Summary of EGU NSPS Public Comments and Responses on Amendments 

Proposed November 30, 2012 (77 FR 71323) 

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 

 
The primary contact regarding questions or comments on this document is: 

Christian Fellner 

U.S. Environmental Protection Agency 

Energy Strategies Group (D243-01) 

Research Triangle Park, North Carolina 27711 

Email: fellner.christian@epa.gov
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Table of Contents

LIST OF COMMENTERS ............................................................................................................. 1

1.0 NATURAL GAS DEFINITION .......................................................................................... 2

2.0 IGCC DEFINITION ............................................................................................................ 3

2.1 Definition Similar to the Definition in the MATS ........................................................... 3

2.2 Alternative NSPS IGCC definition with changes ............................................................ 3

3.0 FILTERABLE PM EMISSIONS ......................................................................................... 5

3.1 Measuring and Averaging Changes ................................................................................. 5

3.2 Opacity Monitoring .......................................................................................................... 6

4.0 TECHNICAL CORRECTIONS .......................................................................................... 8

5.0 COMMENTS ON TOPICS NOT PROPOSED FOR RECONSIDERATION ................... 9

5.1 NOX and SO2 Emission Rates and Compliance ............................................................... 9

5.2 Use of a Digital Opacity Compliance System .................................................................. 9

6.0 GENERAL COMMENTS ................................................................................................. 10

7.0 INCORPORATION BY REFERENCE ............................................................................ 11
1 

LIST OF COMMENTERS 

Commenter Name Commenter Organization EPA Docket ID

Steve Jenkins CH2M Hill Engineers, Inc. EPA-HQ-OAR-2011-0044-5781 

Mark Sokolow Law Office of Mark Sokolow EPA-HQ-OAR-2011-0044-5790 

Claire M. Olson Basin Electric Power Cooperative EPA-HQ-OAR-2011-0044-5791 

Lee B. Zeugin Hunton & Williams LLP et al. on behalf of 

Utility Air Regulatory Group (UARG) EPA-HQ-OAR-2011-0044-5794 

Myra Glover Entergy Services, Inc. EPA-HQ-OAR-2011-0044-5796 

Greg F. Myers Consumers Energy EPA-HQ-OAR-2011-0044-5798 

Paul M. Ling Kansas City Power & Light Co. (KCPL) EPA-HQ-OAR-2011-0044-5801 

Kenneth J. Anderson Ameren Corporation EPA-HQ-OAR-2011-0044-5805 

J. Michael Geers Duke Energy et al. EPA-HQ-OAR-2011-0044-5806 

Norman Shilling General Electric Co. (GE) EPA-HQ-OAR-2011-0044-5813 

Raymond L. Evans FirstEnergy Corporation (FE) EPA-HQ-OAR-2011-0044-5814 

Eli Brill Waste Management (WM) EPA-HQ-OAR-2011-0044-5818 

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

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 

Myra Glover Entergy Services, Inc. EPA-HQ-OAR-2009-0234-20279 
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1.0 NATURAL GAS DEFINITION 

Comment: Commenter (5791) noted that their subsidiary owns and operates a commercial-scale coal 

gasification plant that manufactures synthetic natural gas from lignite. The commenter stated that the 

synthetic natural gas produced at the commenter’s plant chemically satisfies the definition of “natural 

gas” contained in the first sentence of the reconsideration, but the phrase “coal-derived gas” in the last 

sentence of the new definition makes synthetic natural gas fall out of the definition. The commenter 

recommended that the natural gas definition should reflect chemical composition, rather than point of 

origin. The commenter recommended the following language: 

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), 

composed of at least 70 percent methane by volume or that has a gross calorific value 

between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per 

dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, 

natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, 

natural gas does not include the following gaseous fuels: landfill gas, digester gas, 

refinery gas, sour gas, blast furnace gas, coal-derived gas (except for synthetic natural gas 

that meets pipeline standards or the definition in 40 CFR § 63.7575. Subpart DDDDD), 

producer gas, coke oven gas, or any gaseous fuel produced in a process which might 

result in highly variable sulfur content or heating value. 

