

the final rule provides the option to use a certified PM CEMS for direct compliance, but also allows the 

use of PM CPMS. For Commenters that believe the PM CEMS option is not the best approach for their 

EGUs, those Commenters are free to choose the other option specified in the rule. Finally, the EPA 

notes that one Commenter analyzed about 6 months of data from three PM CEMS which had successful 

correlations according to PS-11. That Commenter found no exceedances of the EGU new source 

emission limit. This shows that PM CEMS, calibrated by PS 11 as required by the final rule, is capable 

of measuring to the level of the standard, contrary to the assertions of Commenters. (see EPA-HQ-OAR2009-0234-20282, Attachment 8, page 3). 

The issue of the use of short-term emission test data to establish 30-day rolling average emission limits 

was addressed in the final RTC (see, e.g., Vol. 1, pp. 462 - 463, 468 - 469, 494 - 496, 500, 549 - 551) 

and is outside the scope of this rulemaking. This issue was not one of the issues being reconsidered and 

the EPA did not solicit comment in the reconsideration proposal regarding the use of short-term data. In 

addition, the Agency also explained why its variability analysis is valid and accounts for different realworld operating conditions (see, e.g., RTC, Vol. 1, pp. 493 - 496). The EPA explained its approach to 

assessing variability in the proposed MATS rule, and further discussion is provided elsewhere in this 

document. 

Comment: Commenter (20282) recommended that the EPA set limits based on PM CEMS data 

collected at sources representative of the range of EGUs subject to the standard, and over a sufficient 

period of time to ensure that any lack of stability in the calibration is taken into account. 

Response: The EPA maintains that its approach to establishing the MACT standards in the final rule is 

reasonable and consistent with the statute. The issue of the use of short-term emission test data to 

establish MACT emission limits was addressed in the final RTC (see, e.g., RTC Vol. 1, pp. 462 - 463, 

494 - 496, 500, 549 - 551). 

Comment: Commenter (20282) stated that there is not any significant helpful feedback provided by 
85 

stack-mounted PM CEMS for process control. 

Response: The EPA disagrees with the Commenter and feels that information from a PM CEMS 

monitor that allows a source to maintain compliance with their emission limit is providing helpful 

feedback to the source and supporting the overall aim of this rule. The same is true of measurements 

from a CPMS, which indicated whether the operating parameter has been exceeded. 

Comment: Commenter (20308) stated that for most coal-fired generation that will be built to meet the 

requirements of this proposed reconsideration rule, the pollution control equipment necessary to meet 

the emission limits will likely require operation of a wet stack. The Commenter noted that the ability to 

measure the particulate emission levels with a continuous emissions monitor in a wet stack are unknown 

or in its infancy, and noted that the emissions low in the span of measurements does not provide usable 

data for compliance or operational decisions. 

Response: The EPA disagrees with the Commenter. A number of types of PM CEMS are able to 

measure PM at the level of the standards in the final rule. As mentioned in EPA’s Current Knowledge of 

Particulate Matter (PM) Continuous Emissions Monitoring document, at least one such type of PM 

CEMS uses beta gauge technology, which “...is not affected by the presence of condensed water 

droplets in the [exhaust] gas stream...”in a stack and can be used in wet stacks to “...measure in a range 

from 1 to 500 mg/m3...”24,25 Moreover, the Current Knowledge of Particulate Matter (PM) Continuous 

Emissions Monitoring document, PM CEMS using optical technology “...in conjunction with a heated 

bypass can be calibrated in a wet exhaust stream...”26 The EPA recognizes that applying a technology 

suitable for a particular application would naturally take some planning, but does not agree with the 

Commenter’s view regarding usability of data for compliance purposes. Current guidance given in 

Section 2.4(1) of PS-11 states that an owner or operator should select a PM CEMS that is appropriate for 

its source. For Commenters who believe the PM CEMS option is not the best approach for their EGUs, 

those Commenters are free to choose the other compliance option specified in the rule.

Comment: Commenters (20258 and 20293) stated that they do not support the proposal to reduce or 

eliminate Relative Accuracy Test Audit (RATA) testing for CEMs; if such CEMs are to be installed, 

they should be calibrated so that the reported results accurately reflect the performance of the EGU. 

Response: The EPA agrees with the Commenters that CEMs should be calibrated. The final rule 

requires that PM CEMS used for direct compliance must meet PS-11 performance specifications and 

Procedure 2 quality assurance requirements on an ongoing basis. 

Comment: Commenter (20280) cited their comments on the proposed rule where they expressed their 

concern about PM CEMS. The Commenter attached those comments for reference. 

 

24 See Current Knowledge of Particulate Matter (PM) Continuous Emission Monitoring (EPA-454/R00-039), September 2000, pp. 4-4 and 4-5, in rulemaking docket EPA-HQ-OAR-2009-0234. 

25 The EPA notes that the non-lignite coal PM limit of 9.0 E-2 lb/MWh can be expressed as 16.4 mg/m3

using an F-factor of 9780 and a heat rate of 9000 Btu/kWh. 

26 See Current Knowledge of Particulate Matter (PM) Continuous Emission Monitoring (EPA-454/R00-039), September 2000, p. 5-5, in rulemaking docket EPA-HQ-OAR-2009-0234. 
86 

Response: This comment concerning use of PM CEMS is not relevant. The EPA sought comment in the 

proposed reconsideration only on retaining quarterly testing and on approaches for establishing PM 

CPMS operating limits, and, as explicitly stated in the proposal, the EPA is not responding to any 

comments addressing any provisions of MATS not identified as issues for reconsideration, including 

comments concerning the use of PM CEMS. Further, in this case, Commenters simply reference 

comments they provided on the 2011 proposed MATS rule, to which EPA responded in its final action 

on that proposal. The EPA notes that the final rule provides the option to use a certified PM CEMS for 

direct compliance, but also allows compliance demonstration by establishing operating parameters, 

measured by a CPMS, should a source elect that compliance alternative. Therefore, EGU owners or 

operators who do not believe PM CEMS option is the best approach could choose the other option 

allowed in the rule. 

4.3 PM CPMS 

Comment: Commenter (20242) stated that the existing method and two proposed options for setting the 

PM CPMS operating limit are arbitrary, likely non-representative, and potentially too restrictive. The 

Commenter stated that the proposed methodologies for establishing operating limits are likely nonrepresentative because the time period necessary to perform the PM performance test is relatively short 

and does not represent typical PM control efficiencies. 

Commenter (20281) stated that the PM CPMS option proposed by the EPA offers no advantage, but 

adds potential cost and risk, over PM CEMS for most EGUs. 

Commenter (20282) objected to the proposed revisions to the new EGU PM CPMS option, if it is in 

anticipation of requiring new EGUs to use PM CPMS (or PM CEMS). The Commenter stated that the 

proposed PM CPMS option is seriously flawed, even with the proposed new EGU revisions. 

Commenter (20242) stated that the PM CPMS operating limit determination methods are potentially 

subjective. The Commenter stated that a facility may be penalized if their control system is very 

effective during performance testing, and result in operating limit exceedances that the source will then 

need to rebut. The Commenter observed that with this concern, performing quarterly compliance PM 

stack testing seems to be the most reasonable and objective option. 

Commenter (20282) stated that although the option has the advantage of avoiding the testing issues 

associated with PS 11 correlations, absent that correlation the parameter is nothing more than an 

indicator that PM may be increasing or decreasing. The Commenter stated that CPMS could be useful to 

identify the need for investigation and action, but not to establish an enforceable limit. 

Commenter (20282) stated that an EGU establishing a PM CPMS operating limit could be testing well 

below the applicable emission limit, and there is no basis to assume that an exceedance (or multiple 

exceedances) of a 30-boiler operating day rolling average parameter limit indicates an emission limit 

was exceeded, or that controls were not operated properly. The Commenter stated that it means that 

emissions on average were above the level of emissions during the last performance test. The 

Commenter stated that unless the EGU has collected data to determine what PM CPMS parameter level 

is equivalent to a violation of the emission standard, there is no basis to suggest that any parameter 

exceedance is a violation. The Commenter stated that requiring an EGU to attempt to collect data to 
87 

establish such an equivalent value would require just the sort of PS 11 correlation that the option is 

intended to avoid. 

Commenter (20282) suggested that for the approach to be useful as an alternative to quarterly stack 

testing or PM CEMS, the EPA would have to (1) allow reasonable scaling (Option 3), and (2) abandon 

its arbitrary definition of a violation in favor of a pure investigation and corrective action approach. The 

Commenter suggested that PM CPMS would be more appropriate as a part of a Compliance Assurance 

Monitoring (CAM) approach rather than as a direct indication of compliance. 

Commenter (20304) stated that the language in paragraph (2)(i) of the docket memo is confusing. The 

Commenter stated that it appears to require the use of option 2 (averaging) but the following paragraphs 

(A) through (D) describe the method to extrapolate up to 75 percent of the standard (option 3). The 

Commenter suggested that the Agency clarify the language in (2)(i) to make it clear that the facility is 

allowed to use option 3 when the test shows the emissions are below 75 percent of the standard. The 

Commenter stated that four additional paragraphs (iii, iv, v, and vi) are not needed and could be 

dropped. 

Commenter (20242) supported adding the two new proposed methods/options to establish PM CPMS 

operating limits because this flexibility provides some minor improvement. 

Commenter (20304) stated that all three options for PM CPMS should be included in the final rule. 

Commenter (20308) stated that the costs of a PM CPMS are offset by the costs of stack testing 

procedures. 

