Standards of Performance for

Fossil-Fuel-Fired Steam Generating Units for Which

Construction Is Commenced After August 17, 1971

(40 CFR 60 subpart D)

Standards of Performance for

Electric Utility Steam Generating Units for Which

Construction Is Commenced After September 18, 1978

(40 CFR 60 subpart Da)

Standards of Performance for

Industrial-Commercial-Institutional Steam Generating Units

(40 CFR 60 subpart Db)

Standards of Performance for Small

Industrial-Commercial-Institutional Steam Generating Units

(40 CFR 60 subpart Dc)

Response to Public Comments on

Rule Amendments Proposed May 3, 2011 (73 FR 33642)

US Environmental Protection Agency

Office of Air Quality Planning and Standards

Sector Policies and Programs Division

Research Triangle Park, NC 27711

December 2011
i

Table of Contents

1. Introduction............................................................................................................................................................... 1

2. Response to Comments on Proposed NSPS Amendments to ................................................................................... 1

Subparts D and Da ........................................................................................................................................................ 1

2.1 General NSPS Rule Development ................................................................................................................... 1

2.1.1 Fuel and Technology Neutral Approach for Rule Development ........................................................... 1

2.1.2 Selection of Best System of Emissions Reduction (BSER)................................................................... 3

2.1.2.1 Consideration of EGU Energy Efficiency in Selection of BSER ...............................................3

2.1.2.2 Consideration of IGCC Technology in Selection of BSER........................................................3

2.1.3 Net Energy Output Based Emissions Standards Format........................................................................ 4

2.1.4 Standards for Reconstructed and Modified EGUs................................................................................. 5

2.1.5 Standards for Combined Heat and Power (CHP) Units Subject to NSPS ............................................. 5

2.1.6 NSPS during Periods of EGU Startup, Shutdown, and Malfunction..................................................... 6

2.1.7 Facility-Wide Emissions Averaging...................................................................................................... 6

2.1.8 Interrelationship of NSPS with other EPA Rulemakings Affecting EGUs ........................................... 7

2.1.8.1 Source Category Impact Analysis ..............................................................................................7

2.1.8.2 Delay of NSPS Rulemaking until NESHAP Affecting EGUs is Finalized ................................7

2.1.8.3 Proposal of EGU NSPS Amendments with EGU NESHAP ......................................................7

2.2 Rule Applicability............................................................................................................................................ 8

2.2.1 Regulation of IGCC facilities under 40 CFR 60 subpart KKKK .......................................................... 8

2.2.2 Exemption of EGUs Using “Innovative Technologies” ........................................................................ 8

2.2.3 Applicability to Permitted EGUs for which Construction Has Not Commenced.................................. 9

2.3 Particulate Matter (PM) Emissions Standards................................................................................................. 9

2.3.1 Selection of BSER for PM Emissions................................................................................................... 9

2.3.2 Regulation of Combined PM Emissions................................................................................................ 9

2.3.3 Regulation of PM2.5 Emissions.............................................................................................................11

2.3.4 Selection of PM Emissions Limit Value ..............................................................................................11

2.3.5 PM Control Cost Analysis....................................................................................................................12

2.3.6 PM Standards Exemptions....................................................................................................................12

2.3.6.1 Opacity Standard Exemption for EGUs Using PM CEMS.......................................................12

2.3.6.2 Opacity Standard Exemption for EGUs Complying with a Combined PM Standard...............12

2.3.6.3 PM and Opacity Standard Exemptions for Natural Gas Fired EGUs.......................................12

2.3.6.4 PM and Opacity Standards Exemption for Low-Sulfur Fuel Fired EGUs................................13

2.4 Sulfur Dioxide (SO2) Emissions Standards ................................................................................................... 13

2.4.1 Selection of BSER for SO2 Emissions..................................................................................................13

2.4.2 Selection of SO2 Emissions Limit Value..............................................................................................14

2.3.3 SO2 Control Cost Analysis...................................................................................................................15
ii

2.4.4 Coal Refuse-Fired EGU Exemption from SO2 Standards ....................................................................15

2.5 Nitrogen Oxides (NOX) Emissions Standards ............................................................................................... 15

2.5.1 Selection of BSER for NOX Emissions ................................................................................................15

2.5.2 Combined NOX + CO Emissions Limit................................................................................................16

2.5.3 NOX Emissions Limit............................................................................................................................17

2.6 Compliance Requirements............................................................................................................................. 18

2.6.1 Opacity Monitoring ..............................................................................................................................18

2.6.2 PM Continuous Emission Monitoring ..................................................................................................18

2.6.3 Electronic Reporting of Performance Test Data...................................................................................19

2.6.4 Monitoring PM and Opacity Emissions from EGUs Using ESPs........................................................21

2.7 Other Proposed Amendments........................................................................................................................ 21

2.7.1 Rule Definitions....................................................................................................................................21

2.7.1.1 Definition of “Affected Facility”..............................................................................................21

2.7.1.2 Definition of “Gaseous Fuel” ...................................................................................................21

2.7.1.3 Definition of “IGCC Electric Utility Steam Generating Unit” .................................................21

2.7.1.4 Definition of “Natural Gas”......................................................................................................22

2.7.1.5 Definition of “Petroleum Coke” ...............................................................................................22

2.7.2 General Duty ........................................................................................................................................23

2.7.3 Affirmative Defense Provisions ...........................................................................................................23

2.7.4 Subpart Da Mercury Provisions............................................................................................................24

2.7.5 Removal of References to 30-Day Rolling Averages...........................................................................24

2.7.6 Deletion of Obsolete Provision References in Rule .............................................................................25

2.7.7 Proposed Rule Language Corrections and Clarifications.....................................................................25

3. Response to Comments on Proposed NSPS Amendments to Subparts Db and Dc ................................................ 26

3.1 Definition of “Distillate Oil” ...................................................................................................................26

3.2 Exemption of Steam Generating Units Subject to Other NSPS...............................................................26

3.3 Applicability to Temporary Boilers.........................................................................................................26

3.4 Site-Specific Monitoring Plan .................................................................................................................27

3.5 Opacity Monitoring .................................................................................................................................27

List of Tables

Table 1. List of Commenters Cited in this Summary Document Submitting Comments to EPA Air and Radiation Docket 

Number EPA-HQ-OAR-2011-0044 Regarding NSPS Rule Amendments Proposed May 3, 2011 (76 FR 24976) ..... 2
iii

Acronyms and Abbreviations

BACT Best Available Control Technology

BSER Best System of Emission Reduction

BLD Bag leak detection

Btu British thermal unit

CAA Clean Air Act

CCS Carbon capture and storage 

CEMS Continuous emissions monitoring system

CFB Circulating fluidized bed

CHP Combined heat and power

CO Carbon monoxide 

COMS Continuous opacity monitoring system

CROMERR Cross-Media Electronic Reporting Regulation

DOE U.S. Department of Energy

EGU Electric steam generating unit

EPA U.S. Environmental Protection Agency

ERT Electronic Reporting Tool

ESP Electrostatic precipitator

FGD Flue gas desulfurization

GHG Greenhouse gas

IGCC Integrated gasification combined cycle

kWh Kilowatt-hour

MW Megawatt

MWC Municipal waste combustor

MWh Megawatt-hour

NAAQS National Ambient Air Quality Standard

NO2 Nitrogen dioxide

NOx Nitrogen oxides

NSPS New Source Performance Standards

NSR New Source Review

OMB Office of Management and Budget

PM Particulate matter

PRA Paperwork Reduction Act

PSD Prevention of Significant Deterioration

SCR Selective catalytic reduction

SNCR Selective non-catalytic reduction

SIP State Implementation Plan

SO2 Sulfur dioxide

SOx Sulfur oxides
Introduction

1

1. Introduction

On February 27, 2006, the United States Environmental Protection (EPA) promulgated amendments (71 FR 9866)

to the new source performance standards (NSPS) for electric utility steam generating units (EGUs) under 40 CFR 

part 60 subparts D and Da. EPA was subsequently sued by the offices of multiple state Attorneys General and 

environmental organizations on these amendments. On September 2, 2009, EPA was granted a voluntary remand 

without vacatur of the 2006 amendments. On May 3, 2011, EPA proposed amendments (76 FR 24976) in 

response to the voluntary remand. These amendments included proposed new emissions limits for particulate 

matter (PM), sulfur dioxide (SO2), and nitrogen oxides (NOX) for EGUs that commence construction, 

reconstruction, or modification on or after May 3, 2011. As part of this action, the Agency also proposed several 

minor amendments, technical clarifications, and corrections to existing provisions applicable to the fossil fuelfired EGUs under 40 CFR 60 subparts D and Da, as well as large and small industrial-commercial-institutional 

steam generating units NSPS under 40 CFR part 60 subparts Db and Dc.

A 90-day period ending August 4, 2011 was provided for the public to submit comments to EPA regarding the 

proposed subparts D, Da. Db, and Dc amendments. Approximately 200,000 comments were entered into EPA’s 

Air and Radiation docket assigned for this NSPS rulemaking (number EPA-HQ-OAR-2011-0044). Many of 

these comments were duplicative of comments submitted to EPA’s Air and Radiation docket assigned for the 

development of the proposed national emission standards for hazardous air pollutant (NESHAP) from coal- and 

oil-fired EGUs under CAA section 112 (number EPA-HQ-OAR-2009-0234). 

EPA reviewed all of the comments entered into docket EPA-HQ-OAR-2011-0044 and grouped the commenters 

into three general categories. The first category is commenters submitting duplicative copies of comments also 

submitted to docket EPA-HQ-OAR-2009-0234 regarding the proposed NESHAP rulemaking, and which do not 

contain any comments specifically related to the proposed NSPS amendments. The second category consists of 

commenters stating only general support or opposition to the NSPS rulemaking. Commenters supporting the 

amendments frequently included statements requesting that EPA establish the most stringent air emissions 

standards possible for EGUs. Commenters opposing the amendments frequently stated that the proposed NSPS 

amendments are overly stringent and burdensome and would inhibit or prevent the construction of new coal-fired 

EGUs, thereby increasing costs for electricity. The third and final category of public commenters are those 

providing comments regarding specific issues and topics related to the rule development and proposed rule 

language for amendments to 40 CFR 60 subparts D, Da, Db, and Dc.