Response: The EPA has concluded that the suggested change is unnecessary. The amendments 

discussed below have the same effect as the one suggested by the commenter and coal-derived synthetic 

natural gas will be treated the same as natural gas. Even though the amended definition of natural gas 

excludes coal-derived synthetic natural gas, paragraph 60.42Da(b)(2) has been amended to include 

“and/or synthetic gas that chemically meets the definition of natural gas.” This paragraph exempts 

facilities burning coal-derived synthetic natural gas from the opacity standard. In addition, paragraph 

60.49Da(a)(4) has been amended by changing “natural gas” to “gaseous fuel” so that coal-derived 

synthetic natural gas-fired facilities have the same SO2 monitoring options as natural gas-fired facilities. 

Comment: Commenter (20247) stated that the exclusion of coal-derived gas from the definition of 

natural gas (40 CFR 61.41Da) may create ambiguity when compared to the change that includes 

synthetic natural gas as an acceptable startup fuel. The Commenter suggested the following change in 

the definition of natural gas: 

“Natural gas means . . . coal-derived gas (except for synthetic natural gas that meets 

pipeline standards or the definition in 40 CFR §63.7575, Subpart DDDDD), . . . 

Response: This comment addresses an issue related to startup and shutdown. As the EPA is not taking 

final action on requirements applicable during periods of startup and shutdown at this time we are not 

responding to this comment. 

Comment: Commenter (5818) agreed with the proposed definition of natural gas. The commenter 

supported the proposed definition that clarifies that landfill gas is among the specific gaseous fuels that 

do not qualify as natural gas under Subpart Da, and thus, is not a fossil fuel as defined under Subpart Da 

and other air pollution regulations governing the combustion of fossil fuels, such as EPA’s MATS. 

Response: No response necessary. 
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2.0 IGCC DEFINITION 

2.1 Definition Similar to the Definition in the MATS 

Comment: Commenter (5813) noted that while either of the IGCC definitions effectively address the 

issue of IGCC facilities switching applicability between the stationary combustion turbine NSPS and the 

Utility NSPS, they prefer the alternate definition. The commenter stated the alternate definition provides 

classification certainty throughout the life of the IGCC plant and also allows more flexibility as any 

solid-based fuel can be used. The commenter further stated that it is unlikely that a combined cycle 

would be modified to burn solid-derived fuel due to the technical difficulty, cost and outage 

requirements. The commenter stated that it may be challenging for IGCC units firing natural gas to meet 

Subpart KKKK requirements. The commenter stated that projects that initially install natural gas 

turbines with the intent to later convert to syngas would need to be permitted as natural gas units (under 

subpart KKKK). 

Response: No response necessary since the alternate IGCC definition has been finalized. 

Comment: Commenters (5781, 5794, 5806) noted that the regulatory language in proposed §60.41Da 

(Definitions) has inadvertently inserted the word “natural” between “synthetic” and “gas.” 

Commenter (5813) stated that the proposed IGCC definition could cause syngas to be confused with 

synthetic natural gas that could lead to unintentional requirements to meet lower limits for natural gasfired plants. The commenter suggested these changes: 

“Integrated gasification combined cycle electric utility steam generating unit or IGCC 

electric utility steam generating unit means an electric utility combined cycle gas turbine 

that burns a synthetic natural gas (syngas) derived from coal and/or solid oil-derived fuel 

for more than 10.0 percent of the average annual heat input during any 3 consecutive 

calendar years or for more than 15.0 percent of the annual heat input during any one 

calendar year in a combined cycle gas turbine. No solid coal or solid oil-derived fuel is 

directly burned in the unit during operation.” 

Response: No response necessary since the alternate IGCC definition has been finalized. IGCC facilities 

burning synthetic gas will be subject to the requirements in subpart Da and not subpart KKKK.