Response: The rule requires the third of the three proposed approaches based on the 3-run average 

operating parameter value determined from performance test results, and scaling for units with 

emissions below 75 percent of the limit. This approach avoids penalizing the lower emitting sources by 

allowing the parameter value obtained from the performance test to be scaled up to 75 per cent of the 

limit. Higher emitters must establish operating parameters reflecting the average values of their 

(successful) performance tests, and the CPMS is highly reliable at detecting exceedances of that 

operating parameter. As mentioned earlier, the third approach was selected because it appropriately 

balances the competing concerns considered by the Agency and raised by Commenters. Specifically, 

this approach provides the greatest amount of flexibility while still demonstrating continuous operating 

parameter compliance for lower-emitting EGUs, at the same time holding higher emitters to parametric 

limits representative of values below the emission standard. With this parametric monitoring approach in 

place, the EPA expects EGU owners or operators to evaluate control options that provide excellent PM 

emissions control and provide them greater operational flexibility. 

The EPA is clarifying in the regulatory text for the final rule that, for sources using the average PM 

CPMS value, that value is the average PM CPMS value recorded during the PM compliance test 

demonstrating compliance with the PM limit is to be used to establish parametric operating limits. This 

is consistent with the proposed approach, which would have required use of the highest parameter value 

obtained during an individual emissions test provided that the result of that individual test was below the 

limit. Further, as noted in the preamble to today’s final rule, the approach adopted in the final rule was 

recently adopted as part of the EPA’s amendments to the Portland cement MACT rule, which includes a 
88 

similar limitation requiring operating limits to be based on the average PM CPMS value that is below 

the PM limit. 

Every EGU using PM CPMS will need to conduct an annual Method 5 test to determine compliance 

with the PM emissions limit, and during this testing will also monitor its PM CPMS milliamp output. An 

EGU which emits PM less than 75 percent of their emission limit will be able to scale its PM CPMS 

milliamp output to determine where its PM CPMS would intersect 75 percent of their allowed fPM 

emissions, and set its operating level at that milliamp output. This alleviates many re-testing concerns 

for EGUs that operate well below the emission limit (where a source could exceed the parametric limit 

established from the performance test but still be operating at a level well below the level of the 

standard) and provides them with greater operational flexibility while still assuring continuous 

compliance with the PM parametric limit. It also creates an incentive for EGU owners or operators to 

select high efficiency PM controls when evaluating potential compliance strategies. For EGUs whose 

Method 5 compliance tests place them at or above 75 percent of the emission standard, their operating 

limit levels will be the average PM CPMS milliamp output during the three Method 5 test runs. 

The scaling option provides flexibility for low emitting, well-operated sources, and it was determined to 

be a reasonable compromise of flexibility and protection of the emission standard. Seventy-five percent 

of the emission limit is an already-established threshold in the Standards of Performance for New 

Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid 

Waste Incineration Unit (76 FR 15757) to determine the frequency of subsequent compliance testing. In 

that rule, owners or operators of sources were able to reduce their performance test frequency when 

emissions were equivalent with or below 75 percent of the limits. Otherwise, performance testing was to 

occur at the normal frequency prescribed in the rule. See also 78 FR at 10019-10020 (Feb. 12, 2013) 

where EPA adopted a similar approach for parametric monitoring for the PM standard in the NESHAP 

for the Portland cement source category. The EPA believes this threshold can be used in conjunction 

within a PM CPMS scaling factor, as results above 75 percent of the equivalent emissions limit would 

be ineligible for scaling factor use and could lead to increased performance testing, while results 

equivalent with or below 75 percent of the equivalent emissions limit would be eligible for scaling factor 

use. Adherence to an operating limit with a 25 percent (1 - 0.75) margin of compliance should 

demonstrate continuous, qualitative compliance with an operating limit below the PM standard.

Moreover, the EPA believes that on balance the 30 days of averaged CPMS measurements provides 

ample operating cushion to incorporate operational variability.

The issue of more than four exceedances of the parameter operating limit over a 12 month period as 

being a presumptive violation of the emission limit is discussed in Section 4.3.5 of this RTC. 

Comment: Commenter (20305) stated that rather than retaining the CPMS alternative, the EPA should 

require sources to use PM CEMS to determine compliance, but the EPA has provided no rationale for 

not requiring the use of PM CEMS. The Commenter stated that requiring PM CEMS would eliminate 

the problems associated with the CPMS method for determining compliance, and would provide a 

compliance method that correlates to methods used by EPA to set the applicable emissions limit. 

Response: This comment concerning use of PM CEMS as the exclusive means of demonstrating 

compliance is not relevant. The EPA sought comment on retaining quarterly testing and on approaches 

for establishing PM CPMS operating limits in the reconsideration. The EPA is not addressing this 
89 

comment. Moreover, this Commenter raised the same issue in comments on the 2011 proposed rule, and 

the EPA considered those comments and decided in its final action on that proposed rule not to require 

PM CEMS as the exclusive means of compliance (see pg. 177, RTC Vol. 2). The EPA notes that the 

final rule provides for the use of a PM CEMS to determine compliance with the filterable PM emission 

limit if the source owner or operator elects to use this approach. Finally, the EPA maintains that the 

compliance demonstration options (PM CPMS and PM CEMS) both assure compliance with the final 

standards, and the Commenters have provided no data or information to demonstrate otherwise. 

Comment: Commenter (20291) stated that allowing opacity, pressure drop across baghouse, or 

electrostatic precipitator (ESP) voltage to be linearly correlated to PM emissions pursuant to 40 CFR 

Part 64 (CAM Plans) should be allowed as a compliance method in MATS. The Commenter explained 

that pursuant to CAM Plan methodology, a battery of typically three method 5 tests is run at three 

differing ESP voltage settings during EGU steady state for a total of nine method 5 benchmarks. The 

Commenter stated that during each test the opacity is noted from the installed continuous opacity 

monitoring system (COMS). The Commenter continued that using the results of the method 5 tests and 

COMS readings a linear curve fit correlation is drawn with requisite criteria of acceptability. Hence, the 

Commenter stated, equivalent PM reading can be extrapolated from a COMS reading in the range of 

compliance up to the PM limit for the EGU without artificially placing the compliance limit at the 

highest source test result under the requisite regulatory limit. The Commenter stated that the regulatory 

limit is the limit and there is no penalization. The Commenter noted that in many of the Commenter’s 

federal Part 70 permits this is a PM compliance option already in place. The Commenter stated that 

allowing this method would reduce regulatory overlap, redundancy and confusion as well as providing a 

flexible cost effective avenue to compliance for EGUs with already installed equipment and approved 

plans. 

Response: The EPA does not agree with these comments. As explained in the Portland cement rule 

preamble (78 FR 10019; February 12, 2013), the PM CPMS is considerably more sensitive than an 

opacity monitor at detecting fluctuations in PM level. An opacity monitor determines the percent of a 

light signal that is occluded across the stack diameter. Opacity analyzers operate on a zero to 100 

percent scale, meaning they are capable of registering PM that completely occludes the far stack wall 

from the instrument light source. This amount of PM is roughly equivalent to a complete failure of the 

emission control device. A properly operating control device will emit five percent opacity or less, 

which is barely visible to the naked eye and on the low end of the opacity monitor capability. PM 

emissions that increase opacity two percent at this level may well exceed the emission standard, yet they 

only mildly deflect the opacity monitor output. However, this same 2 percent opacity increase will 

register changes of several milliamps on a PM CPMS when operating on the scale provided in this final 

rule. Further, the PM CPMS has several decimal fractions available between each milliamp to track 

signal output, and three or four milliamps represent 1 percent change in opacity. Therefore, a small 

increase in PM emissions at low PM concentrations – which could represent an exceedance of the 

standard – is more easily read using PM CPMS has a clear advantage than through opacity monitoring 

systems. 

Comment: Commenter (20304) recommended that the PM CPMS language should allow new and 

existing sources to use all three options. 

Commenters (20262, 20267, 20282) encouraged EPA to allow existing EGUs to benefit from these 
90 

slightly more flexible provisions. Commenter (20262) stated that EGUs that have, or choose to install, 

high performing PM control equipment cannot take advantage of the linear scale approach; extending 

this approach to existing EGUs would provide an incentive to install and operate technologies that 

control PM emissions well below the MATS limit. 

Response: These comments concerning use of alternative PM CPMS monitoring approaches for 

existing EGUs are not relevant to today’s action. The EPA neither proposed nor requested comments in 

the proposed reconsideration on the operating limit for PM CPMS at existing EGUs, and, as explicitly 

stated in the proposal, the EPA is not responding to any comments addressing any provisions of MATS 

beyond those identified as issues for reconsideration. 

4.3.1 First Approach for establishing the operating limit for PM CPMS – Requiring use of the highest 

parameter value obtained during any run of an individual emissions test as the operating limit, provided 

that the result of that individual emissions test met the emission limit. 

Comment: Commenter (20305) stated that the provision of the first approach does not suffice to secure 

compliance with the standard. The Commenter stated that the first approach demands compliance with a 

“parameter,” but fails to ensure that the parameter correlates with the applicable emissions limit. The 

Commenter stated that an emissions test may, on average, be below the limit, even while individual test 

runs yield emissions above the limit. The Commenter stated that the “highest parameter value” 

associated with one test among a test run may therefore exceed the limit, even while the average of all 

test values does not. The Commenter stated that monitoring compliance with a parameter thus derived 

will not ensure compliance with the standards, and does not ensure compliance with the law. The 

Commenter suggested that the EPA should require plant-owners to define their operating parameters 

only according to “the average parameter value obtained from all runs pertaining to an individual 

emissions test” demonstrating compliance with the PM limit. 