This document presents a summary of the public comments entered into docket EPA-HQ-OAR-2011-0044

regarding specific issues and topics related to the development of the proposed NSPS amendments to 40 CFR 60 

subparts D, Da, Db, and Dc (i.e., comments submitted by commenters in the third category) and EPA’s responses 

to those comments. The comment summaries pertaining to subparts D and Da are grouped by topic in Section 2 of 

this document. Comments pertaining to proposed amendments specific to subparts Db and Dc are included in 

Section 3. Tables 1 and 2 match the commenter to the docket entry number cited in Sections 2 and 3 for specific 

legal or technical comments. Some of the comment sets were signed or submitted on behalf of multiple 

commenters. 
Introduction

2

Table 1. List of Commenters Cited in this Summary Document Submitting Comments to EPA Air and 

Radiation Docket Number EPA-HQ-OAR-2011-0044 Regarding NSPS Rule Amendments 

Proposed May 3, 2011 (76 FR 24976)

EPA-HQ-OAR-2011-0044

Document No. Date Submitted Name and Affiliation

4634 August 4, 2011 James S. Pew

Earthjustice

4635 August 4, 2011 Thomas C. Perry

National Mining Association

4656 August 4, 2011 William D. Bissett

Kentucky Coal Association

4673 August 4, 2011 Reid T. Clemmer

PPL Services Corporation

4674 August 4, 2011 Martha E. Rudolph

State of Colorado

Colorado Department of Public Health and Environment

4686 August 4, 2011 John T. Heard

The Virginia Coal Association

4698 August 2, 2011 Ronald A. Amirikian

State of Delaware

Department of Natural Resources & Environmental Control

4712 August 4, 2011 John M. McManus

American Electric Power

4713 August 4, 2011 William O’Sullivan

State of New Jersey

Division of Environmental Protection

4714 August 4, 2011 Mark R. Vickery

State of Texas

Texas Commission on Environmental Quality

4715 August 4, 2011 Erika Padgett

Elizabeth Wheeler

Clean Wisconsin

Kim Wright

Midwest Environmental Advocates

Peter Bakken

Wisconsin Interfaith Power and Light

George Meyer

Wisconsin Wildlife Federation

4760 August 3, 2011 Jolene M. Thompson

American Municipal Power, Inc.

4765 August 4, 2011 Alex Hofmann

Theresa Pugh

American Public Power Association

4766 August 4, 2011 Chris M. Hobson

Southern Company

4768 August 3, 2011 James A. Landreth

SCE&G

4770 August 3, 2011 Desi M. Chari 

The Dow Chemical Company

4830 August 4, 2011 Rae E. Cronmiller 

National Rural Electric Cooperative Association 
Introduction

3

EPA-HQ-OAR-2011-0044

Document No. Date Submitted Name and Affiliation

4832 August 4, 2011 Kathleen L. Barrón

Exelon Corporation

4833 August 4, 2011 JoAnne Rau

Randal Griffin

Dayton Power and Light Company

4834 August 4, 2011 Jay Hudson

Santee Cooper

4836 August 4, 2011 F. William Brownell

Craig S. Harrison

Lauren Freeman

Hunton & Williams LLP

Counsel to the Utility Air Regulatory Group (UARG)

4839 August 4, 2011 Verne Shortell

NRG Energy, Inc.

4841 August 4, 2011 Robert D. Bessette

Council of Industrial Boiler Owners

4893 August 4, 2011 Tom Thompson,

Eco Power Solutions (USA) Corp

4926 August 4, 2011 Lisa Jacobson

The Business Council for Sustainable Energy

4984 August 4, 2011 Brian H. Moeck

The Large Public Power Council

4985 August 4, 2011 Raymond L. Evans

FirstEnergy Corporation

4989 August 4, 2011 John M. McManus

American Electric Power

4997 August 4, 2011 Les Oakes

Cynthia AM Stroman

King & Spalding LLP

Counsel to The IPP Coalition

5000 August 4, 2011 John L. Stowell

Duke Energy

5074 August 4, 2011 David Gardiner

Alliance for Industrial Efficiency

5075 August 4, 2011 Caroline Choi

Progress Energy

5077 August 4, 2011 John W. Myers

Tennessee Valley Authority

5087 August 4, 2011 Raymond L. Evans

FirstEnergy

5089 August 4, 2011 Thomas C. Perry

National Miming Association

5208 August 3, 2011 G. Vinson Hellwig

State of Michigan

Department of Environmental Quality

5195 August 4, 2011 Kerry Kelly

Waste Management
Introduction

4

EPA-HQ-OAR-2011-0044

Document No. Date Submitted Name and Affiliation

5210 August 4, 2011 Susanne Brooks

Elena Craft

Mark MacLeod

Hilary Sinnamon

Mandy Warner

Peter Zalzal

Environmental Defense Fund

5240 August 4, 2011 Michael J. Nash

Gulf Coast Lignite Coalition

5279 August 3, 2011 Eric Redman

Summit Texas Clean Energy, LLC

5470 August 3, 2011 Mark J. Sadlacek

Los Angeles Department of Water and Power

5477 August 15, 2011 Williw R. Taylor

U.S. Department of the Interior

5715 August 4, 2011 Ann Brewster Weeks

Clean Air Task Force

Sanjay Narayan

Sierra Club

James S. Pew

Earthjustice

John Walke

Natural Resources Defense Council

Janice E. Nolen

American Lung Association

John Suttles

Southern Environmental Law Center

Joseph Mendelson III

National Wildlife Federation

Justin Bloom

Scott Edwards

Waterkeeper Alliance

5749 July 20, 2011 Myra C. Reece

State of South Carolina

Bureau of Air Quality, South Carolina Department of Health 

and Environmental Control

17620 in 

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 S. William Becker

National Association of Clean Air Agencies

17622 in 

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 David Foerter

Institute of Clean Air Companies

17711 in

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 Paul Noe and Robert Glowinski

American Forest & Paper Association (AF&PA) and

American Wood Council (AWC)

17755 in

Docket No. EPA–HQ–

OAR–2009–0234

August 3, 2011 Eddie Terrill

State of Oklahoma

Oklahoma Department of Environmental Quality

17852 in

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 Gregory C. Staple

American Clean Skies Foundation (ACSF)
Introduction

5

EPA-HQ-OAR-2011-0044

Document No. Date Submitted Name and Affiliation

17878 in

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 Ben Yamagata

Coal Utilization Research Council

17929 in

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 James S. Pew

Earthjustice

17975 in

Docket No. EPA–HQ–

OAR–2009–0234

August 4, 2011 Environmental Integrity Project

Eric Schaeffer
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

1

2. Response to Comments on Proposed NSPS Amendments to

Subparts D and Da

2.1 General NSPS Rule Development

2.1.1 Fuel and Technology Neutral Approach for Rule Development

Comment: One commenter (4698) stated support for EPA decision to adopt a fuel and technology neutral 

approach to developing the NSPS for new EGUs because it potentially facilitates the selection of a cleaner fuel as 

part of the overall integrated emissions compliance strategy, and provides flexibility in the design, construction, 

and operation of the unit in a configuration optimized for a given EGU. One commenter (5210) stated that “fuel 

neutral” standards should be based on the cleanest burning fuels instead of EGUs that burn pulverized coal, which 

EPA has used as the basis for the proposed emissions limits. According to the commenter, this approach violates 

the intent of Congress under Clean Air Act (CAA) section 111 that NSPS for new sources be forward looking and 

technology forcing. Many commenters (4766, 4830, 4834, 4948, 5077, 17878) oppose using a fuel and 

technology neutral approach to developing NSPS for EGUs, and instead recommend developing standards 

based on technology that account for the type of fuel burned. One commenter (4766) stated that EPA has no 

basis for developing “fuel neutral” standards in which all coal-, gas-, and oil-fired EGUs are subject to 

identical NSPS emissions limits. This approach unlawfully fails to consider the differences among boilers 

using different fuel types. Congress gave EPA the authority to “distinguish among classes, types, and sizes”

when establishing standards; EPA, therefore, has an obligation to explain how it is applying the CAA Section 

111 criteria to each fuel type, and to explain the national policy implications of its choices. A third 

commenter (4830) stated that it is bad public policy for NSPS to effectively eliminate whole categories of 

generation types, pollution control devices, and fuels. Diversities in generation design are critical to 

optimizing a facility for its specific and intended use. For example, fluidized bed combustion (FBC) is an 

ideal technological choice for intermediate-sized generation, and can utilize a broad array of fuels, from 

biomass to coal of different ranks. On the other hand, pulverized coal (PC) units have generally less fuel 

flexibility but are better suited for larger generation uses and can be designed to have superior thermal 

efficiency. An NSPS that effectively precludes coal, a particular coal rank, or combustion design is in effect 

tailoring the nation’s future options for electric generation. CAA Section 111 statutory provisions are 

directed at disseminating best system of emission reduction (BSER) throughout an identified source category 

and not for the purposes of significantly narrowing the nation’s choices for types of steam electric generation 

and fuel to power it.

Response: The vast majority of subpart Da affected facilities burn coal as the primary fuel. It is within EPA’s 

authority under the CAA to establish fuel and technology neutral standards. (See, for example, Lignite Energy 

Council v. EPA) It is also within EPA’s authority to subcategorize standards based on fuel and boiler type.

Whichever approach EPA chooses, it is appropriate for it to establish standards for EGUs that allow the use of 

inherently cleaner burning fuels to comply with the standards. The amended NOX and PM standards for EGUs are 

largely fuel neutral, since the achievable emissions rate for the best system of emission reduction (BSER) is 

similar across boiler and fuel types. While the amended SO2 standard does not establish separate standards based 

on coal rank, it does account for the impact of fuels with inherently high sulfur concentrations on the performance 

of the BSER technology by providing an alternate percent reduction standard. EPA has concluded that the 

amended standards allow affected EGUs the flexibility to use the boiler design and fuel types that best meet the 

site-specific needs of the EGU owner and operator. All of the amended standards have been achieved by primary 

boiler types (pulverized coal and fluidized beds) and across all coal ranks. Under the adopted fuel neutral 

approach, owners/operators of affected EGUs have the flexibility to build new units designed to use a cleaner 

burning fuel as an alternative to installing post-combustion emission control technology or to co-fire cleaner 

burning fuels with coal and install slightly less-efficient post combustion control technology. 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

2

Neither natural gas nor distillate oil is typically used in new baseload steam generating units (e.g., boilers). Basing 

the standards on either of these fuels would result in standards that are not economically achievable for a coalfired EGU. EPA has concluded that it is appropriate to continue to allow the construction of properly controlled 

coal-fired baseload EGU since, as a general matter, it is not economically feasible to burn either natural gas or 

distillate oil in a baseload boiler/steam turbine EGU. Basing the standards on what is achievable by BSER

employed on a coal-fired unit accomplishes this. EPA has concluded that the use of natural gas and distillate oil 

will still play a significant role in the future generation of electricity. Rather than burning natural gas or distillate 

oil in a boiler based EGU, however, any new baseload electric generation based on the use of either of these fuels 

would likely use combined cycle combustion turbines. Combustion turbines burning natural gas and distillate oil 

generate power more efficiently and economically than a boiler burning natural gas or distillate oil. The efficiency 

and capital cost benefits of combined cycle facilities outweigh the fact that natural gas and distillate oil are 

significantly more expensive per unit heat input than coal. 