2.2 Alternative NSPS IGCC definition with changes 

 

Comment: Commenters (5794, 5806) supported the alternate definition for IGCC electric utility steam 

generating units, including the phrase “startup and commissioning, shutdown,” as Commenter (5794) 

suggested in response to the 2011 proposed rule. Commenter (5794) stated that their preferred definition 

concerns design rather than operation, which is the appropriate focus. 

Commenter (5813) preferred the alternative definition modified from the NSPS definition of IGCC. The 

commenter stated that the modified definition provides certainty as to classification as a solid fuel plant 

and fuel flexibility. 

Response: The alternate IGCC definition has been finalized as suggested by the commenters. 
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Comment: Commenter (5813) stated that having different definitions applying to IGCC in the MATS 

and NSPS rules is a confusing and unnecessary inconsistency, and that EPA should consider changing 

the MATS definition to that in the NSPS. 

Response: We have concluded that the alternative definition is most appropriate and are adopting the 

definition which is consistent with the Agency’s statements on IGCC contained in the RTC in support of 

the final Utility NSPS rule published on February 16, 2012 (77 FR 9304). The Utility NSPS IGCC 

definition deals with the intent of an IGCC facility and is, thus, broader than the definition in the MATS 

NESHAP. The facility would still be subject to the same criteria pollutant emission standards even when 

burning natural gas for extended periods of time. The MATS NESHAP applicability is determined based 

on the EGU’s utilization of coal and oil and the rule may not apply depending on the extent of natural 

gas usage. 

Comment: Commenter (5813) stated that the uncertainty of the Administrator’s discretion in the NSPS 

definition (“may waive”) is of concern. The commenter recommended that the EPA change the word 

“may” to “shall” in the alternative definition (2) so there is not an indeterminate regulatory application 

or interpretation that subjects an IGCC unit to dual regulatory requirements during its operational life. 

Response: The EPA has concluded that “may waive” is an appropriate use of the Administrator’s 

discretion. Every situation is site specific, and the burden is on the owner/operator to present the case for 

why the combustion of nonsolid-derived fuels is within the intent of the design of the facility. 

 
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3.0 FILTERABLE PM EMISSIONS 

3.1 Measuring and Averaging Changes 

Comment: Commenter (5794) agreed that Subpart Da and Subpart UUUUU should use the same 

calculation and monitoring procedures for new unit emission rate calculation procedures and monitoring 

options for filterable PM. 

Commenter (5794) stated that Subpart Da and Subpart UUUUU should have the same option for use of 

quarterly stack tests. 

Response: With respect to this issue, the same rationale applies to both the NSPS and NESHAP. 

Therefore, the finalized calculations and monitoring procedures for PM are the same for the NESHAP 

and NSPS and the quarterly stack testing option has been removed. EGUs complying with an outputbased emissions standard can be designed to incorporate PM CEMS or PM CPMS from the outset, 

without being impeded by retrofit location installation constraints that would impact existing EGUs. 

Continuous direct measurement of either filterable PM or a correlated parameter are preferable to 

quarterly stack testing for determining compliance on a continuous basis, Therefore, this final action 

requires EGUs complying with an output-based standard to use either PM CEMS or PM CPMS as 

options for determining compliance with the PM limits. 

Comment: Commenter (5794) supported the EPA’s revision of the rule to allow facilities constructed, 

reconstructed, or modified after May 3, 2011 the alternative of complying using the PM CPMS or 

quarterly stack testing options. The commenter stated that the EPA cannot require Subpart Da sources to 

use a compliance method – PM CEMS – that has not been demonstrated to be feasible or accurate for 

that purpose. The commenter stated that to require use of PM CEMS, EPA must evaluate data from PM 

CEMS in the standard setting process, and establish the achievability of the required PS 11 correlation 

criteria at the level of the applicable standard. The commenter recommended that if the EPA does not 

finalize the language allowing use of the PM CPMS and quarterly stack testing procedures as specified 

in Subpart UUUUU, EPA should add those options directly to Subpart Da. 