Commenter (20305) stated that allowing plant owners to combine the data collected over multiple 

performance tests to establish a more representative value for the monitored parameter invites plantowners to further distance their parametric monitoring from plant’s actual emissions. The Commenter 

stated that combining multiple stack tests may result in a set of characteristics that do not reflect any of 

the plant’s actual operating characteristics. The Commenter stated that this difficulty is exacerbated if 

the Agency continues to establish, as its governing parameter, the highest test-run amongst stack tests 

whose average meets the underlying standard; the distance between the highest test and the average 

value is likely to increase as a greater number of stack tests are combined together. 

Commenter (20269) supported the use of the first approach due to the amount of operational flexibility. 

Response: As mentioned earlier, the rule requires the third approach based on the three run average 

operating parameter value determined from performance test results, and scaling for EGUs with 

emissions below 75 percent of the limit; not the highest operating parameter value determined from 

performance test results approach. Scaling alleviates many re-testing concerns for EGUs that operate 

well below the emission limit, and provides them with greater operational flexibility while still assuring 

continuous compliance with the PM stack emission standard. 

4.3.2 Second Approach for establishing the operating limit for PM CPMS – Requiring use of the average 
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parameter value obtained from all runs of an individual emissions test as the operating limit, provided 

that the result of the individual emissions test met the emissions limit. 

Comment: Commenters (20258 and 20293) stated that they agree with EPA’s proposal to index 

parametric monitoring to the average of the parameters in three run reference method tests rather than to 

the parameters in the highest emitting run. The Commenters stated that because the highest emitting run 

would show emissions greater than the average of the three runs, the parameters associated with the 

highest run would not be sufficient to assure compliance with the applicable limit. 

Regarding Option 2, Commenter (20267) stated that it is obvious that increasing the sample duration 

increases the accuracy of any measurement. It is no less true for the CPMS parameter vs. actual 

emissions correlation. The Commenter stated that inclusion of multiple runs into an average parameter 

value will strengthen that correlation. 

Response: Consistent with the Commenters’ concerns and, as mentioned earlier, the rule requires the 

third approach based on the 3-run average operating parameter value determined from performance test 

results, and scaling for EGUs with emissions below 75 percent of the limit; not the first approach. 

4.3.3 Third Approach for establishing the operating limit for PM CPMS – Requiring use of the higher of 

a parameter scaled from all values obtained during an individual emissions test to 75 percent of the 

emissions limit or the average parameter value obtained from all runs of an individual emissions test as 

the operating limit, provided that the result of the individual emissions test met the emissions limit. 

Comment: If the first approach is rejected, Commenter (20269) supports the third approach. The 

Commenter noted that the third approach does not provide as much operational flexibility as the 

Commenter would prefer. 

Response: As mentioned earlier, the rule requires the third approach based on the 3-run average 

operating parameter value determined from performance test results, and scaling to 75 percent for EGUs 

with emissions below 75 percent of the limit; not the first approach. Scaling alleviates many re-testing 

concerns for EGUs that operate well below the emission limit, and provides them with greater 

operational flexibility while still assuring continuous compliance with the PM stack emission standard. 

This approach is discussed more fully in Section 4.3 of this RTC. 

Comment: Commenter (20269) asked that EPA clarify (in the third option) whether a 30-day rolling 

average or a 30-day average is intended. 

Response: The operating limit is based on a 30-boiler operating day rolling average. 

Comment: Commenter (20282) expressed appreciation for EPA’s proposed scaling option, but the 

Commenter stated that EPA’s proposed use of 75 percent of the emission level as the upper point is 

arbitrary, and still would put sources that are operating with significant compliance margin at risk of a 

violation. The Commenter stated that for a scaled limit to justify a violation, the EPA must establish not 

only the consistency of the uncorrelated measurements over time, but allow scaling up to 100 percent of 

the emission limit. The Commenter stated that the EPA’s reliance on the extended averaging time to 

ensure that complying sources are not deemed in violation is based on the incorrect assumption that, at 
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an EGU with properly operated PM controls, hourly parameter values above the average (or highest) 

value during the performance test will always be the result of normal variability that will automatically 

smooth out over time. The Commenter stated that such values, however, could just as easily be the result 

of an actual change in condition that does not result in emissions above the applicable emission limit. 

The Commenter illustrated this point with a memorandum analyzing raw PM CEMS output data, 

provided as Attachment 8 to the comment letter. The Commenter concludes, based on this analysis, that 

neither the average nor the maximum 1-hour average PM CEMS raw output during a performance test 

provides a reasonable basis for setting an operating limit for any facility with any compliance margin. 

Commenter (20282) also included in Attachment 8 of their comment a comparison of the three options 

proposed to develop an operating limit using PM CPMS for new sources and an approach for existing 

sources using the 75 percent scaling approach. In the Commenter’s study, the first and second options 

produced false positives; the scaled approach produced better results. The Commenter reiterated that 75 

percent is not the appropriate end point for scaling. 

 Commenter (20262) supports the approach to allow an EGU owner or operator whose PM emissions do 

not exceed 75 percent of the limit to set a PM CPMS operating limit by linearly scaling the average 

operating value obtained during all the performance testing runs to be equivalent to the value at 75 

percent of the limit. The Commenter encourages EPA to allow scaling up to 100 percent of the limit. 

Commenter (20267) stated that without Option 3, there is no mechanism to reduce the compliance 

burden on very low-emitting EGUs. The Commenter stated that those EGUs would be forced to overcomply with the MATS PM standard as the CPMS operating limits would be set at a level 

commensurate with tested PM emissions that are under that standard. Otherwise, the Commenter 

observed, a utility might be compelled to perform a science experiment of gradually detuning PM 

controls during multiple stack tests in order to achieve the most flexibility and a margin of safety in 

daily operation. The Commenter stated that the exact scaling method and the 75 percent target should be 

up for debate as well. The Commenter stated that in addition, ruling that four exceedances of the EGU 

operating limit violate the standard unnecessarily burdens low-emitting EGUs that operate at or below 

75 percent of the standard. 

Response: As mentioned earlier, the rule requires the third approach based on the 3-run average 

operating parameter value determined from performance test results, and scaling for EGUs with 

emissions below 75 percent of the limit; not the highest operating parameter value determined from 

performance test results approach. Scaling alleviates many re-testing concerns for EGUs that operate 

well below the emission limit, and provides them with greater operational flexibility while still assuring 

continuous compliance with the PM stack emission standard. The EPA believes that the 30-boiler 

operating day rolling averaging feature plus the 75-percent scaling feature for the lower emitting sources 

provides a sufficient operating cushion. Also see the response to comments on the chosen approach in 

Section 4.3 on PM CPMS, and see Section 4.3.5 on the issue of four exceedances leading to violation.

In response to the Commenter who sought use of a 100 percent scaling factor, the Agency disagrees. A 

parameter level scaled to a level below the emissions limit is appropriate for the reasons stated above. 

Moreover, while EPA expects there to be a relationship between emissions at the scaled level and the 

emissions at other parameter values, the precise correlation is not known, so some allowance for 

correlation imprecision is necessary. Over time, an EGU owner or operator may develop enough data to 
93 

provide a better prediction and then submit such information to the Administrator in a request for an 

alternative standard. An EGU owner or operator who is concerned about not having enough operating 

limit flexibility could always switch to PM CEMS use, as those instruments report values in terms of the 

emissions limit. 

The EPA notes that the term false positive, as claimed by one Commenter in its review of PM data 

collected over a period of about six months from three PM CEMS operated as PM CPMS may be 

incorrect. As the data were reviewed well after the instances occurred, there was no ability of the EGU 

owner or operator to take corrective action or to perform stack testing and reset the operating limit to 

demonstrate that the value recorded did not indicate non-compliance with the emissions limit. As 

mentioned earlier, this Commenter analyzed about 6 months of data from three PM CEMS which had 

successful correlations according to PS-11. The Commenter found no exceedances of the EGU new 

source emission limit. This shows that PM CEMS, calibrated by PS-11 as required by the final rule, is 

capable of measuring to the level of the standard. 

Comment: Commenter (20305) stated that the third approach would permit emissions in excess of the 

limits. The Commenter expressed concern that plant owners are given leeway to select an indicator of 

convenience, and the rule does not indicate that the “parameters” available to power-plant operators all 

have a linear relationship to PM emissions. The Commenter noted that most facilities will be controlled 

with fabric filters, which are constant-output devices. The Commenter stated that a properly maintained 

and operating fabric filter will either meet a specified emissions limit or not; its emissions will not vary, 

and certainly not linearly, over a wide range. 

Commenter (20305) stated that parametric options for the performance of fabric filters do not show a 

functional or linear correlation, as a small change in any of the parameters – e.g., a reduction in pressure 

or amperage below the threshold at which the filter is designed to function – could result in a very large 

increase in particulate emissions. The Commenter stated that the EPA cannot rely on “linear scaling” to 

ensure that emissions will remain below the limit. 

Response: The EPA does not agree that the PM CPMS output is an indicator of convenience and 

maintains that PM CPMS monitoring provides for continuous qualitative assessment of source PM 

emission controls and is protective of the emission standard – i.e., given the instrument sensitivity to 

detecting and reporting increases in the PM signal, there is virtually no likelihood of false negatives. 

Where PM controls are failing, the PM CPMS signal will indicate the increasing concentration of PM in 

the stack gas. The EPA recognizes this as a significant step forward in emissions measurement related to 

PM standards. Indeed, the sensitivity of the PM CPMS is why the EPA introduced the scaling factor to 

accommodate the situation of lower-emitting facilities, to avoid what in effect would be false positives – 

CPMS measurements where an increase in PM emissions would not exceed the emission standard itself. 