Comment: Several commenters (4836, 4997) stated that IGCC technology is inherently different from other coalbased electric generation technologies and should be regulated separately. The NSPS applicable to IGCC EGUs 

should address the unique characteristics of IGCC technology. Factors that should be examined to properly 

consider the design and operational characteristics of IGCC technology include: 1) operating scenarios in which 

the IGCC EGUs (combustion turbines and duct burner) are combusting different fuels or a combination of fuels,

such as natural gas, coal or other carbonaceous compound (petroleum coke, biomass, municipal solid waste, etc.),

derived syngas, and/or syngas produced off-site; 2) the applicability of any work practice and fuel sampling 

provisions as they relate to the design and operation of IGCC EGUs; and 3) the use of heat input and generation 

output terminology specific to IGCC EGUs.

Response: EPA has concluded that the language is sufficiently clear that the output from an IGCC facility is the 

combination of the output from the combustion turbine, steam turbine, and any useful thermal output. The heat 

input to an IGCC facility is the combined heat input to the combustion turbine engine and any fuel input to the 

duct burners in the heat recovery steam generator. For an IGCC facility that does not coproduce hydrogen or 

carbon containing chemicals, this value should be close to the energy content of the raw coal input to the 

gasification system (greater than 95%). The gasification/purification system should be designed to provide a 

uniform syngas regardless of the feedstock so it is unclear how the feedstck would impact emissions. The 

commenter did not provide data indicating that the use of natural gas during periods when the gasification system 

is not providing syngas would create compliance problems. On the contrary, combined cycle facilities would only 

need to maintain a NOX emissions rate of 25 ppm to comply with the amended NOX standard. This emissions rate 

is routinely achieved by both combustion turbines using dry low NOX combustion controls and natural gas-fired 

diffusion flame combustion turbines using water or steam injection. The combustion of natural gas also results in 

minimal SO2 and PM. Post combustion controls would not even be required to maintain compliance with the 

emission standards. 

Comment: One commenter (5210) stated that high thermal efficiency should be used to establish standards, 

instead of being considered a control technology. In EPA’s current proposed amendments to the NSPS, there is no 

discussion of thermal efficiency or what efficiency rate was used by the Agency to determine the new standards. 

The commenter requests that EPA explain in the final rule what thermal efficiency assumptions were used in 

determining the new NSPS, and whether they are different from the assumptions used in the last amendments. 

The commenter also recommends that EPA use the greatest feasible thermal efficiency for EGUs as an input to 

determine the NSPS.

Response: The facilities used to establish the output-based standards included some of the most thermal efficient 

facilities. Therefore, the emission standards account for both high thermal efficiency and the efficiency of the 

emissions control equipment. This is the preferred approach when sufficient data is available, and simultaneously 

accounts for both the thermal efficiency and control equipment efficiency under various operating conditions. We 

consequently concluded it is not necessary to measure emissions on a heat input basis and then use an assumed 

efficiency to convert to an output-based standard, but rather directly established output-based standards based on 

the performance of the best performing facilities.
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

3

Comment: One commenter (5240) stated that separate NSPS must be established for the subcategory of EGUs 

burning coal with a heat input of less than 8,300 Btu/lb as was the case in EPA’s proposed NESHAP standards. 

According to the commenter, emissions of air pollutants, especially PM and SO2, are significantly different when 

burning these types of coal and must be reflected in any applicable NSPS.

Response: The commenter provided no data indicating a subcategory for low Btu fuel such as lignite would be 

appropriate based on emissions data, or that SO2 and PM controls would not work as effectively with other types 

of coal. Fabrics filters, the selected BSER for control of PM emissions, are designed to control emissions to a 

specified outlet concentration and are relatively independent of the PM concentration coming into the baghouse. 

The SO2 standard has an alternate percent reduction requirement that specifically accounts for the use of high 

sulfur fuels. In addition, various coal cleaning, upgrading, and drying technologies for low rank coals reduce the 

ash, sulfur, and moisture content of these coals resulting in a fuel with characteristics similar to that of higher rank 

coals. Finally, owners/operators have a choice on what fuel to burn and could co-fire cleaner fuels as a 

compliance option.

The following are several examples of existing facilities and their emissions data (which demonstrate that the 

current standards are achievable for low rank coals):

1. The Sandow 5B facility is a subcritical lignite-fired fluidized bed EGU and is presently operating 

below the amended SO2 % reduction alternative. Furthermore, both Sandow 5A and 5B are operating below the 

amended PM standard of 0.090 lb/MWh. 

2. The Oak Grove 1 and 2 facilities are supercritical lignite-fired pulverized coal EGUS. Both are 

presently operating below the amended numerical SO2 standard, and the Oak Grove 2 facility is also operating 

below the amended SO2 % reduction requirement. 

3. The Milton R. Young B1 and B2 facilities are subcritical lignite-fired cyclone boiler EGUs. Both are 

operating below the amended PM standard of 0.090 lb/MWh.

2.1.2 Selection of Best System of Emission Reduction (BSER)

2.1.2.1 Consideration of EGU Energy Efficiency in Selection of BSER

Comment: One commenter (4634) stated that EPA’s failure to set NSPS emissions limits for PM, SO2, and NOX

reflecting the use of energy-efficient design is unlawful and arbitrary. New coal-fired EGUs can significantly 

reduce emissions of all pollution emitted by incorporating energy-efficient design (e.g., use of supercritical 

boilers), allowing them to produce more electricity from burning a given amount of coal. To satisfy the directives 

of CAA section 111, EPA must assume a higher efficiency in combination with emissions controls to impose 

more stringent emissions limits for PM, SO2 and NOX. Another commenter (17929) questions EPA basing the 

proposed output-based emissions limits on gross electrical generating efficiency of 36 percent, which is not BSER

as required by the CAA. The commenter states that 25 percent of existing EGUs achieve this generating 

efficiency, or higher and new EGUs can achieve net efficiencies as high as 45 percent.

Response: Efficiency has already been accounted for since the facilities used to establish the amended standards 

include some of the highest efficiency supercritical facilities. 

The comment from commenter 17929 is unclear and appears to refer to the approach taken in previous 

amendments to subpart Da. The analysis in this rulemaking did not assume any gross efficiency.

2.1.2.2 Consideration of IGCC Technology in Selection of BSER

Comment: One commenter (5715) stated that integrated gasification combined cycle (IGCC) technology is a 

demonstrated system of emissions control for EGUs and EPA should consider it in determining BSER to control 

PM, SO2 and NOX emissions from coal-fired EGUs. Another commenter (4997) stated that integrated gasification 

IGCC technology is a power generation technology and should not be identified as EGU emissions control.

Response: As stated in the preamble, the benefits resulting from reduced emissions of criteria pollutants are not 

sufficient in all instances to justify the higher capital costs of today's IGCC units.
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

4

2.1.3 Net Energy Output Based Emissions Standards Format

Comment: Comments were received in support of and in opposition to EPA’s proposal to require affected EGUs 

to meet the proposed NSPS for PM, SO2, and NOX using an emissions standards format that expresses limits as

the allowable amount of pollutant emitted per net energy output by the affected EGU. Several commenters (5715, 

5074, 5210) supporting the proposal stated that use of this format will encourage improvements in overall EGU 

facility energy efficiency, which results in lower air pollutant emissions and is an incentive to minimize parasitic 

energy demands from pollution control equipment (auxiliary energy demands is synonymous with parasitic 

energy demands). Many other commenters (4673, 4698, 4712, 4765, 4830, 4836, 4989, 4997, 5000, 5077, 5089, 

5208, 17878) oppose the mandatory use of this format, stating that the NSPS should be based on limits on the 

allowable amount of air pollutant emitted per gross energy output by the affected EGU or on allowable amounts 

of air pollutants emitted per energy input to the affected EGU. Reasons cited by the commenters for their 

opposition to requiring mandatory compliance with net energy output based emissions standards include: 1) a 

significant amount of the parasitic power demands at coal-fired power plants is needed to operate the air pollution 

control equipment required to comply with air emissions standards; 2) there are monitoring difficulties in 

measuring net output, especially at facilities operating multiple EGUs; 3) parasitic loads vary on a individual 

EGU-by-EGU basis and, for a given EGU, on a duty cycle basis (e.g. as the load decreases on a typical EGU, the 

percent of parasitic power increases: 4) EGUs are not as thermally efficient at lower loads and consequently the 

amount of fuel that must be used increases on an electrical output basis; 5) at facilities with affected EGUs and 

also at older, less efficient EGUs which supply power to various auxiliaries throughout the plant, requiring the 

proposed net output-based NSPS on the affected EGU could actually decrease overall plant efficiency; and 6) a 

net output approach will be problematic with emerging technologies such as IGCC and certain greenhouse 

reduction technologies such as carbon capture and sequestration (CCS).

Response: The final rule allows, but does not require, the use of a net-output based standard as an alternative to 

the gross-output based standard. However, the use of a gross output-based standard as it is presently defined could 

potentially drive the installation of electrically driven boiler feed pumps instead of steam driven boiler feed 

pumps. From an overall net efficiency basis, it is often more efficient to use steam driven boiler feed pumps, 

although a facility that uses electrically driven pumps would appear more efficient when using the present 

definition of gross output. Electrically driven boiler feed pumps could account for as much as 3% of the gross 

electric output of a coal-fired EGU, substantially increasing the parasitic power requirements. Therefore, we are 

amending the definition of gross output for new facilities to be the gross output from the generator(s) minus any 

electric power requirements to drive the boiler feed pumps. Since boiler feeds pumps are specific to individual 

boilers, the monitoring issues mentioned by the commenters are no longer applicable. In addition, the majority of 

larger EGUs use steam driven boiler feed pumps and would not be impacted by the amendment.