Response: The EPA disagrees with the commenters suggestions regarding limits on its ability to 

prescribe compliance determination methods. PM CEMS continue to be installed and operated at 

existing EGUs; moreover, their use has been required and successfully used at EGUs that have emission 

rates at levels near those contained in the standards. Therefore, PM CEMS remain an option to monitor 

emissions of PM. However, the final rule also allows the use of PM CPMS. Owners/operators that 

believe the use of PM CEMS is not the best approach for their EGUs may elect to use a PM CPMS. The 

EPA has concluded that either option provides adequate assurance of compliance with the PM standard. 

As described above, the EPA has concluded that the use of quarterly testing is not appropriate for new 

electric utility steam generating units. 

Comment: Commenter (5794) discussed and objected to the phrase “applicable 30-boiler operating day 

rolling average PM emissions limit” in §60.48Da(f) because no other provision in subpart Da states that 

a 30-operating day rolling average applies to any standard in §60.42Da. The commenter recommends 

that the EPA also remove the reference in this provision to modified units. The commenter noted that 

under this proposal, units modified after May 3, 2011 would be subject to the PM emissions limit in 

§60.42Da(c) or (d) and the compliance procedures in §60.48Da(o) or (p), not the procedure in 

§60.49Da(f). [Proposed §§60.42Da(e)(1)(ii) and 60.48Da(o), 77 Fed. Reg. at 71335-36.] The commenter 
6 

stated that Section §60.48Da(p), which allows use of PM CEMS in lieu of the procedures in 

§60.48Da(o), specifies use of a “24-hour daily (block) average” for those modified units that opt to use 

PM CEMS to demonstrate compliance. [40 CFR §60.48Da(p)(4).] 

To address the above issues, the commenter suggested the following rewording of 60.48Da(f): 

....For affected facilities for which construction, modification, or reconstruction 

commenced after May 3, 2011 that opt under §60.49Da(t) to demonstrate compliance 

using PM CEMS, compliance with the applicable 30-boiler operating day rolling average

PM emissions limit in §60.42Da(e)(1)(i) is determined on a 30-boiler operating day 

rolling average basis by calculating the arithmetic average of all hourly PM emission 

rates for the 30 successive boiler operating days, except for data obtained during periods 

of startup or shutdown. 

Response: The regulatory text has been revised to remove “modification” and move “30 boiler 

operating day rolling average” as suggested by the commenter. However, the paragraph references have 

been left more general to facilitate potential future amendments without having to revise specific 

paragraph references. 

Comment: Commenter (5794) agreed with the proposed removal of the reference to a daily average in 

relation to units constructed, reconstructed, or modified after May 3, 2011 and with the use of a straight 

arithmetic average of the hourly PM emission rates for the 30 successive boiler operating days. The 

commenter stated that this compliance methodology is the same as the one used in Subpart UUUUU 

and, as long as periods of startup and shutdown are excluded from the compliance calculation, it is not 

necessary to sum all of the hourly output values prior to determining a numerical value in order to 

compensate for the lack of output. The commenter agreed that compliance for the new unit filterable PM 

limit should be calculated the same way under both rules. 

Response: No response necessary. 

Comment: Commenter (5794) agreed with the revisions to the introductory text of §60.48Da(o) to add a 

reference to the standard in §60.42Da(e)(1)(ii) and to revise the introductory text of §60.48Da(o)(1), 

(o)(2), (o)(3), (o)(3)(i), and (o)(4) to remove references specific to standards and facilities. The 

commenter assumed the intended effect of the revisions is to make these compliance provisions 

applicable to any facility constructed, reconstructed, or modified after February 28, 2005 that is 

demonstrating compliance with an input-based standard through performance testing rather than PM 

CEMS. If that is EPA’s intent, the commenter expressed agreement with these revisions. 