The scaling option provides flexibility for low emitting and well-operated sources, and was determined 

to be a reasonable compromise of flexibility and protection of the emission standard. Seventy-five 

percent of the emission limit is an already-established threshold in the Standards of Performance for 

New Stationary Sources and Emission Guidelines for Existing Sources: Commercial and Industrial Solid 

Waste Incineration Unit (76 FR 15757) to determine the frequency of subsequent compliance testing. In 

that rule, owners or operators of sources were able to reduce their performance test frequency when 

emissions were equivalent with or below 75 percent of the limits. Otherwise, performance testing was to 
94 

occur at the normal frequency prescribed in the rule. The EPA believes this threshold can be used in 

conjunction within a PM CPMS scaling factor, as results above 75 percent of the equivalent emissions 

limit would be ineligible for scaling factor use and could lead to increased performance testing, while 

results equivalent with or below 75 percent of the equivalent emissions limit would be eligible for 

scaling factor use. Adherence to an operating limit with a 25 percent (1 - 0.75) margin of compliance 

should ensure continuous, qualitative compliance with an operating limit below the PM standard. 

Moreover, use of a scaling factor limited to 75 percent reduces concerns about non-linearity of 

emissions relative to PM CPMS signal. As explained in the Establishing an Operating Limit for PM 

CPMS memorandum,27 although the EPA may not know the specific shape of the emissions/PM CPMS 

signal relationship prior to data collection, an assumption of linearity from zero to 75 percent of the 

emissions limit focuses attention on the lower part of the relationship which is more linear that the upper 

part of the relationship. Moreover, stopping the scaling at 75 percent of the emissions limit provides a 

margin of safety or reserve such that emissions values from non-linear relationships near the scaling 

endpoint do not exceed the emissions limit. 

4.3.4 Emissions Testing After Each Exceedance 

Comment: Commenter (20282) stated that it is not reasonable for the EPA to require sources to (1) 

conduct performance tests, perhaps as often as every 45 days, in order to demonstrate compliance and 

reassess its parameter level and (2) be labeled a violator as a result of its fourth successful performance 

test in a 12-month period. The Commenter stated that if an EGU that has invested in a PM CPMS is 

conducting appropriate investigations and corrective action in response to parameter exceedances, there 

is no basis to label that poor control device performance. 

Response: We understand the Commenter is concerned about the relationship of testing after each 

exceedance and still being labeled as in violation after four exceedances. See response to comments 

under Section 4.3.5., below, for EPA’s response to concerns with the four exceedance provisions. 

Comment: Commenter (20304) supported allowing a facility to retest when the limit established during 

the annual test is exceeded. 

Response: The EPA appreciates Commenter’s support. 

4.3.5 Exceedances Leading to Violation 

Comment: Commenter (20282) disagreed with the proposed presumptive violation after more than four 

tests (within one calendar year). The Commenter asked what evidence is the source supposed to rebut if 

the rule defines the violation based on the triggering of a fifth test in 12 months, and not based on any 

evidence that the exceedance that triggered the fifth test resulted from emissions that were actually 

above the emission limit. 

Response: The Commenter objected to the proposal that four same-calendar year exceedances from the 

 

27 See Docket ID EPA-HQ-OAR-2011-0817-0840 in the Portland cement rulemaking docket; also found 

in rulemaking docket EPA-HQ-OAR-2009-0234.
95 

parametric limit would be a presumptive violation of the emission standard. The EPA does not agree 

with this objection. First, the EPA may permissibly establish such a presumption by rule, assuming there 

is a reasonable factual basis to do so. See Hazardous Waste Treatment Council v. EPA, 886 F. 2d 355, 

367-68 (D.C. Cir. 1989) explaining that such presumptions can legitimately establish the elements of the 

agency’s prima facie case in an enforcement action. 

Second, there is a reasonable basis for the presumption that four exceedances (i.e. increases over the 

parametric operating limit) of the 30-boiler operating day rolling averages in excess of the operating 

limit are a violation of the emission standard. The parametric monitoring limit is established as a 30-

boiler operating day rolling average of the averaged test value in the performance test, or the 75th

percentile value if that is higher. In either instance, the 30-boiler operating day rolling averaging feature 

provides significant leeway to the owner or operator not to deviate from the parametric operating level 

because the impact of transient peaks or valleys is limited due to the length of the rule’s averaging 

period – 30 boiler operating days, rolled daily. See 77 FR 42377/2 and sources there cited. 

Moreover, for even a single exceedance to occur, the 30 day average would have to be higher than the 

operating limit established for the PM CPMS during normal EGU operation. If that occurs, then the 

EGU owner or operator is required to conduct an inspection to determine any abnormalities and an 

emissions test to re-establish or generate a new operating limit. Given that EGUs and their emissions 

control devices are designed to operate at known, specific conditions, deviations from these conditions 

are not expected and are indicative of problems with load, controls, or some combination of both. 

Continued operation outside these known, specific conditions will require an EGU owner or operator to 

identify and then correct problems. More than four such exceedances of the 30 day average would mean 

that the EGU owner or operator was unable to determine or correct the problem, since inspection and recalculation of the operating limit is required after each exceedance. This indicates an ongoing problem 

with maintaining process control and/or control device operation, which would be the basis for a 

presumptive violation of the emissions standard. 

The EPA notes that emissions tests conducted by an EGU owner or operator to better define or reassess 

the operating limit that are not the result of an exceedance of the operating limit are not included as 

counting towards the 4 test limit over a 12 month period that constitutes a presumptive violation of the 

emission standard. 

The EPA further notes that the rule identifies more than 4 compliance tests over a 12-month period as 

only a presumptive violation of the emissions limit. A presumption of a violation is just that – a 

presumption – and can be rebutted in any particular case. There are a number of items a court may find 

credible as evidence that an EGU did not exceed its emissions limit even though the EGU did exceed its 

PM CPMS operating limit. For example, an EGU owner or operator might provide sufficient 

information to show that the EGU remained in process control, or that the operation and maintenance 

conducted on the EGU ensured the control devices remained in proper operating condition, or that 

emissions tests results conducted while replicating the conditions showing exceedance of the 30-boiler 

operating day rolling average showed compliance with the emissions limits. What would be sufficient 

information for credible evidence to rebut non-compliance remains a case-by-case determination based 

on specific facts. 

Comment: Commenter (20269) asked that EPA clarify that a “single equipment problem that spans two 
96 

or more days that causes the average emissions to exceed the limit over multiple days will be treated as a 

single episode of exceedance, triggering the requirement to conduct a single performance test.” The 

Commenter (20269) asked that “any enforcement action taken in response to a fifth performance test in 

a 12-month process operating period” be treated as a single violation of the standard. 

Response: The EPA disagrees that the rule needs the additional clarification sought by the Commenter. 

The rule is clear that an exceedance occurring between the first exceedance and the performance test is 

considered part of the initial exceedance (see 40 CFR §63.10021(c)(1)(iii)) as long as no more than four 

performance tests are conducted over a 12-month period (rolling monthly). Should an exceedance of the 

operating limit occur after the fourth performance test conducted over a 12-month period, a violation of 

the 30-boiler operating day rolling average occurs on the day of the exceedance. Further, each day in 

which an exceedance continues to occur (or a new one occurs) creates a rebuttable presumption of a 

separate violation of the 30-boiler operating day rolling average. 

Comment: Commenters (20258 and 20293) stated that EPA proposes to define a separate violation 

when more than four reference method tests result in a year because of exceedances of 30-day PM 

Continuous Parametric Monitoring System (“CPMS”) parameters. The Commenters stated that this limit 

is a 30-day limit, rolled monthly, and the source has 45 days to conduct the reference method test. The 

Commenters stated that during this time period additional exceedances of the CPMS parameters do not 

count and there is no violation unless the source is required to conduct more than four reference method 

tests in a year. The Commenters stated that up to 375 days of continuous noncompliance may elapse 

before a fifth reference method test occurs. 

Commenters (20258 and 20293) stated that EPA undercuts its establishment of a separate violation by 

asserting that this provision merely creates a rebuttable presumption. The Commenters stated that this 

“separate violation” therefore is illusory and of no particular benefit. The Commenters stated that 

instead, it can be read to limit the authority of permitting agencies to prove a violation based on a single 

gross exceedance of a parametric limit – such as data showing that the ESP has been turned off. 

Commenters (20258, 20264, and 20293) stated that 40 CFR §63.10021(c)(2) is unnecessary and 

unhelpful and they suggest that it be removed. 

Commenter (20264) said it is unclear what is meant by “separate violation” in the proposed new 

paragraph 63.10021(c)(2). The Commenter stated that EPA is proposing to take away the enforcement 

authorities’ discretion in deciding what is and what is not a violation when there has been a deviation 

from the CPMS operating limit. The Commenter stated that by explicitly stating that exceedances 

leading to more than four performance tests per year will be considered a violation, this paragraph 

implies that exceedances leading to four or fewer tests in a year cannot be considered a violation. The 

Commenter stated the enforcement authority’s ability to determine whether a CPMS deviation is a 

violation should not be limited in this way. 

Commenters (20258 and 20293) stated that if EPA intends to address those who chronically exceed their 

CPMS parameters, the Commenters suggest that the EPA identify a number of months in a year, perhaps 

two or three, where exceedances of a monthly CPMS parameter will require conversion of the 

monitoring system to a PM CEMS. The Commenters stated that EPA should also make clear that the 

permitting agency has the authority and the ability under the Credible Evidence rule to determine 
97 

whether a CPMS deviation is a violation of the underlying limit. 

Commenters (20258, 20264, and 20293) stated that if a facility reports, for example, that it has been 

operating at a level twice as high as its operating limit, the enforcement authority should be able to 

determine that there has been a violation of the standard. 

Commenter (20305) stated that the consequences for an exceedance of an indicator remain inadequate. 