Furthermore, the primary parasitic power requirements for an IGCC facility that account for the primary 

differences between the net and gross efficiency with a PC boiler are the gas compressors (air separation unit 

main compressor, oxygen compressor, and nitrogen compressor). Correspondingly, the gross parasitic power 

requirements for an IGCC facility would also subtract out the electric power required to run these compressors. 

For facilities that coproduce chemicals, only a portion of the power would be subtracted from the gross output. 

Comment: Several commenters (4698, 4766, 4768, 5000) disagree with EPA’s proposal to calculate the net 

energy output for an EGU from the EGU’s gross energy output, assuming a 5% parasitic electric load loss factor.

Actual parasitic load can vary across EGUs depending on site-specific factors such as geographic location, EGU 

operating mode, and equipment selection. All of these factors affect a facility’s overall auxiliary power load and 

hence its net energy output. Therefore, a uniform 5% assumption is inappropriate. One commenter (4698) 

recommends that EPA solicit input from EGU architect and engineering companies to develop auxiliary load 

estimates for a range of EGU sizes and configurations. Another commenter (4768) states that a 10% parasitic 

electric load loss factor would be a more representative value. One commenter’s (5000) experience is that 

approximately 7 to 8% of a conventional coal fired station’s power is required to run auxiliary equipment. The 

commenter believes that this is a more representative value across the industry considering that units generally 

will be operating with SCR, FGD, and PM emissions controls, all of which require auxiliary power. Also, if a 

CCS is used in the future, the amount of auxiliary power will dramatically increase. 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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Response: According to the National Energy Technology Laboratory in the document “Cost and Performance 

Baseline for Fossil Energy Plants,” parasitic power requirements for pulverized coal-fired boilers using 

supercritical steam conditions varies from 5.2% for high rank coals to 5.9% for low rank coals. These estimates 

are best an detailed designs and are the best estimates available to EPA. However, in recognition that parasitic 

power requirements can increase in terms of percentage of load at lower loads the final rule uses a 7.5% parasitic 

load assumption. 

Comment: One commenter (5210) states that output-based standards are only truly effective when determined by 

using output based data. The commenter requests that EPA not use input based data to set the NSPS standards and 

then simply convert those standards to output based numbers. Instead, the commenter recommends that EPA

finalize output-based standards, based on output data, for all pollutants, regardless of whether compliance is based 

on performance tests or continuous emissions monitoring systems (CEMS).

Response: Output-based emissions data was used to establish the amended emissions standards. 

2.1.4 Standards for Reconstructed and Modified EGUs

Comment: One commenter (5715) states that EPA’s proposal to allow modified and reconstructed EGUs to meet

less stringent NSPS emission limits than those required for new EGUs is not authorized by the CAA, and is 

therefore unlawful. The proposed NSPS for reconstructed and modified EGUs contradict Congressional intent 

that as existing sources are upgraded, they control their emissions to a rate reflecting best system of emission 

reduction for the industry. The commenter cites specific CAA sections and past court decisions to support this 

comment.

Response: Standards under section 111 of the Clean Air Act must be achievable. See, National Lime Association

v. EPA, 627 Fed. 2d 416 (D.C. Cir. 1980). Certain existing facility designs are not capable of operating 

combustion controls as effectively as newly designed facilities and, therefore, cannot achieve the same level of 

emissions reductions as newly designed facilities through the use of combustion controls. Further, even using the 

most efficient post combustion controls these facilities are not able to achieve the same NOX emissions rate as a 

newly designed facility. In determining what is achievable, EPA must consider costs and for modified facilities, 

the incremental cost effectiveness of adding a second scrubber to reduce SO2 emissions beyond what is 

achievable by currently installed technology is not cost effective. The new source PM standard is based on the use 

of a fabric filter. Existing facilities potentially don’t have adequate space available to cost effectively retrofit an 

existing ESP with a fabric filter.

2.1.5 Standards for Combined Heat and Power (CHP) Units Subject to NSPS

Comment: One commenter (5074) states that the net output-based standards in the NSPS should be modified in 

the final rule to account for both the thermal and electric generation from combined heat and power (CHP) and 

waste heat recovery systems subject to the NSPS. Absent this, the net output-based standards fail to account for 

(and incentivize) the full efficiency gains associated with such systems.

Response: Based upon comparison of the criteria pollutant emissions that would result from generating the 

thermal and electric output in separate facilities, EPA increased the thermal credit from 50% to 75% in 2006 (71 

FR 9866). The definition is as follows:

Gross output means the gross useful work performed by the steam generated and, for an IGCC electric utility 

steam generating unit, the work performed by the stationary combustion turbines. For a unit generating only 

electricity, the gross useful work performed is the gross electrical output from the unit's turbine/generator sets. For 

a cogeneration unit, the gross useful work performed is the gross electrical or mechanical output plus 75 percent 

of the useful thermal output measured relative to ISO conditions that is not used to generate additional 

electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an 

industrial process).

Comment: EPA requested comment on, “whether it is appropriate to recognize the environmental benefit of 

electricity generated by CHP units by accounting for the benefit of on-site generation, which avoids losses from 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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the transmission and distribution of the electricity.” One commenter (5074) states that these avoided losses should 

be recognized because such savings are one of the key benefits of distributed generation. Several commenters

(4926, 5074) state that that for CHP units subject to the NSPS, a 5% benefit for avoided transmission and 

distribution losses is too low. EPA should adopt a higher multiplier that fully credits the transmission and 

distribution savings of CHP and therefore incentivizes such investments. 

Response: EPA acknowledges that overall transmission and line losses are closer to 10%. However, the CHP 

facilities typically covered by subpart Da are large facilities with relatively large amounts of the generated 

electricity being transmitted to other end users, and the benefits are reduced. Therefore, the 5% credit is 

reasonable and adequately recognizes the environmental benefit of CHP compared to separate electric and thermal 

generation.

2.1.6 NSPS during Periods of EGU Startup, Shutdown, and Malfunction

Comment: Comments were received in support of and in opposition to EPA’ s proposal that NSPS emission 

limits apply at all times, including start up, shut down and malfunction (SSM). Commenters (4698, 5210) support 

the proposal for a number of reasons. The commenters state that startup and shutdown periods are normal phases 

of EGU operation and should not be held separate from other normal operating activities. Reasons stated by 

commenters (4832, 4834, 4839, 4841, 4984, 5077, 5470) opposing the proposal were varied. One commenter 

(4714) states that the DC Circuit Court decision regarding emission limits during SSM periods (Sierra Club vs. 

EPA, DC Circuit Court, 2008) was specifically regarding NESHAP rules and not NSPS rules. EPA has not 

provided any reasoned explanation or justification for why it is applying the same approach for new, modified, 

and reconstructed sources in the proposed NSPS rule revisions. Furthermore, EPA has not appropriately evaluated 

applying the same emission limits for normal operations and for SSM periods. Another commenter (4836) states

that coal-fired EGUs co-fire other fuels (typically natural gas or oil) during certain operating modes, such as 

startup, shutdown, and flame stabilization operations. The proposed NSPS do not address the potential emissions 

from these co-fired fuels, which will have different emissions profiles from the times the EGU burns coal only. 

One commenter (4834) states that instead of emission limits, work practices should be proposed for the NSPS to 

control emissions during SSM periods. Another commenter (4839) states that provisions for SSM periods should 

follow precedent in the Industrial Boiler MACT Rule. Many of the commenters opposing the proposal state that 

work practices should be used to control emissions from EGUs during startup and shutdown. For malfunctions, a 

source should have to address the malfunction as soon as safely practicable. One commenter (17975) states that 

since maintenance activities are generally carried out for EGU boilers after they have been turned off, the 

distinction between “maintenance” and “startup/shutdown” is meaningless.

Response: The NOX and SO2 CEMS data used to establish the standards include all periods of operation and it is 

therefore not necessary to attempt to separate the data and establish separate numerical standards during normal 

operation and periods of startup and shutdown. However, since we did not have CEMS data for PM emissions, we 

are establishing work practice standards for control of PM emissions during periods of startup and shutdown. 

2.1.7 Facility-Wide Emissions Averaging

Comment: One commenter (4839) stated that facility-wide emissions averaging should be allowed as a 

compliance alternative in certain circumstances. EPA should reconsider and support including facility-wide 

averaging in emission limitations for existing sources subject to the NSPS as an additional compliance alternative. 

By including this type of flexibility mechanism, EPA will ensure that facilities will retain some degree of 

flexibility when complying with the rule requirements. Similarly, varying operational modes or combination of 

systems (e.g., wet/dry scrubber, ESP or fabric filter) could be employed to provide the greatest potential for 

economically reducing emissions to meet compliance requirements. EPA’s averaging formula should be 

constructed so that the average emissions by a group of EGUs subject to the NSPS will be no more than what is 

permitted on an aggregated individual basis. From a practical standpoint, the ability to monitor units with shared 

stacks may present technical difficulties to the point where separate monitoring is simply not feasible.

Response: While the suggested approach would provide additional flexibility without an increase in emissions to 

the atmosphere, the present applicability of the NSPS is on a boiler by boiler basis and no change to that approach 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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was proposed. Facility-wide averaging would require a notice and comment rulemaking to at a minimum clearly 

identify the affected facility, how the averaging would be done, and how modifications and reconstructions would 

be determined. 

2.1.8 Interrelationship of NSPS with other EPA Rulemakings Affecting EGUs

2.1.8.1 Source Category Impact Analysis

Comment: One commenter (4760) states that EPA needs to analyze the combined impacts of all regulatory 

proposals to the electric industry. Decisions by U.S. electric utilities to add needed electricity generating capacity 

are being impacted by the breadth and complexity of the numerous rules-- including the NSPS amendments that 

EPA is implementing to regulate EGU.

Response: The amendments to the NSPS would have a negligible incremental impact on the cost of new coalfired generation. Annual costs, compared to the existing NSPS requirements, will increase less than 0.3%. In 

addition, the various regulatory actions impacting air emissions from EGUs require similar controls such that the 

actual impacts of the NSPS amendments would be even less.