Response: The intent was to make the provisions more broadly applicable and as such no response is 

necessary. 

3.2 Opacity Monitoring 

Comment: Commenters (5796, 20269, 20279) supported the proposed clarification that EGUs using a 

PM CPMS to monitor PM emissions are exempt from the requirement to install a COMS. 

Commenter (5794) stated that in the Reconsideration proposal, the exemption from the COMS 

requirement for any facility that operates a PM CPMS according to the requirements in Part 63, subpart 
7 

UUUUU is moved from §60.49Da(a)(4) to §60.49Da(a)(2), and as a result, imposes new monitoring on 

these units without any justification. The commenter stated that the change is not a clarification, but a 

significant revision, and the commenter objected to the revision. The commenter stated that if a facility 

is demonstrating continuous compliance with the applicable PM limit using a PM CPMS, there is no 

basis for requiring monitoring of the surrogate opacity standard. The commenter stated that the EPA 

must issue a proposal explaining why such additional monitoring is necessary, and submit a proposed 

information collection request justifying the additional testing under the Paperwork Reduction Act. 

Response: While PM CPMS do not provide a measured emissions rate, the EPA has concluded that the 

continuous direct measurement of a correlated parameter and indication whether the operating parameter 

has been exceeded provides similar assurance as PM CEMS that a facility is continuously operating 

below a specified emissions rate. In previous rulemakings, the EPA determined that the 20% opacity 

standard was unnecessary for subpart Da facilities using PM CEMS to demonstrate compliance with an 

emissions limit of 0.03 lb/MMBtu or lower. At this emissions rate, a facility will emit opacity on the 

lower end of an opacity monitor capability, and increases in PM emissions might only mildly deflect the 

opacity monitor output. However, a PM CPMS is considerably more sensitive than an opacity monitor at 

detecting fluctuations in PM level. Therefore, a small increase in PM emissions at low PM 

concentrations is more easily detected using PM CPMS and has a clear advantage compared to opacity 

monitoring systems. Consequently, the use of PM CPMS together with compliance with the subpart Da 

PM emissions rate of 0.03 lb/MMBtu provides sufficient assurance that the facility is operating with an 

opacity of less than 20 percent. Therefore, the paragraph is not being moved, and facilities using PM 

CPMS are not required to monitor opacity and the rule burden is unchanged. 

 
8 

4.0 TECHNICAL CORRECTIONS 

Comment: Commenter (5794) agreed with the revision of the subpart Da filterable PM standard 

applicable to facilities for which construction, reconstruction, or modification commenced before March 

1, 2005 to 13 ng/J (0.03 lb/MMBtu) heat input. The commenter cited their NSPS Reconsideration 

Petition and NSPS Petitioners’ Brief in support of the revision. The commenter noted that EPA’s 

revision of the standard to include an additional significant digit was unlawful. The commenter saw no 

reason to solicit comment on this change, and stated that the EPA lacks discretion under the CAA to do 

anything other than reinstate the original limit as of April 16, 2012. 

Response: The change was necessitated by an inadvertent error and the language has been finalized as 

proposed. 

Comment: Commenter (5794) agreed with the revision of the regulatory text to specify that the 

requirements in 40 CFR 60.42Da(c) or (d), which includes two additional alternative limits, are 

applicable to facilities modified after February 28, 2005. The commenter stated that the revision is 

consistent with the Agency’s determination of the best demonstrated technology for such modified units 

and with the Agency’s stated intent in the final rule. The commenter stated that to finalize any other 

standard, EPA would have to issue a new proposal justifying the new standard. The commenter cited 

their NSPS Reconsideration Petition and NSPS Petitioners’ Brief in support of the revision. 

Response: The language has been finalized as proposed. 

Comment: Commenter (5794) stated no objections to removal of the phrase “at all times except during 

periods of startup and shutdown” in the introductory text of §60.42Da(e)(1), provided that the EPA 

retains the language in §60.48Da(a). 