The Commenter stated that the Agency would permit nearly six months (4 periods of 45 days, 180 days 

in total) of exceedances out of every 12 months – without finding a violation of the underlying standard. 

The Commenter stated that by permitting exceedances of the specified parameters – even with those 

provisions in place, and with an opportunity to rebut the presumed violation – the Agency is permitting 

plants to emit PM at levels exceeding the emission control of the best performing similar source, in 

violation of the Act. 42 U.S.C. §7412(d)(3). 

Response: The EPA disagrees with the Commenters’ concerns that the approach is inadequate for 

ensuring continuous compliance because the time period between an exceedance and testing could be 

long, thus leading to potential additional exceedances, and permits plants to emit PM at levels exceeding 

the emission limit in violation of the CAA. The final rule requires an EGU owner or operator to visually 

inspect the APCD within 48 hours of the exceedance, and to take corrective action as soon as possible to 

return the PM CMPS measurement to within the established value. In addition, an EGU owner or 

operator is required to conduct a performance test within 45 days of the exceedance to determine 

compliance and verify or re-establish the PM CMPS limit. The EPA finds it unlikely that there will be 

long periods of noncompliance with the underlying PM standard as estimated in some of the comments 

given the inspection and performance testing requirements. 

Moreover, the Credible Evidence rule still applies, and is not restricted by this approach. This approach 

does not limit in any way a permitting or enforcement authority’s ability to proceed with an enforcement 

action resulting from exceedances that do not trigger more than four performance tests in a 12-month 

period under this approach. 

 
98 

5.0 TECHNICAL CORRECTIONS AND CLARIFICATIONS 

5.1 Definitions (existing) 

Comment: Commenter (20285) asked that the EPA revise the definition of “coal refuse” in the Final 

MATS Rule. The Commenter stated that the definition of coal refuse in the MATS rule includes some 

additional qualifying language that is not included in the referenced NSPS provisions. The Commenter 

stated that these criteria are not supported by available data. The Commenter stated that coal refuse can 

be variable in many relevant characteristics, and provided discussion concerning that point. The 

Commenter requested that the EPA revise the definition for coal refuse to be consistent with the 

definition previously promulgated by EPA through the NSPS, at 40 CFR §60.41 and §60.41 Da. The 

Commenter suggested the following changes: 

“Coal refuse means any by-product of coal mining, physical coal cleaning, and coal 

preparation operations (e.g., culm, gob, etc.) containing coal, matrix material, clay, and 

other organic and inorganic material with an ash content greater than 50 percent (by 

weight) and a heating value less than 13,900 kilojoules per kilogram (6,000 Btu per 

pound) on a dry basis.” 

The Commenter discussed a further advantage to removing the heating value qualifier clarifies that coal 

refuse-fired FBC EGUs would be classified as EGUs not combusting low rank virgin coal. The 

Commenter stated that if the EPA does not revise the definition of coal refuse by eliminating the 

restriction on heating value, then the EPA should clarify which of the two subcategories for coal-fired 

EGUs under the MATS rule applies to coal refuse-fired FBC EGUs. 

The Commenter noted that the definition of coal refuse in the relevant NSPS references the word 

“waste.” The Commenter recommended the exclusion of this word from the definition of coal refuse in 

the Final MATS Rule, because currently-mined coal refuse is not a waste at the point of generation, and 

in general, coal refuse is not a waste at the point of combustion. 

Response: This issue is outside the scope of this rulemaking. The definition of “coal refuse” was 

addressed in the final rule (see, e.g., RTC, Vol. 2, pp. 709 - 710). The EPA did not solicit comment in 

the reconsideration proposal on the definition of “coal refuse.” 

Comment: Commenter (20285) stated that the EPA should revise the second sentence of the definition 

of dry FGD to clarify that the sorbent injection system in an FBC boiler need not be a separate, add-on 

air pollution control system located downstream of the EGU, in order to qualify as FGD. The 

Commenter requested that the EPA revise the definition of FGD by either eliminating the reference to a 

required back-end pollution control device, or clarifying that such reference does not apply to sorbent 

injection systems associated with FBC boilers. 

Response: This issue is outside the scope of this rulemaking. The EPA does not believe that there is any 

ambiguity in the definition of “dry flue gas desulfurization technology, or dry FGD, or spray dryer 

adsorber (SDA), or spray dryer, or dry scrubber” and that the definition clearly indicates that FBC and 

CFB boilers qualify the respective EGU for the alternate SO2 emission limit. 
99 

Comment: Commenter (20304) stated that multiple definitions of natural gas are not needed. The 

Commenter noted that the EPA has defined natural gas in 40 CFR Part 60, subpart Db, and 40 CFR Part 

63, subpart DDDDD. The Commenter discussed the varying caloric values of natural gas, and suggested 

that the EPA allow for averaging the gross caloric value over time (e.g., quarterly) to meet the 910 to 

1,150 Btu/dscf range. The Commenter recommended that the EPA revise the definition of natural gas to 

expand the range of gross caloric values to match the definition in Db. The Commenter stated that 

facilities do not have control over whether a pipeline company would add landfill gas if that material 

was available, and may not be informed about the addition of landfill gas. The Commenter stated that 

the facility may be liable for a deviation in that case. 

Commenter (20304) disagreed with the exclusion of the gases listed in the last part of the natural gas 

definition. The Commenter noted that the majority of these gases would not meet the minimum gross 

caloric value, but if they did and would meet the maximum sulfur content, there are no practical or 

technical reasons why these fuels would not create as clean a flame as would natural gas, and provide 

the facility with additional operating flexibility. 

Response: This issue is outside the scope of this rulemaking. The definition of “natural gas” was 

addressed in the final rule (see, e.g., RTC, Vol. 2, p. 700). The EPA did not solicit comment in the 

reconsideration proposal on the definition of “natural gas.” 

5.2 Definitions (new) 

Comment: Commenters (20258 and 20293) noted that EPA has proposed more lenient limits for certain 

pollutants for sources that are designed to burn “nonagglomerating virgin coal” having a heat value of 

less than 8,300 Btu/lb “that are constructed and operated at or near the mine that produces such coal” 

[emphasis added]. The Commenters noted that the term “at or near” is not defined and new coal-fired 

facilities could still claim the more lenient standard if they burn nominal amounts of low rank virgin 

coal and are within a short distance of the low rank virgin coal mine where they purchase the nominal 

amount of low rank virgin coal. The Commenters stated that one potential solution to this issue would be 

to write the rule so that only those EGUs that combust a minimum percentage of low rank virgin coal 

would qualify for the more lenient standard. The Commenters suggested that this percentage would be a 

reasonably high figure based on the fuel-use of the EGUs that were the basis of the standard. The 

Commenters stated that the rule should be written to ensure that there is not a third class, such as low 

rank virgin coal-fired EGUs that are not near the mine, for which no standards are applicable. 

Response: This issue is outside the scope of this rulemaking, and therefore EPA need not respond to the 

comment. The EPA maintains, however, that consideration of the “at or near” term is best left for 

specific implementation determinations. EGUs such as those noted by Commenters would need to meet 

the “designed to burn” part of the definition in addition to the “at or near” portion. 

5.3 Rule language 

Comment: Commenter (20282) supported the change to the term Rti in 40 CFR §63.10009(b)(2) (Eq. 

2a) and (3) (Eq. 3a). 

Commenter (20282) supported the correction to a reference in Appendix A §4.1 to the deadline for 
100 

initial compliance demonstration (replacing 40 CFR §63.10005(g) with §63.99849(f)). 

Response: The EPA appreciates the Commenter’s support for the corrections. 

Comment: Commenters (20282, 20294, and 20308) request that the EPA retain the 30-day notice for a 

performance test, as a 60-day notice is not reasonable for facilities conducting quarterly tests. The 

Commenters provided discussion about the importance of a 30-day notification period. 

Commenter (20308) disagreed with the changes to notification time frames in 40 CFR §63.10030 

paragraphs (b), (c), and (d). The Commenter noted that this may be in line with other parts of 40 CFR 

Part 63 and 40 CFR Part 60, but longer than the EPA’s current philosophy. The Commenter stated that 

40 CFR 75 has allowed reduced times of less than 30 days, not increased times. The Commenter stated 

that the requirement to make notifications 60 days prior to a test when quarterly testing may be utilized 

as the monitoring method does not allow flexibility of scheduling and will increase the notifications for 

changes that may occur on such a short time frame for compliance testing. The Commenter 

recommended keeping this time at 30 days. 

Commenter (20294) opposed changing the performance test notification period from 30 days to 60 days. 

According to the Commenter, a 30-day notification allows greater flexibility to take advantage of testing 

opportunities when system demand, equipment and contractor availability are in alignment with the 

Commenter’s testing needs. The Commenter noted that a 30-day notification will also reduce the 

occurrence of performance test rescheduling due to unforeseeable events such as emergency and/or 

unscheduled equipment repair, maintenance and malfunctions that may be more likely with multiple 

EGUs that share common pollution control equipment. 

Response: The EPA notes that the proposed 60-day notification requirement technical correction was 

provided to address previous concerns from some of the same Commenters that different advance notice 

of performance testing periods existed in the rule. Upon consideration of the Commenter’s concerns, and 

in concert with timelines allowed by the acid rain program, the rule has been changed to allow 30-day 

notices for performance tests. 

5.4 Other technical corrections and clarifications 

Comment: Commenter (20263) is fully supportive of EPA’s proposed revision of the new EGU Hg 

standard to 3.0E-3 lb/GWh. The Commenter stated the proposed revised limit combined with the recently 

confirmed capability of NIST to certify Hg calibration gas, and generators down to 0.2 μg/ as well NIST 

has the capacity to create a Zero gas for Hg by 2014. The Commenter asked that Hg gas calibration 

cylinders for both the pollutant and the zero gas be included in the reconsideration. 