Comment: One commenter (4832) states that EPA proposing substantive changes to 40 CFR 60 subpart Da is 

outside the scope of the proposed NESHAP rulemaking and the changes have not been properly analyzed or 

justified. Specifically, EPA is proposing to demonstrate compliance with certain HAP emissions limits under the 

NESHAP by proxy methods that refer back to SO2 or PM limits established in 40 CFR 60 subpart Da.

Response: While the proposed SO2 and PM NSPS amendments are not expected to have any benefits or costs due 

to the similar benefits and costs in the new source EGU NESHAP requirements, they would be cost effectively 

achievable in the absence of the NESHAP. Docket entry EPA-HQ-OAR-2011-0044-0002 includes detailed 

incremental cost effectiveness calculations for each pollutant and EPA has concluded the amended standards are 

justified in the absence of the NESHAP. If cost and benefits of the proposed amendments were included, it would 

double count the impacts of the rules.

2.1.8.2 Delay of NSPS Rulemaking until NESHAP Affecting EGUs is Finalized

Comment: One commenter (4839) states that the substantial technical comments submitted for the EGU 

NESHAP warrants a delay of the proposed NSPS to allow EPA sufficient time to consider the more 

comprehensive affect these revised rules will have on the utility sector. In addition, there are some commonalities 

in the controls needed to comply with the requirements of the two rules. Syncing the two rules such that they 

apply to the same set of new sources will allow owners/operators of those sources to better plan for compliance. 

Finally, since EPA is not under any judicial timeline to promulgate the proposed NSPS, the commenter 

recommends a delay to account for the considerable time EPA will need to revise the EGU NESHAP and respond 

to any potential judicial challenges.

Response: While the EGU NSPS amendments and NESHAP were included in the same package and are related 

in the types of required controls, they are independent rulemakings that both serve the purpose of reducing 

emissions of pollutants. EPA has sufficiently replied to comments submitted on both proposals.

2.1.8.3 Proposal of EGU NSPS Amendments with EGU NESHAP

Comment: Several commenters (4839, 5087) state that the inclusion of a proposed NSPS rule within the 

extensive and comprehensive proposed EGU NESHAP is inappropriate and circumvents the appropriate comment 

period that should be afforded each rule individually. The release of NSPS and EGU NESHAP in the same 

proposal notice with one 60-day comment period suggests that EPA is rushing its regulatory agenda and shortcircuiting the regulatory process. Since EPA is not under a court ordered deadline to develop NSPS amendments, 

each of these rulemakings should have been proposed separately with their own comment period.

Response: The proposed 60 day comment period was extended an additional 30 days to provide sufficient time 

for the public to review and comment on both proposals.
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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2.2 Rule Applicability

2.2.1 Regulation of IGCC facilities under 40 CFR 60 subpart KKKK

Comment: EPA requested comment on whether or not an IGCC EGU that co-produces hydrocarbons or 

hydrogen should be subject to the combustion turbine NSPS under 40 CFR 60 subpart KKKK instead of the EGU 

NSPS under 40 CFR 60 subpart Da. Several commenters (4836, 5715) state that an IGCC EGU that coproduces 

hydrocarbons or hydrogen should be subject to subpart Da. One commenter (4836) states that IGCC EGUs are 

designed and structured differently than natural gas-fired combined cycle EGUs. For the sake of clarity and 

regulatory certainty, there should not be a mechanism that would require a particular EGU to switch back and 

forth between different NSPS standards, even if an IGCC is capable of using natural gas as a fuel. Such units that 

may co-produce hydrocarbons or hydrogen still convert coal or oil into electricity, and apportioning the parasitic 

load would be difficult. The commenter requests that EPA provide a heat input-based alternative based on the raw 

feed stock to the gasifier for these units instead of struggling to make them demonstrate compliance with an 

output-based standard. Another commenter (5715) states that not applying subpart Da to certain IGCC EGUs that 

co-produce hydrocarbons or hydrogen is not logical. All IGCC facilities that sell more than one third their 

potential electric output capacity and more than 25 megawatts of electricity (MWe) to the grid are and should be 

classified as an EGU subject to 40 CFR 60 subpart Da whether the EGU produces other useful byproducts or not, 

consistent with the applicability of EGUs to 40 CFR 60 subpart Da that are classified as combined heat and power 

units.

Response: The IGCC facilities that meet the existing applicability criteria will continue to be regulated under 

subpart Da. EPA concluded that a gross output based standard, including the revised definition of gross output, is 

appropriate and can be relatively easily measured for all affected facilities, including IGCC facilities. A heat input 

based standard would require an IGCC facility owner/operator to measure the coal input to the gasification system 

and assume all of the energy is input to the stationary combustion turbine and heat recovery steam generator, and 

calculate a site specific f-factor along with a stack flow meter and CO2 CEMS or a fuel flow meter. EPA has 

concluded that the additional complexity associated with such an approach would not yield improved result 

compared to an output-based standard.

2.2.2 Exemption of EGUs Using “Innovative Technologies”

Comment: One commenter (5715) states that EPA is not authorized under the CAA to allow the proposed 

exemption of certain EGUs using “innovative technologies” from complying with the NSPS emissions standards. 

The CAA only allows EPA to grant a compliance time extension for such affected EGUs on a case-by-case basis 

that meet certain conditions specified in the statute. Several commenters (4839, 4893, 4984) support the proposed 

exemption. One commenter (4839) requests that to avoid precluding the development of new technologies, EPA 

should consider a broader applicability of the exemption to include all DOE-funded commercial-scale technology 

demonstration projects.

Response: As explained in the preamble, the compliance time extensions under section 111(j) of the Act are not 

adequate for owners/operators of affected facilities subject to this subpart to secure the funding necessary for 

construction of certain capital intensive projects. As such, the development of promising technologies that offer 

potential reductions in criteria, hazardous, and GHG emissions could be restricted. The permits will be granted on 

a case-by-case basis and depend on the anticipated emissions performance of the specific technology.

To preclude development of emerging technologies that offer potential for future emissions reductions, the 

commercial demonstration permit exemption will be maintained as proposed for pressurized fluidized beds and 

multi-pollutant control technologies. Neither of these technologies is generally applicable to existing facilities, 

and overly stringent standards could impede their future development and make financing projects cost 

prohibitive. The majority of existing facilities already have some form of emissions control technology. Installing 

a multi-pollutant control technology is not necessary and pressurized fluidized beds are sufficiently different from 

traditional designs that retrofits are unlikely. However, advanced combustion controls are applicable to existing 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

9

facilities and the exemption is not necessary to further the development of the technology. That exemption is not 

included in the final amendments.

DOE-funded technology demonstration projects are typically installed at existing EGUs and would not trigger 

applicability with the NSPS requirements. Therefore, the exemption would not be applicable. If in the future DOE 

were to request EPA evaluate the exemption for DOE-funded technology demonstrations it could be considered in 

a future rulemaking.

2.2.3 Applicability to Permitted EGUs for which Construction Has Not Commenced 

Comment: One commenter (4830) states that EPA must appropriately accommodate permitted facilities for 

which construction will not have commenced prior to the date of the NSPS regulation. Several electric utility 

entities have recently obtained air permits authorizing the construction of new units. However, they were not in a 

position to commence construction on these new units prior to the date that EPA intends to apply the proposed 

NSPS to facilities that have not commenced construction (May 4, 2011). As a result, these units will be regulated 

as new sources under this proposed rule. This situation creates significant inequities for the projects that are 

permitted but have not commenced construction prior to the proposed NSPS, and ultimately, this proposal may 

prevent the projects from being implemented, depending on the NSPS adopted in the final rule.

Response: Section 111(a) of the CAA defines a new source as one for which construction or modification 

commences after the publication of proposed regulation applicable to the source. In this case, the relevant date is 

May 4, 2011 and any source which commences construction or modification after that date is a new source for 

purposes of the final regulations. EPA has long defined “commenced” in this context to mean “that an owner or 

operator has undertaken a continuous program of construction or modification or that an owner or operator has 

entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program 

of construction or modification.” 40 CFR 60.2. Merely obtaining an air permit authorizing construction does not 

meet this requirement. Furthermore, EPA disagrees that the NSPS amendments will prevent projects from going 

forward since, on average, the standards have minimal impact on the capital cost of a new EGU, cost less than 

$10/kW (less than a 1% increase), and are achievable for a range of technologies and coal types. Therefore, we 

have concluded that the amended standards would not require significant redesign of already permitted facilities 

or impact the decision on the type of boiler or fuel selection.

2.3 Particulate Matter (PM) Emissions Standards

2.3.1 Selection of BSER for PM Emissions

Comment: Several commenters (4765, 4836, 5089, 5715) state that the proposed NSPS for PM emissions does 

not reflect the application of BSER systems of emissions reduction. Commenters differ as to which PM emissions 

control technologies should be used as BSER for establishing the NSPS emission limits. One commenter states 

that EPA’s proposal to require new facilities to meet the same limits already achieved by many existing sources is 

contrary to the clear requirements of the statute and Congressional purpose to require new sources to apply the 

best demonstrated systems of pollution control. Instead, EPA sets PM standards that are “achievable” by all new 

sources (and even many existing sources) rather than standards that are “achievable” through the application of 

the best adequately demonstrated system of emissions control, as the CAA requires. One commenter (4765) states 

that the CAA §111(a)(1) does not allow EPA to base an NSPS on a BSER that is a combination of technologies 

and EPA has not attempted to do so in the past.

Response: The amended PM standard is a filterable only standard and the BSER would therefore only include a 

fabric filter. The BSER can take into account multiple factors including, but not limited to, choice of generation 

technology, fuel selection, and multiple emission control technologies. Nothing in the CAA limits BSER to a 

single emissions control technology.

2.3.2 Regulation of Combined PM Emissions 

Comment: Many comments were received in support of and in opposition to the proposal to establish a new 

combined PM emissions limit for EGUs that is determined by adding the measured condensable PM plus the 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

10

measured filterable PM. Commenters’ (4698, 4710, 5715, 5210) reasons for supporting the proposal include 1) 

some state permitting agencies already regulate condensable PM for steam generating; and 2) methods now exist 

to both measure and control condensable PM. One commenter (4714) notes that the State of Texas has regulated 

condensable PM through permitting for more than three decades. 

Commenters (4712, 4766, 4836, 4989, 5075, 5077, 5089, 5208) oppose the proposal for a number of reasons. 