Response: The removal of the phrase has been finalized as proposed and the language in §60.48Da(a) is 

unchanged. 

Comment: Commenter (5813) stated that the phrase in §60.42Da(e)(1) is in error and should be 

corrected as follows: 

“...the owner or operator shall not cause to be discharged into the atmosphere from that 

affected facility any gases that contain PM in excess of the applicable emissions limit...” 

Response: Paragraph 60.42Da(e) has been revised to include “not” as suggested by the commenter. In 

addition, “... any gases that contain PM in excess of ...” in paragraphs (e)(1)(i) and (ii) is redundant 

since the phrasing is already contained in paragraph (e)(1) and therefore has been deleted. 

 
9 

5.0 COMMENTS ON TOPICS NOT PROPOSED FOR RECONSIDERATION 

5.1 NOX and SO2 Emission Rates and Compliance 

Comment: Commenter (5813) stated that for new facilities, demonstration of compliance with the NOX

standard as defined in §60.44Da is not consistent with that of the alternative NOX+CO limit defined in 

§60.45Da. The commenter stated that in §60.45Da NOX+CO is determined on a 30-boiler operating day 

rolling average basis, but for NOX, §60.44Da excludes the clarification of a 30-day average basis. The 

commenter discussed IGCC natural gas startup, and how NOX emissions are higher during that time than 

during operation with syngas. The commenter stated that in the absence of the 30 day provision, the 

NOX-only requirement could be interpreted as an absolute and instantaneous limit. The commenter 

suggested that flexibility to average emissions is needed to compensate for intermittent higher NOX

emissions that occur during plant startup for IGCC plants, and that a 30-day rolling average for NOX

compliance be added to §60.44Da to avoid potential misinterpretation and misapplication of the 

standard. 

Response: The EPA has concluded that the current language is sufficiently clear. Paragraph 60.48Da(b) 

in the compliance provisions section specifies that the averaging period is 30 boiler operating days. 

Stating the “30-boiler operating day average” averaging period in the NOX+CO section is redundant and 

could be removed without changing the rule requirements.. 

5.2 Use of a Digital Opacity Compliance System 

Comment: Commenter (5794) referred to the provision promulgated as §60.49Da(a)(3)(iv) but 

incorrectly codified in the electronic CFR as §60.49Da(a)(4)(iv), regarding the option for use of a digital 

opacity monitoring system. The commenter noted that in 2009, the commenter judicially challenged this 

provision and petitioned for administrative reconsideration of it. The commenter stated that because the 

purpose of this republication is simply to correct the codification error and that the Agency is not 

accepting comment in this proceeding on the substance of these provisions, the commenter incorporated 

their prior objections, but did not reiterate their objections in this comment letter. However, the 

commenter requested that the EPA confirm in response to comments that if EPA finalizes this proposed 

error correction, the commenter need not judicially challenge the final rule in order to preserve its 

objections. 

Response: The amendment is only intended to correct the codification error and not as a substantive 

change that the EPA intended to request comment on. 

 
10 

6.0 GENERAL COMMENTS 

Comment: Commenter (5790) stated that the air emission standards should be enforced in adjacent 

countries in order to give industry a level playing field. The commenter stated that the emission limits 

should be tied to viable health standards that can be documented. 

Response: This issue is outside the scope of this rulemaking. It is beyond the legal authority of a Clean 

Air Act section 111 rulemaking to enforce emission standards in other countries. As to the commenter’s 

second comment, under the existing Clean Air Act, section 111 standards are technology-based 

standards, not health-based standards. 

 
11 

7.0 INCORPORATION BY REFERENCE 

Comment: Commenters (5798, 5801, 5805, 5806, 5814) supported the comments of UARG (EPA-HQOAR-2011-0044-5794). 

Comment: Commenter (5794) incorporated by reference the portions of its NSPS petitions for 

reconsideration that address issues covered by the proposed reconsideration rule (EPA-HQ-OAR-2011-

0044-5771).