Commenter (20263) noted an inconsistency between the requirements of 40 CFR Part 72.2 

(“Definitions”) and the discussion on continuous compliance within the proposed reconsideration: 

1) “Continuous emission monitoring system or CEMS means the equipment required 

by part 75 of this chapter used to sample, analyze, measure, and provide, by means of 

readings recorded at least once every 15 minutes (using an automated data acquisition 

and handling system (DAHS)).
101 

2) “Calibration error means the difference between: 

(1) The response of a gaseous monitor to a calibration gas and the known 

concentration of the calibration gas; 

(2) The response of a flow monitor to a reference signal and the known value of the 

reference signal. 

3) “Calibration gas means: 

(1) A standard reference material; 

(2) A standard reference material-equivalent compressed gas primary reference 

material; 

(3) A NIST traceable reference material; 

(4) NIST/EPA-approved certified reference materials; 

(5) A gas manufacturer’s intermediate standard; 

(6) An EPA protocol gas; 

(7) Zero air material; or 

(8) A research gas mixture. 

4) “Alternative monitoring system means a system or a component of a system designed 

to provide direct or indirect data of mass emissions per time period, pollutant 

concentrations, or volumetric flow, that is demonstrated to the Administrator as 

having the same precision, reliability, accessibility, and timeliness as the data 

provided by a certified CEMS or certified CEMS component in accordance with part 

75 of this chapter.” 

Commenter (20263) stated, in summary to the above excerpts from 40 CFR §72.2: 

1) It is evident that for a CEMS to qualify for Part75 the EGU must be challenged with a 

traced “compressed gas primary reference” of some manner. It is therefore that the 

Zero Gas should also be included in the MATS as a requirement to zero out the 

analyzers for the daily calibration check process. Gas generators cannot be used for 

CGAs and RATAs. 

2) Based on the criteria set in §72.2 a CEMS must be able to provide continuous data 

points at a minimum of every 15 minutes. 

3) If the monitoring system does not have the capability to be challenged by a traceable 

gas or cannot provide a minimum data set of every 15 minutes then it must be 

qualified as an Alternative Monitoring System (AMS) and will be subject to the 

requirements of 40CFR Part75; subpart-E in order to be used as a compliance device. 

Commenter (20263) concluded that these points are needed to be added to the MATS such that it will 

remain compliant with the Clean Air Management [sic] Division (CAMD) requirement. 

Commenter (20268) noted an inconsistency between the requirements of 40 CFR Part 72.2 

(“Definitions”) and the discussion on continuous compliance within the proposed reconsideration. The 

Commenter stated that if the monitoring system does not have the capability to be challenged by a 

traceable gas or cannot provide a minimum data set of every 15 minutes then it must be qualified as an 

Alternative Monitoring System (AMS) and will be subject to the requirements of 40 CFR Part 75; 

subpart-E in order to be used as a compliance device, and sorbent traps may fall in this category. The 

Commenter stated that this is not clear in the proposed reconsideration. 
102 

Response: The Commenter requests that Hg gas cylinders and zero gas be addressed in the 

reconsideration; the EPA sees no rationale for this. In the case of Hg cylinder gases, they are already 

addressed in several places both within Part 63, subpart UUUUU and within associated documents. In 

Section 3.1.4 of Appendix A of Subpart UUUUU, compressed gases are mentioned as suitable 

calibration standards if prepared according to the “EPA Traceability Protocol for Assay and 

Certification of Gaseous Calibration Standards” and though Hg gas cylinders are not specifically 

mentioned in the document, it would clearly be possible and appropriate to certify Hg gas cylinders 

through an unbroken chain of comparisons using NIST-traceable ‘vendor prime’ Hg gas generators (as 

defined in the “Interim EPA Traceability Protocol for Qualification and Certification of Elemental 

Mercury Gas Generators”28). The appropriate target uncertainty would be the same as that specified in 

the latest version of this interim protocol (currently 5 percent). Cylinder gases are also mentioned in the 

interim protocol as reference gases (see Section 3.20) and to perform periodic assessments of certified 

generators (see Section 7.1.4). The EPA sees no rationale for defining zero gases beyond what is 

specified in Section 3.1.8 of Appendix A of Subpart UUUUU which specifies ‘calibration gas 

containing a Hg concentration that is below the level detectable by the Hg gas analyzer in use. The EPA 

finds irrelevant the Commenter’s concerns regarding monitoring system inconsistencies between this 

rule and the acid rain rules. It is not unreasonable that the MACT program has differing requirements 

than the acid rain program given the different mandates of the programs. The requirements for this rule’s 

Hg monitoring and HCl/HF monitoring systems are provided in Part 63, subpart UUUUU, Appendices 

A and B, while the concerns mentioned by the Commenter are found in Parts 72 and 75. The 

Commenters’ assertion that complete consistency with Part 72 and 75 monitoring requirements must be 

achieved for this rule’s unique monitoring systems is inappropriate and beyond the scope of this 

rulemaking. 

 

28 http://www.epa.gov/ttnemc01/metals/ElemHgProtocol.pdf, from July 1, 2009. Also available in 

Docket ID EPA-HQ-OAR-2009-0234. 
103 

6.0 IMPACTS AND COST ANALYSIS 

6.1 Air Impacts 

Comment: Commenter (20249) stated that the EPA addresses control technologies needed to meet the 

NESHAP and NSPS emission limits for a new source in Item 7 of Section IV. The Commenter said, 

based on an analysis of control requirements for a new hypothetical 500 MW facility, the EPA 

concluded that new EGUs would need to be designed to use the same types of emission control 

technologies to meet the proposed new source limits as would have been needed to meet the final MATS 

new source limits. The Commenter stated, however, that the EPA chose a hypothetical EGU of roughly 

median size (500 MW). The Commenter said this approach may not address design and operation 

limitations of such controls when EGU sizes approach either the minimum and maximum size. 

Response: The EPA evaluated the types of emission controls that would generally be necessary to meet 

the final new source limits and compared those to the types of emission controls that would generally be 

necessary to meet the proposed reconsideration new source limits. The EPA chose to examine the level 

of control needed at a hypothetical 500 MW plant. However, the size of the EGU is irrelevant – the EPA 

could have just as easily compared the controls needed at a 100 MW plant or at a 900 MW plant. In each 

case, the comparison would have been between the controls needed to meet the final new source limits 

and the controls needed to meet the proposed reconsideration new source limits. Our conclusion would 

have been the same. Any “design and operation limitations” of the controls would have been present 

whether the EGU was attempting to meet the final limits or the proposed reconsideration limits. 

Comment: Commenter (20249) stated when addressing control technologies in Item 7 of Section IV, 

the EPA also analyzed controls on existing sources to determine whether existing sources can meet 

standards for new sources. The Commenter said the EPA performed this analysis even though it asserts 

that nothing in the statute (CAA) requires the EPA to make such a demonstration. The Commenter 

stated, as evidenced by Figure 1, Example sorbent injection performance curve, in the November 16, 

2012, EPA Memorandum from Nick Hutson, the effectiveness of controls can diminish as higher 

removal rates are targeted. The Commenter stated there can be inordinate costs associated with 

achieving an incremental amount of additional emissions reduction. 

Response: The EPA agrees that the effectiveness of controls can diminish as higher removal rates are 

targeted and that there can be inordinate costs associated with achieving an incremental amount of 

additional emissions reduction. The cost effectiveness for incremental levels of control was examined in 

the BTF analysis (see Section 3.0 of this document for additional detail). When setting MACT emission 

limits for the new source categories, the EPA determined the emission limitation achieved in practice by 

the best performing existing source within that category. The EPA then incorporated inherent variability 

(e.g., process, fuel, operational) using the “upper predictive limit” methodology that has been explained 

elsewhere. 

CAA §112(d)(2) requires that the Agency promulgate standards that “shall require the maximum degree 

of reduction in emissions...that the Administrator, taking into consideration the cost of achieving such 

emission reduction, and any non-air quality health and environmental impacts and energy requirements, 

determines is achievable...” This is referred to as the BTF analysis. The EPA has, as directed by 

Congress, considered the cost of achieving “the maximum degree of reduction” and in all cases, except 
104 

one, found the costs of achieving a BTF level of control to be not cost-effective or unreasonable. 

6.2 Energy Impacts 

Comment: Commenter (20266, 20286, and 20301) stated that the EPA has not addressed how the 

proposed issues under reconsideration will impact electric power grid reliability. 

Commenters (20266, 20286, and 20301) stated that they expressed these concerns in previous comments 

on the proposed rule regarding the EPA’s erroneous assumptions regarding the Electric Reliability 

Council of Texas (ERCOT) and the Texas electric power grid. The Commenters expressed concerns that 

EPA had significantly understated the effects of the rule on electric reliability and electricity prices in 

Texas, and had made incorrect assumptions regarding the Electric Reliability Council of Texas 

(ERCOT) and the Texas power grid in the rule. Commenter (20286) stated that the EPA continued to 

perpetuate those errors in the final rule, relying on incorrect information when evaluating the potential 

effects of the final rule on electric reliability. The Commenters stated that in its final rule, the EPA 

acknowledged and corrected one of its errors, but otherwise failed to revise its analysis to correct the 

numerous other errors and invalid assumptions enumerated by their earlier comments. The Commenters 

stated that by failing to address how the proposed reconsideration would impact electric reliability, the 

EPA compounds these errors further, while refusing to provide transparent information to the public for 

review and comment. 

Response: This issue is outside the scope of this rulemaking. The EPA has addressed the issue of 

reliability in the final rule (see, e.g., 77 FR 9406 - 9411). The impacts of this rulemaking are further 

minimized because it only addresses new sources. 