Changing the existing NSPS for PM from a filterable PM standard to a combined PM standard by basing the 

proposed emissions limit on the performance of the top 20% best performing units is unlawful and arbitrary. 

EPA cannot establish a combined PM emissions limit because the Agency failed to follow the CAA statutory 

requirements for establishing a standard by not identifying the condensable PM component, how to control 

condensable PM, or what BSER is for reducing condensable PM emissions. Also, BSER for filterable and 

condensable PM components are separate. There is no basis for establishing an emissions limit at the emission 

rate expected by the best performing 20% of the industry, when EPA has not provided any guidance on how 

the rest of the industry might seek to comply. Commenters also state that the proposed compliance procedures 

for the combined PM standard are unworkable because EPA Test Method 202 is inadequate to measure the 

condensable PM component. 

Response: EPA Test Method 202 was promulgated in December 2010. The revised test method is as precise and 

accurate in measuring condensable PM as Method 5 or 17 are at measuring filterable PM. We have provided 

responses in the NESHAP response to comments concerning the reliability of Method 202. As such, we have 

concluded that it would be possible to establish and determine compliance with a combined PM standard (Method 

5 plus Method 202). 

Based on comments received and on further consideration since the proposal, however, EPA has concluded it is 

appropriate to amend only the filterable PM standard at this time. In a future rulemaking, we will specifically 

request comment on: i) the appropriate monitoring procedures, ii) whether separate standards for condensable PM 

and filterable PM have any benefit over a combined PM standard, and; iii) the appropriate numerical standards in 

each case. In addition, while EPA collected over 200 source tests for condensable PM from the Utility Boiler ICR, 

these tests represent only a single test for each facility. Therefore, subpart Da is amended to require Method 202 

testing and reporting of those emissions each time a Method 5 or 17 performance test is performed. This approach 

minimizes the burden to the regulated community, while at the same time collecting sufficient data for evaluation. 

If appropriate, EPA will include condensable PM in the PM standard in a future rulemaking that accounts for 

annual variability. The incremental cost of Method 202 over Method 5 or 17 is less than $700 (10% of PM testing 

cost). The proposed NESHAP ICR assumed condensable PM testing for all facilities subject to the NESHAP. The 

amended NSPS ICR accounts for the subset that will be required to test under the NSPS.

While EPA plans on evaluating separate filterable and condensable PM standards, we support the present 

approach that several recent permits have taken in establishing a combined PM standard that includes both 

filterable and condensable PM. Controls required by an NSPS help in achieving and protecting the NAAQS. In 

the context of a PM standard, the relevant NAAQS is for PM10 and PM2.5. For this source category, a combined 

PM measurement represents mostly PM2.5 since the filterable controls remove the larger sized PM. The primary 

distinction between filterable and condensable PM is based on temperature, not the form of the PM in the ambient 

air. The NSPS establishes standards that can be met through the use of the best controls for managing the ambient 

air pollutant. We chose to issue a filterable only standard, rather than a combined PM standard, in part because of 

the inability to quantify particle size in a wet stack environment and recognition that many new EGU will employ 

wet scrubbers. Further, while the technology that best controls filterable PM may be different from that which 

best controls condensable PM, the available data does not establish a distinct line that differentiates filterable PM 

and condensable PM This is demonstrated by the fact that the Part III EGU NESHAP ICR data, indicates that 

some units with lower combined PM emissions had relatively low filterable PM emissions with somewhat higher 

condensable PM emissions, while other units had a more balanced control of filterable and condensable PM. 

In the proposal, we identified dry sorbent injection (DSI) to neutralize SO3 to sulfate prior to removal by a mist 

eliminator or particulate control and a wet ESP as control technologies for condensable PM. However, there are 

several additional measures that control condensable PM. These include, but are not limited to, (1) the selection of 

catalysts which minimize the formation of SO3 from SO2, (2) minimizing the temperature at which the particulate 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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matter control device operates, (3) minimizing the ammonia slip when SCR or SNCR is used, and (4) a more 

efficient mist eliminator. In addition, the sulfuric acid mist portion of condensable PM emissions is strongly 

dependent on the sulfur content of the incoming coal. All of these factors need to be taken into consideration in

establishing a meaningful national standard. At this time we do not have sufficient knowledge to determine the 

combination of control technologies which will achieve the best level of control of both filterable PM and 

condensable PM and, thus, cannot establish a technical basis for an appropriate national combined PM emissions 

standard. The additional condensable PM test data will allow us to evaluate the capabilities of a combination of 

techniques to reduce PM emissions. One potential outcome would be a PM standard that is based on the sulfur 

content of the coal, similar to the format for the SO2 emissions standard. Since we did not propose that approach, 

we plan on doing a future notice/comment rule that specifically requests comment on the best approach for 

achieving the best level of control of both filterable and condensable PM. 

Even though we are not establishing a PM standard that includes condensable PM, emissions of condensable PM 

by facilities subject to the amended requirements in subpart Da would not be uncontrolled. All new facilities in 

this source category would be subject to PSD and be required to account for condensable PM in performing the 

required analysis under that program. In addition, condensable PM emissions are generally lower for facilities 

with lower filterable PM emissions and high SO2 control rates and since the amended NSPS will require greater 

control of the emission of these pollutants, there should be some reduction in condensable PM. PM controls are 

more efficient at capturing filterable PM at lower temperatures and a greater proportion of the condensable PM 

will be solid and thus captured by the PM control device. The SO2 relationship results from the increased liquid to 

gas contact capturing more of the condensable PM.

2.3.3 Regulation of PM2.5 Emissions

Comment: One commenter (4841) states that a separate filterable PM2.5 should not be established due to both 

measurement issues with respect to wet stacks and also because control technologies installed for combined PM, 

NOX, and HCl/SO2 will result in reductions of both direct PM2.5 and PM2.5 precursors.

Response: The final rule amendments do not include a standard for PM2.5.

2.3.4 Selection of PM Emissions Limit Value

Comment: Several commenters (4714, 4765, 4836, 5075) state that the proposed PM emissions limit is not 

achievable on a nationwide basis, and as a result the final rule needs to be revised upwards to reflect the actual 

levels of performance achievable. Several commenters (4673, 4836) state that the proposed PM emissions limit is 

so stringent that it would effectively preclude construction of new coal-fired EGUs. Several commenters (4712, 

4989) state that the methodology EPA used to select the proposed PM emissions limit value does not sufficiently 

address variability in EGU fuel use, equipment design, and operation. One commenter (4713) states that PM 

emission limits for new source EGUs should be the same in the NSPS and NESHAP. One commenter (5210) 

examined the emissions limits in 27 permits and permit applications for proposed coal-fired EGUs and concludes

that a combined PM standard of 0.030 lb/MMBtu best reflects BSER for new EGUs. Moreover, of the 27 permit 

and permit application limits reviewed, 14 listed both a filterable PM limit and a combined PM limit. The 

commenter also requests that EPA either adopt the most stringent feasible filterable PM standard for modified 

EGUs or finalize a combined PM standard that reflects a BSER requiring additional controls for condensable PM

for these units.

Response: For the reasons explained previously, EPA is issuing a final standard for filterable PM only and that 

standard is appropriate for a national requirement as it represents BSER for both new and modified facilities and 

takes variability into account. The amended standard is technology and fuel neutral and multiple PC and FB 

EGUs burning various coal types are presently operating below the amended standard. Finally, the amended 

standard is consistent with the NESHAP and the 0.090 lb/MWh PM standard accommodates IGCC facilities in 

multiple operating modes.

Comment: One commenter (5279) states that the proposed PM emissions limit should be revised to address the 

use of duct burners at IGCC facilities when fired using syngas and using natural gas. The commenter states that 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

12

higher PM emission limits than the proposed limit are required when operating under either of these two 

scenarios.

Response: The PM standard is based on the permit conditions for an IGCC and accounts for both operating 

conditions.

2.3.5 PM Control Cost Analysis

Comment: Many commenters (4635, 4656, 4765, 4766, 4686, 4830, 4836, 5075, 5089, 5240) state that EPA 

failed to independently calculate the control costs for implementing the proposed PM emissions limit as required 

by the CAA § 111(a)(1). It specifies that EPA “tak[e] into account the cost of achieving such reduction and any 

non-air quality health and environmental impact and energy requirements...” when establishing NSPS. 

Instead, EPA has unlawfully relied on the PM emissions reductions that it anticipates to occur through 

implementation of the proposed NESHAP for EGUs. EPA concludes that the proposed NSPS PM emissions 

limit will not result any costs or benefits attributable to implementing the NSPS.

Response: Docket item EPA-HQ-OAR-2011-0044-0002 includes an incremental cost analysis and a secondary 

environmental impacts analysis for the proposed PM emissions limit and EPA concluded that these would support 

the NSPS even absent the NESHAP. 

2.3.6 PM Standards Exemptions

2.3.6.1 Opacity Standard Exemption for EGUs Using PM CEMS

Comment: Several commenters (4673, 4766, 4836) state that EPA should exempt EGUs subject to 40 CFR 60 

subpart D and using PM CEMS from the opacity standard requirements. For affected EGUs that monitor PM

emissions directly with a method EPA has determined as “sufficiently accurate,” the surrogate opacity standard is 

no longer necessary to assure compliance with the applicable PM emissions limit. EPA should finalize the 

exemption proposed in 2008 for any EGU subject to 40 CFR 60 subpart D that demonstrates continuous 

compliance with the applicable PM emissions limit on a 24-hour (not 3-hour) average basis.

Response: We agree with the commenters that using PM CEMS provides not only a continuous check on the

ability of the PM control device to minimize filterable PM emissions but also a direct, continuous measure of 

compliance with the filterable PM emissions standard. The rule allows source owners or operators who choose to 

use PM CEMS with a three hour averaging time demonstrating continuous compliance with the filterable PM 

emissions limit to drop the requirement for COMS for purposes of the NSPS. Should source owners or operators 

want a different averaging time, they can petition the Administrator in accordance with the requirements in 40 

CFR 60.42(c). Furthermore, the EGU NESHAP includes an existing source filterable PM standard of 0.030 

lb/MMBtu as an alternate to measuring total metals. Therefore, the vast majority of subpart D facilities will be 

installing controls that would allow them to control PM emissions to such an extent that the opacity standard 

would no longer be applicable.

2.3.6.2 Opacity Standard Exemption for EGUs Complying with a Combined PM Standard 

Comment: One commenter (4836) supports EPA’s proposed opacity standard exemption for affected EGUs 

complying with a combined PM emissions limit.

Response: The final rule amendments do not include a combined PM emissions limit (see Section 2.3.3) and, 

therefore, the proposed exemption is no longer relevant.

2.3.6.3 PM and Opacity Standard Exemptions for Natural Gas Fired EGUs

Comment: Several commenters (4836, 4841, 17711, 17852) support EPA’s proposed opacity standard exemption 

for natural gas fired EGUs. However, one commenter (4836) does not understand why EPA proposes to limit the 

Subpart D exemption to those facilities subject to a federally enforceable permit limiting fuel use. No such 

condition is attached to the proposed Subpart Da exemption. The commenter also does not understand why EPA

has not proposed to exempt Subpart Da facilities that combust only natural gas from the filterable PM standards. 

Those facilities also will have negligible filterable emissions. As long as the facility is actually combusting only 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

13

natural gas, it should be exempt from filterable PM and opacity standards regardless of a pre-existing permit 

restriction. One commenter (17852) also states that the option to integrate combustion turbines and/or fuel cells 

with steam generating units is another good way to reduce emissions. The commenter also states that if an owner 

chooses to integrate and connect a fuel cell or combustion turbine to a steam boiler to use waste heat to improve 

efficiency, they should be able to elect to consider them an integrated unit for compliance purposes.

Response: The “federally enforceable permit” requirement has been removed from subpart D. The second part of 

the comment is unclear since the proposed language in paragraphs §60.42Da(a)(4), (e), and (g) exempt natural 

gas-fired EGUs from the PM standard. 

Comment: One commenter (5749) states that EPA should clarify the circumstances under which 40 CFR 60 

subpart Da may apply to gaseous fuel firing, where such gaseous fuel is not a fossil fuel (for example, where a 

non fossil gaseous fuel is combusted in combination and/or alternately with a fossil fuel). To the extent that 

Subpart Da would apply under any such circumstance, EPA should extend the Subpart Da exemption from PM 

and opacity limits for natural gas units to also apply to gaseous fuel fired units, such as those firing landfill gas. 

The commenter believes that landfill gas and other non fossil gaseous fuels have similar emission profiles to

natural gas, and should be encouraged as viable alternatives to fossil fuels, including natural gas.

Response: A facility that only burns non fossil gaseous fuels would not be subject to subpart Da. Subpart Da only 

applies to owners/operators of facilities capable of combusting more than 250 MMBtu/h of fossil fuel and 

supplying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output 

to any utility power distribution system for sale. Owners/operators of that meet the fossil input requirements and 

co-fire non fossil fuels would be subject to subpart Da. We have concluded it is not appropriate to provide an 

outright exemption for all co-fired gaseous fuels since they can potentially contain contaminants that result in PM 

emissions and opacity. However, the amount of sulfur in a gaseous fuel is a general indication of the amount of 

impurities. Therefore, gaseous and liquid fuels with potential SO2 emissions rates of less than 0.060 lb/MMBtu 

are included in the PM exemption, but not the opacity exemption. Other gaseous fuels do not necessarily burn as 

completely as natural gas. Subpart Da already includes reduced opacity monitoring for owners/operators burning 

gaseous fuels other than natural gas.

2.3.6.4 PM and Opacity Standards Exemption for Low-Sulfur Fuel Fired EGUs

Comment: One commenter (4836) supports EPA’s proposal to exempt EGUs that combust only gaseous or liquid 

fossil fuel with potential SO2 emission rates of 0.060 lb/MMBtu or less from the otherwise applicable filterable 

PM standard, provided the EGU does not use post-combustion SO2 or NOX controls. One commenter does not 

support this option for other forms of oil, especially for No. 4 oil and other grades. Another commenter (4698) 

opposes the exemption because opacity emissions from EGU firing such fuels is not generally due to fuel ash and 

impurities but rather is more a function of incomplete fuel combustion.

Response: EPA agrees that opacity and filterable PM emissions from low sulfur oil-fired boilers are a result of 

incomplete combustion and do not result from fuel ash or impurities. However, EPA believes that 20% opacity 

would rarely occur at facilities burning these fuels. Therefore, subparts D, Da, and Db are amended to include a 

provision providing state permitting authorities the flexibility to approve site-specific monitoring requirements for 

distillate oil containing less than 500 ppm sulfur, while still maintaining the opacity standard itself. This 

flexibility will be especially beneficial to owners/operators who only burn distillate oil as a backup fuel. The state 

would then have the flexibility to either require the procedure set forth in the rule or the owner/operator could 

monitor carbon monoxide emissions as an alternative.

2.4 Sulfur Dioxide (SO2) Emissions Standards

2.4.1 Selection of BSER for SO2 Emissions

Comment: Many commenters (4712, 4715, 4765, 4836, 5715, 4989) state that EPA failed to state the BSER that 

the Agency selected as the basis for establishing the proposed SO2 emissions standards. One commenter (5715) 

states that the proposed SO2 emissions rates are not the result of an analysis of the application or performance of 

BSER systems of SO2 emission reduction– instead they are based on the SO2 emissions rates that are already 
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14

being achieved by existing EGUs. EPA’s BSER determination analysis was not based on the application of new 

and innovative multi-pollutant control options nor the application of systems of emissions reductions that allow 

control of greenhouse gas emissions (which EPA is regulating under a separate rulemaking) along with control of 

SO2.

Response: The BSER for SO2 is the same as in the 2006 final amendments, low sulfur coal and a spray dryer or 

high sulfur coal and a wet scrubber. In this remand, the achievable standards were reevaluated, but no new 

technology developments have taken place so the BSER technologies were not changed. The facilities used to 

establish the numerical standard used low sulfur coal and a spray dryer, and the facilities used to establish the 

percent reduction requirement burned high sulfur coal and used a wet scrubber. EPA has concluded it is not 

appropriate to base the amended SO2 standard on potential GHG requirements that have not been proposed. 

2.4.2 Selection of SO2 Emissions Limit Value

Comment: Many commenters (4715, 4765, 4768, 4836, 5715, 4989, 5075, 5077) state that the proposed NSPS 

SO2 emissions limit does not reflect the application of BSER systems of emissions reduction, and the 

methodology EPA used to select the proposed SO2 emissions limit value does not sufficiently address variability 

in EGU fuel use, equipment design, and operation. One commenter (4836) included an analysis of the data set 

used by the Agency in evaluating the achievability of the proposed SO2 emissions limit using BSER. Based on 

this analysis, commenters state that an appropriate SO2 emissions limit is 1.25 lb/MWh for new units with an 

optional reduction limit of 96%. In contrast, another commenter (4715) states that EPA did not set the NSPS SO2

emissions limit based on the best demonstrated unit in its data set. Nearly all of EPA’s sample units (12 of 15 

units) could meet the proposed NSPS of a 97% reduction in SO2, and a third of the units (5 of 15 units) could 

meet a 98% reduction. Furthermore, all of the units in the data set that tested in the 97% reduction range, 

excepting one, tested in the upper limits of the 97% range. This fact indicates that a 98% reduction limit is 

achievable. EPA should incentivize the most efficient use of control technologies to achieve the maximum 

amount of SO2 reduction. The reduction limit of SO2 should be set at 98% for this NSPS. One commenter (5210) 

examined emissions limits of six existing coal units (at Intermountain Power, Colstrip, and Navajo) and the 

emissions limits in 29 permits and permit applications. Based on those data, the commenter recommends setting a

SO2 standard of at least 0.7 lb/MWh to reflect BSER for all EGUs.

Response: Both fluidized beds and pulverized coal EGUs have demonstrated that a 97% reduction in potential 

SO2 emissions is achievable. While short term data indicates that greater than 97% reduction may be achievable, 

it has not been demonstrated to be achievable on long term basis. Furthermore, a 97% reduction in potential 

emissions has only been demonstrated to be achievable for coals with nominal uncontrolled SO2 emissions of 

greater than approximately 3.5 lb/MMBtu. Assuming a gross efficiency of 36%, this correlates to a numerical 

emissions rate of 1.0 lb/MWh. Setting a numerical standard below 1.0 lb/MWh could limit the ability to use 

medium sulfur coals in new EGUs and drive the market toward subbituminous and low-sulfur bituminous coals.

While subbituminous coal and low-sulfur bituminous coal have inherently low sulfur content and thus low SO2

emission rates, neither is a viable option for establishing a national standard as the use of these ranks of coal is not 

practicable for some units due to transportation constraints, costs, and supply limitations. The transportation 

logistics and costs render the use of subbituminous coal by all new coal-fired generation unfeasible. 

Subbituminous coal is mined in the western states and requires long distance transportation, resulting in increased 

emissions from locomotives, increased energy consumption, and potential additional rail line construction due to 

existing rail system limitations. The use of lower sulfur eastern bituminous coal is also problematic as it is in high 

demand across the eastern United States and abroad. The increased demand does not just come from the electric 

generation sector, the coal is also in demand for use as a raw material in manufacturing. In addition, available 

veins of low-sulfur eastern bituminous coals are being exhausted. As a result, in recent years electric utilities have 

begun to burn eastern bituminous coals with increasingly higher sulfur content levels. In addition, adding a 

subbituminous-fired boiler at an existing site designed to burn bituminous coal would require significant design 

changes to the coal material handling and other existing ancillary equipment.

Comment: One commenter (17622) states that Table 17- SO2 Emissions Performance Data in the proposal notice 

(76 FR 25065) used by EPA to select the SO2 performance level for EGUs lists the best performing units in terms 
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of percentage SO2 control and the subsequent commentary incorrectly indicates that with the exception of the HL 

Spurlock Units 3 and 4, all utilize wet limestone scrubbing technology. The three units at the Harrison Station 

utilize wet magnesium on demand lime scrubbing technology, not wet limestone technology.

Response: The Harrison technology description has been corrected.

2.3.3 SO2 Control Cost Analysis

Comment: Many commenters (4635, 4656, 4765, 4766, 4686, 4830, 4836, 4989, 5075, 5240) state that EPA 

failed to independently calculate the control costs for implementing the proposed SO2 emissions limit as required 

by CAA §111(a)(1). It specifies that EPA, “tak[e] into account the cost of achieving such reduction and any 

non-air quality health and environmental impact and energy requirements...” when establishing NSPS. 