6.3 Economic Impacts/Employment Impacts 

Comment: Commenter (20273) stated that the reconsidered MATS will discourage the use of petroleum 

coke, a fuel Commenter asserts is abundant, affordable, and renewable. The Commenter noted that 

regardless of whether the Commenter’s facility is built, petroleum coke will continue to be produced in 

large quantities as part of the oil refining process. The Commenter stated that they are developing a new, 

petroleum coke-fueled electric generation project in Corpus Christi, Texas. The Commenter stated that if 

this facility is brought on-line, it will serve a vital role in addressing the shortfall in electric generating 

capacity facing Texas. The Commenter noted that the new facility’s EGUs will burn 100 percent solid 

oil-derived fuel, i.e., petroleum coke, a product of nearby refineries. The Commenter stated that using 

CFB boiler technology to generate approximately 1,200 net megawatts of electricity, the new facility 

would generate enough electricity to power more than 850,000 Texas homes. 

Commenter (20273) stated that each year, approximately 1.7 million tons of petroleum coke are 

produced in Corpus Christi and approximately 35 million tons are produced throughout other parts of 

the Gulf Coast region. The Commenter says that presently, the majority of Gulf Coast petroleum coke is 

transported to remote international markets where it is burned in cement kilns, power plants, and other 

processes. The Commenter stated that because petroleum coke will continue to be generated as part of 

the petroleum refining process and, because this fuel will continue to be shipped abroad and burned for 

energy recovery in the absence of a local consumer, operation of the well-controlled new facility would 

result in a net decrease in air emissions, including global Hg and GHG emissions versus the present 
105 

alternative uses. The Commenter noted that the new facility will use CFB boilers for steam generation 

where limestone is injected into the CFB for in-bed desulfurization, and a CDS-FGD system and a fabric 

filter located downstream of the CFB boilers. The Commenter stated that injection of powdered 

activated carbon (“PAC”) for Hg capture will be employed upstream of the CDS-FGD system. The 

Commenter noted that using this fuel locally will eliminate the GHG emissions associated with the 

transportation of petroleum coke to international markets, the new facility will more efficiently convert 

the petroleum coke into useful energy relative to other users, and it will employ emission controls that 

will result in significantly lower amounts of Hg and other air emissions relative to other users. 

Commenter (20273) stated that despite the obvious benefits to the environment from using domesticallyproduced solid oil-derived fuel at the Commenter’s new facility and even as revised, the EPA’s 

proposed reconsidered MATS, will likely cause the Commenter to abandon development of its new 

facility and the unique opportunity of locating a significant and much-needed power generation facility 

near an abundant, affordable, and renewable fuel supply will be lost. The Commenter disagreed with the 

revised standards as a matter of policy. The Commenter stated that EPA should modify the reconsidered 

MATS applicable to solid oil-derived fuel for EGUs because the proposed standards will discourage, if 

not preclude, the use of these EGUs. 

Response: The EPA disagrees with Commenter’s allegation that the proposed reconsidered limits will 

discourage or preclude construction or use of solid oil-derived fuel-fired EGUs, as the data used to 

establish the emission limits came from such EGUs and the Commenter has provided no information to 

support an argument that the final limits cannot be achieved on a new solid oil-derived fuel-fired EGU. 

Comment: Commenter (20274) stated that the price of energy is a significant concern to the 

Commenter’s members, and that small-business owners depend on energy supplies at globally 

competitive prices to operate and effectively run their businesses. The Commenter cited the most recent 

edition of NFIB’s Small Business Problems and Priorities, published earlier this year, and stated that the 

cost of energy was reported by NFIB members to be the third most important problem facing their 

company. The Commenter stated that nearly 35 percent of survey respondents cited the issue as a 

“critical” problem. 

Commenter (20274) stated the way that the Utility MACT rule is structured will mean significant 

increases in energy rates. The Commenter stated that the Final Rule finalized in February is the most 

expensive in U.S. history and the Reconsideration has done little to alleviate this burden. The 

Commenter stated that small businesses cannot afford to spend more on energy, and that the rule 

threatens energy reliability. 

Commenter (20274) asked that the EPA issue a rule that addresses the target pollutants commensurate 

with the benefits of reducing the target pollutants. 

Response: This issue is outside the scope of this rulemaking. The EPA has addressed the price of 

electricity and the potential impact of MATS in the final rule (see, e.g., 77 FR 9414). The impacts of this 

rulemaking are further minimized because it only addresses new sources. 

6.4 Health Co-Benefits 
106 

Comment: Commenter (20305) stated that recent studies continue to demonstrate that methylmercury 

impacts are widespread and significant, impact more wildlife species than previously recognized, and 

adversely affect fish and wildlife at lower concentrations. The Commenter cited several recent studies 

that discuss the extent of Hg in the environment. The Commenter stated that research continues to 

confirm that coal-fired power plants contribute to significant local Hg contamination and exposure. The 

Commenter cited a recent study of Hg levels in infants, and cited a recent study on the widespread 

health effects to all organs in the human body. 

Commenter (20305) discussed the role of PM2.5 and toxic metal content on human health, citing several 

journal articles, and discussed carcinogenic emissions and cancer risks, citing three studies. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding additional health impacts. 

6.5 Other impacts and cost analysis 

Comment: Commenter (20247) stated that the use of powdered activated carbon (PAC) injection for Hg 

control has been linked to fires in baghouse hoppers. According to the Commenter, loss on ignition 

(LOI) is one of the key parameters in assessing the risk of fire and although not all the factors affecting 

auto-ignition potential are known, a target LOI level in the fly ash of 10 percent provides a reasonable 

margin from the level of 15 percent identified by the Institute of Clean Air Companies (ICAC) as a level 

at which auto-ignition did not occur. The Commenter stated that the LOI should be taken into account in 

evaluating the PAC and Hg emission limits on newly constructed EGUs and recommends that EPA 

allow the regulating agency with primacy over the program to consider LOI levels on a case-by-case 

basis and use a target LOI level in the fly ash of 10 percent to provide a reasonable margin from the 

value determined by ICAC. 

Response: The EPA is aware of such instances as Commenter notes in early installations of activated 

carbon injection. However, the EPA believes these issues have been resolved and ACI is installed and 

being used successfully, without fire issues, on a wide range of EGUs. Individual companies and their 

engineering firms should always consider safety in the design of all of their emission controls. 

Comment: Commenter (20307) stated that the purpose of the Commenter’s filing is to express an 

interest in these matters and to note some consistencies between the Agency’s action in reconsidering 

some provisions of previously proposed rules with the Commenter’s studies on regulatory policy. The 

Commenter cited: Resolution on the Role of State Regulatory Policies in the Development of Federal 

Environmental Regulation and subsequent Resolution on Increased Flexibility for the Implementation of 

EPA Rulemakings. The Commenter emphasized the need for environmental and energy policies that 

ensure continued emission reduction progress that also enhances energy reliability and lower costs. 

Commenter (20307) cited Resolution on the Role of State Regulatory Policies in the Development of 

Federal Environmental Regulation, stating that this resolution set forth the Commenter’s initial position 

on the development of public health and environmental regulations that will directly affect the electric 

power sector. In this resolution the Commenter acknowledged that such regulations could pose 

economic, feasibility and reliability challenges. The Commenter stated that state utility regulators are 

well positioned to evaluate risks and benefits of various resource options through policies that 
107 

appropriately account for and mitigate the risks arising from compliance with pending regulations. The 

Commenter said that state utility regulators, by working with the power sector and State and federal 

environmental regulators, can help to facilitate least-cost compliance with public health and 

environmental goals. 

Commenter (20307) stated the Resolution on the Role of State Regulatory Policies in the Development 

of Federal Environmental Regulation includes several policy resolves that pertain specifically to the 

Agency in developing public health and environmental programs such as MATS. The Commenter urged 

the Agency through this resolution to: 1) seek ways to minimize cost impacts to consumers, 2) ensure 

that its actions do not impair the availability of adequate electricity and natural gas resources, and 3) 

recognize the needs of states and regions to deploy a diverse portfolio of cost-effective supply-side and 

demand-side resources based on the unique circumstances of each state and region. 

Commenter (20307) recognized the need for increased flexibility for the implementation of Agency 

rulemakings. The Commenter stated that there are many strategies available to states and utilities to 

comply with EPA regulations, including 1) retrofits and installation of pollution control equipment, 2) 

construction of new power plants, 3) transmission upgrades to provide resources adequacy and system 

security where needed when power plants retire, 4) purchases of power from wholesale markets, 5) 

demand response, 6) energy efficiency, and 7) renewable energy policies -- the collection of which can 

be implemented at different time frames by different interested parties and may constitute lower-cost 

options that provide benefits to ratepayers. The Commenter stated that the proposed revisions to the new 

sources standards represent changes that may assist with preserving the multitude of options available to 

comply with the Agency’s hazardous air pollution standards. 

Response: This comment requires no response. 
108 

7.0 GENERAL COMMENTS 

Comment: Commenters (20244, 20259, and 20260) stated that EPA should eliminate the use of coal. 

Response: This comment is outside the scope of this rulemaking, as the EPA is only establishing certain 

revised emission limits for new sources rather than setting national energy policy. 

Comment: Commenters (20309, 20310, 20311, 20312, and 20313) stated that EPA should not weaken 

the Mercury and Air Toxics Standard. The Commenters opposed loosening of the Hg and other emission 

standards while reclassifying synthetic natural gas derived from coal, ULSD fuel and propane as clean 

fuels as this designation places those pollutants outside of EPA’s rule. The Commenters stated that such 

fuels emit GHGs, are not clean fuels and that EPA is putting industry interests ahead of protecting public 

health. 

Response: The EPA does not believe that the MATS rule is being weakened, as alleged by 

Commenters. Further, as this rulemaking addresses hazardous air pollutants (HAP), comments on GHG 

issues are outside the scope of the rulemaking. 
109 

8.0 OTHER OUT OF SCOPE 

Comment: Commenter (20256) stated that, similar to its recalculation of the new source MACT floors 

based on all of the emissions data in the record, the EPA must be consistent it its approach in the 

establishment of the MACT limits for existing sources as well. In particular, the Commenter stated that 

the input based emissions standard for PM for existing “petroleum coke units” should similarly be 

revised by EPA based on all of the emissions data in the record from the “best performing” EGUs. The 

Commenter’s February 17, 2012, petition seeking reconsideration includes a detailed analysis of data 

from the “best performing” petroleum coke EGUs. 

Response: This issue is outside the scope of this rulemaking. The EPA did not solicit comment in the 

reconsideration proposal regarding the existing-source emission limits. 

Comment: Commenter (20248) requested that EPA reconsider the stack testing requirements related to 

demonstrating compliance for non-mercury metals and acid gases and provide the opportunity to scale 

back testing after a demonstration period. The Commenter stated that the EPA should recognize the 

difficulty in planning stack tests for EGUs that are not base load. The Commenter noted that stack tests 

require coordinating schedules with the regional Independent System Operator (ISO), state agencies, 

stack test contractors, and plant operations. The Commenter stated that it is very difficult to align 

schedules and as a result EGUs will be forced on for the sole purpose of stack testing. The Commenter 

observed that reducing the frequency of testing will satisfy the EPA’s desire for EGUs to demonstrate 

consistent emissions profiles, while eliminating unnecessary emissions and minimizing the burden on 

resources. The Commenter requests that the EPA reduce the LEE demonstration period to quarterly 

testing for 1 year and that the EPA revert back to the original MATS proposal for subsequent LEE tests 

to be conducted every 5 years. For EGUs not eligible for LEE, the Commenter requests quarterly testing 

for 1 year and, provided each quarterly test nets a compliant result, test frequency would be reduced to 

annually. 

Response: These issues are outside the scope of this rulemaking. The EPA did not solicit comment in 

the reconsideration proposal regarding the existing-source emission limits or on monitoring issues 

related to existing sources. 

Comment: Commenter (20262) stated that they were confused about when and how to demonstrate 

compliance with several of the tune-up provisions of 40 CFR §63.10005(e-f) and §63.10021(e) and 

encouraged EPA to issue more guidance or make clarifications within the rule. The Commenter 

provided several examples of tune-up provisions in need of additional guidance or clarification. 

Response: Issues such as those noted by Commenter are outside the scope of this rulemaking. If there 

are questions or concerns about the implementation of the final MATS rule for existing sources, the 

owners or operators should contact the EPA or the appropriate state authority. 

Comment: Commenter (20262) stated that EPA should allow the use of the diluent cap for all hours 

outside of these thresholds, not just for hours that fit within EPA’s narrow definition of startup and 

shutdown. The Commenter stated that this would be consistent with 40 CFR Part 75 Appendix F Section 

3.3.4.1 for calculating lb NOX/MMBtu. The Commenter stated that this concept should likewise be 

applied to calculating HCl (Appendix B to subpart UUUUU) emissions. 
110 

Response: This issue, expansion of diluent cap use, is outside the scope of this rulemaking. The EPA 

neither proposed nor requested comments on this issue; thus, the EPA is not addressing this comment. 
111 

9.0 INCORPORATE BY REFERENCE 

Comment: Commenter (20243) incorporated by reference comments from the National Rural Electric 

Cooperative Association (NRECA; no docket number) and Utility Air Regulatory Group (UARG; 

Docket ID EPA-HQ-OAR-2009-0234-20282). 

Commenter (20253) stated that they incorporated by reference comments submitted to EPA during the 

initial MATS rulemaking that provide support for its arguments regarding the availability of natural gas, 

cost effectiveness, non-air quality health and environmental impacts, the need for EPA to consider the 

use of cleaner fuels under the MACT standards, and the BTF requirements. The Commenter also 

incorporated by reference comments including those of America’s Natural Gas Alliance (Docket ID 

EPA-HQ-OAR-2009-0234-17810), Julander Energy Company (Docket ID EPA-HQ-OAR-2009-0234-

18423), and the comments originally submitted by the Commenter (20253) (Docket ID EPA-HQ-OAR2009-0234-17852). 

Commenter (20255) stated that they endorse and adopt the comments submitted by American Electric 

Power Company (Docket ID EPA-HQ-OAR-2009-0234-20308). 

Commenter (20281) incorporated by reference comments from UARG (Docket ID EPA-HQ-OAR2009-0234-20282). 

Commenter (20285) incorporated by reference and reasserted, by the extent applicable, their comments 

in their Petition for Reconsideration of the Final MATS Rule. 

Commenter (20295) supports the comments of UARG (Docket ID EPA-HQ-OAR-2009-0234-20282), 

and incorporated by reference their own comments submitted for the 2011 proposed MATS rule. 

Commenter (20305) incorporated by reference 10 scientific articles concerning the dangers of Hg, three 

articles about PM and toxic metals and human health, and three articles about airborne carcinogens. 

Commenter (20266) has reviewed and fully endorses the comments of Public Utility Commission of 

Texas (Docket ID EPA-HQ-OAR-2009-0234-20301) and TCEQ (Docket ID EPA-HQ-OAR-2009-

0234-20286). 

Commenter (20277) fully supports and incorporates by reference the comments of UARG (Docket ID 

EPA-HQ-OAR-2009-0234-20282) including its attachment prepared by RMB Consulting and Research, 

Inc., and EEI (Docket ID EPA-HQ-OAR-2009-0234-20295). 

Commenter (20276) stated that they support and incorporate by reference the comments made by the 

Edison Electric Institute (EEI) (Docket ID EPA-HQ-OAR-2009-0234-20295) and the UARG (Docket 

ID EPA-HQ-OAR-2009-0234-20282). 

Commenter (20308) incorporated by reference comments from UARG (Docket ID EPA-HQ-OAR2009-0234-20282). The Commenter also incorporated by reference their comments submitted on the 

proposed MATS rule (Docket ID EPA-HQ-OAR-2009-0234-19114) regarding long-term achievability 

of the standards and IGCCs. 
112 

Commenter (20306) incorporated by reference comments from EEI (Docket ID EPA-HQ-OAR-2009-

0234-20295), GCA (Docket ID EPA-HQ-OAR-2009-0234-20288), and UARG (Docket ID EPA-HQOAR-2009-0234-20282). 

Commenter (20303) incorporated by reference comments from NRECA and GCLC (Docket ID EPAHQ-OAR-2009-0234-20275). 

Commenter (20301) agreed with and supported the comments made by TCEQ (Docket ID EPA-HQOAR-2009-0234-20286). 

Commenter (20300) incorporated by reference comments submitted for the proposed MATS rule in 

2011 (Docket ID EPA-HQ-OAR-2011-0044-5715). 

Commenter (20256) endorsed and incorporated by reference comments submitted by the UARG 

(Docket ID EPA-HQ-OAR-2009-0234-20282) that comment’s attachment, prepared by RMB 

Consulting & Research, Inc. (RMB). The Commenter also incorporated by reference the relevant 

portions of their earlier, more extensive comments on the proposed rule dated August 4, 2011. 

Commenters (20257 and 20270) supported and endorsed the comments submitted by UARG (Docket ID 

EPA-HQ-OAR-2009-0234-20282). 

Commenters (20262 and 20291) endorsed the comments submitted by the EEI (Docket ID EPA-HQOAR-2009-0234-20295) and UARG (Docket ID EPA-HQ-OAR-2009-0234-20282). 

Commenter (20271) stated that they support and incorporate by reference the comments of EEI (Docket 

ID EPA-HQ-OAR-2009-0234-20295). 

Commenter (20294) stated that they support and incorporate by reference the comments of EEI (Docket 

ID EPA-HQ-OAR-2009-0234-20295), EPRI (Docket ID EPA-HQ-OAR-2009-0234-20261) and AEP 

(Docket ID EPA-HQ-OAR-2009-0234-20308). 

Commenter (20275) incorporated by reference, as applicable, comments submitted to the proposed 

MATS rule: Docket ID EPA-HQ-OAR-2009-0234-17930; Docket ID EPA-HQ-OAR-2011-0044-5240. 

Commenter (20321) stated that they support the comments of the Class of ‘85 Regulatory Response 

Group (Docket ID EPA-HQ-OAR-2009-0234-20269). 

Response: The comments have been addressed elsewhere in this document. The EPA notes that 

NRECA did not submit comments on the reconsideration proposal. 
113 

10.0 OTHER COMMENTS NOT COVERED 

Comment: Commenter (20238) stated that had the EPA indicated in any way that the Agency planned 

to use CAA §111(d) to require states to draft and seek approval from the Agency for a SIP requiring 

existing emission sources to comply with the emission limits set forth in this and in the original rules on 

which the reconsideration is based, the Commenter would have submitted substantial comments. 

Response: As this rulemaking is conducted under CAA section 112, this comment is not relevant. 

Comment: Commenter (20270) recommended that the EPA consider all of the items addressed in 

petitions for reconsideration and provide further opportunity to comment on those issues as well. The 

Commenter stated that utilities are in the process of planning for compliance and need further 

clarification and/or revisions in order to proceed. 

Response: The EPA is still evaluating the reconsideration issues that the November 30, 2012, 

reconsideration notice did not address. 
114 

11.0 DUPLICATE COMMENTS 

Docket entries identified as duplicate comments are: 20278, 20283, 20314, 20317.