Instead, EPA has unlawfully relied on the SO2 emissions reductions that the Agency anticipates from 

implementation of the proposed NESHAP for EGUs. EPA concludes that the proposed NSPS SO2 emissions 

limit will not result any costs or benefits attributable to implementing the NSPS.

Response: In proposal docket item EPA-HQ-OAR-2011-0044-0002 an incremental cost analysis and a secondary 

environmental impacts analysis include control costs for implementing the proposed SO2 emissions limit. On the 

basis of that information, EPA concludes the SO2 limits are achievable and cost effective even in the absence of 

the NESHAP.

2.4.4 Coal Refuse-Fired EGU Exemption from SO2 Standards

Comment: One commenter (5715) states that EPA’s proposal to exempt EGUs burning more than 75% coalrefuse on an annual basis from the proposed NSPS for SO2 emissions and instead allow such units to meet the 

existing NSPS for SO2 emissions is unlawful. The commenter states that in proposing to establish such an 

exemption, EPA failed to distinguish these EGUs as a subcategory warranting separate emissions standards in 

accordance with the proper statutory requirements as provided by 42 U.S.C. §7411(b)(2) (“the Administrator may 

distinguish among classes, types and sizes within categories of new sources for the purpose of [setting NSPS].

One commenter (5210) states that new coal refuse-fired EGUs can meet the same standard that EPA is proposing 

to maintain the existing SO2 emissions standard of 1.4 lb/MWh for owners/operators of affected facilities 

combusting 75% or more coal refuse on an annual basis. The commenter recommends that EPA adopt a SO2

standard of 0.07 lb/MWh output for units burning 75% or more coal refuse.

Response: Coal refuse-fired facilities are subcategorized for the secondary environmental reasons stated in the 

proposal. The amended standards are based on the best performing coal refused-fired EGUs. The Seward 1 and 2 

coal refuse-fired EGUs are the best performing facilities in terms of percent SO2 control. Both have demonstrated 

that 94% reduction is achievable, but no coal-refuse-fired EGU has demonstrated greater than 94% reduction. 

Therefore, the percent existing percent reduction standard of 94% is BSER and unchanged. While we have no 

data that any existing coal refuse-fired EGU is presently meeting the existing numerical SO2 standard, we are 

maintain that standard to avoid backsliding of the NSPS. Similarly, the Northeastern 31 EGU is the best 

performing coal-refuse-fired EGU in terms of NOX. The facility has demonstrated a NOX emissions rate of 0.85 

lb/MWh and we are therefore amending the standard accordingly. Furthermore, the previous 8 PM performance 

tests at the Northampton NGC01 coal refuse-fired EGU have been under the amended PM standard of 0.090 

lb/MWh.

2.5 Nitrogen Oxides (NOX) Emissions Standards

2.5.1 Selection of BSER for NOX Emissions

Comment: One commenter (5715) states that the proposed NSPS to control NOX emissions (a combined 

NOX/CO standards and an alternative NOX standard) does not reflect the application of BSER systems of 

emissions reduction. EPA’s selection of selective catalytic reduction (SCR) and selective noncatalytic reduction 

(SNCR) with advanced combustion controls does not represent BSER systems for control of NOX emissions. 

Furthermore, EPA failed to state the BSER that the Agency selected for controlling CO emissions. The 
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16

commenter states that EPA’s BSER analysis did not evaluate the NOX and CO emissions reductions achievable by 

all available NOX and multipollutant control technologies.

Response: Since SCR has not been widely applied to fluidized bed boilers, SNCR in combination with good 

combustion controls achieve the lowest NOX emissions rate, and are, therefore, considered BSER. Regenerative 

SCR is a relatively new technology and emissions rates are not yet available. For pulverized coal boilers, BSER

was determined to be the use of advanced combustion controls and SCR. The only currently viable CO controls 

on EGUs are combustion controls.

2.5.2 Combined NOX + CO Emissions Limit

Comment: Many commenters (4673, 4712, 4836, 4989) object to establishing a mandatory NOX + CO NSPS 

emissions limit for EGUs at this time because of limited CO emissions data and the inadequate methodology used 

to determine the emissions limit. An analyses prepared by one commenter concludes that such a standard is 

unachievable for many EGUs much of the time. However, several of these commenters (4673, 4836, 4839, 5470) 

also state that a combined NOX and CO emissions limit could provide an advantage in terms of compliance 

flexibility. These commenters do not object to establishing an NOX + CO emission limit that EGU 

owners/operators could chose to comply with as alternative to a NOX emissions limit. Other commenters (4715, 

5715) support EPA establishing a mandatory NOX + CO NSPS emissions limit for EGUs. However, one 

commenter states that EPA failed to explain why the Agency believes that a NOX + CO emissions limit of 1.2 

lb/MWh for new sources reflects BSER systems of emission reduction, when it is at a significantly higher 

emissions rate than its NOX-only emissions limit proposed alternative. The NSPS emissions limit for NOX + CO 

should be lowered to reflect BSER, or at the very least, EPA must select a standard at the low end of the proposed 

range. Another commenter (17620) states that a better option to adopting a combined limit for NOX + CO would 

be to set a sufficiently stringent CO standard that avoids poor combustion. Allowing inappropriately high CO 

levels will simply permit sources to use less effective SCR controls and emit higher levels of organic HAPs than 

would limits that are based on the level of NOX reduction and CO levels achievable by high efficiency SCRs 

controls.

Response: While EPA believes that the limited data available supports the achievability of a combined NOx/CO 

standard in at least some circumstance, it does support the imposition of such a standard across the board. As a 

result, the combined NOX/CO standard will be provided as an alternative to the amended NOX standard. The 

alternative standard will be 1.1 lb/MWh, as that is the lowest standard that has been demonstrated for both 

pulverized coal and fluidized bed technologies. The combined standard is much more stringent than recent 

separate NOX and CO BACT permits. The majority of CO BACT standards are 0.10 lb/MMBtu or greater. This 

translates to an approximate CO emissions rate of 1.0 lb/MWh. With corresponding BACT NOX standards of 0.70 

lb/MWh, this corresponds to an equivalent combined standard of 1.7 lb/MWh.

Comment: One commenter (5210) states that EPA must set the most protective NOX standard. EPA requested 

comment on whether the Agency should adopt a single NOX standard or a combined NOX + CO standard. While 

supporting EPA’s suggested benefits of such a combined standard, the commenter states concern over if and how 

the Agency weighed the different health and environmental impacts of NOX and CO in determining the proposed 

combined standard. It appears the Agency weighed them equally, which the commenter believes is not 

appropriate, given the greater health and environmental impacts of NOX and its contribution to ozone. While the 

commenter does not want CO emissions to significantly increase as a result of NOX controls, the commenter is 

concerned that the flexibilities of a combined NOX + CO standard will provide for an ultimately more lenient NOX

standard, resulting in fewer reductions. Therefore, the commenter recommends that EPA at the least set the most 

stringent standard feasible for NOX, in order to protect public health and the environment from the harmful 

impacts of ozone, PM, and other NOX related emissions. Another commenter (5208) states that a combined NOX

+ CO standard potentially would allow higher NOX emissions that would not protect the more stringent nitrogen 

dioxide (NO2) National Ambient Air Quality Standard (NAAQS). 

Response: EPA has concluded that the combined standard is sufficiently stringent. New facilities would at a 

minimum have to reduce emissions to the existing NOX standard in subpart Da, that was established in 2006, to 
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17

comply with the standard. Therefore, this is not a relaxation of the existing requirements and would not result in 

increased NOX emissions.

2.5.3 NOX Emissions Limit 

Comment: Several commenters (4712, 4765, 4768, 4836, 5075) state that the proposed NOX emissions limit is

not achievable on a nationwide basis, and the final rule should be revised upwards to reflect the actual levels of 

performance achievable. In addition, a separate NOX emissions limit should be set for modified EGUs subject to 

the NSPS. Several commenters (4712, 4768) state that the methodology EPA used to select the proposed NOX

emissions limit value does not sufficiently address variability in EGU fuel use, equipment design, and operation. 

One commenter (4768) includes their analysis of the data on which EPA based its determination that the proposed 

NOX emissions limit is achievable using BSER. Based on this analysis, the commenter asserts that an appropriate 

NOX emissions limit is 0.83 lb/MWh for new units and 1.1 lb/MWh for modified or reconstructed units. The

commenter states that the NOX emissions standard for modified units should be based on the performance of cell 

burners, wet-bottom boilers, and cyclone fired EGUs. The commenter further notes that recent consent decrees for 

SCR-equipped cyclone boilers require NOx emissions between 0.100 to 0.0120 lb/MMBtu.

Response: The proposed standard of 0.70 lb/MWh has been demonstrated to be achievable by both pulverized 

coal and fluidized bed boilers burning various coal types. Since the CEMS data used in establishing the standards 

included long term data, various operating conditions and variability are inherently accounted for. In recognition 

of the difficulties of retrofitting certain modified facilities with combustion controls, the final NOX standard for 

modified facilities is 1.1 lb/MWh.

Comment: One commenter (5077) states that emissions during startup and shutdown periods have a particularly 

large impact on NOX emissions, even after taking into account the compensating effect of a 30-day rolling 

average. Hence, these periods need to be excluded in the evaluation of compliance with the standard. Further, 

EPA should set a higher NOX NSPS standard for modified units, since older modified units typically have higher 

heat rates than new units.

Response: Periods of startup and shutdown have not been filtered out of the CEMS data used to establish the 

standards, so there is no reason to separately evaluate those periods. The standard accounts for emissions typically 

being higher during periods of startup and shutdown and at the same time is sufficiently stringent that 

owners/operators need to minimize emissions during all periods to comply with the 30-day standard. The final 

standard for modified units (1.1 lb/MWh) is based on CEMS data from facilities using subcritical steam 

conditions and accounts for the higher heat rates of older facilities.

Comment: One commenter (4830) states that the proposed NOX NSPS of 0.70 lb/MWh appears to eliminate the 

further use of lignite coal for new EGUs. Section 111(a) requires EPA to explain the economic and energy 

impacts when establishing NSPS. Lignite coal is an abundant resource in the upper mid-west and Gulf Coast areas 

and elimination of it as an energy source would have significant regional economic impacts. EPA has the 

discretionary authority to subcategorize EGUs such that lignite-fired EGUs could have different NOX standards 

based on BSER for lignite. Thus, EPA should propose lignite NOX NSPS for new units. EPA has not 

demonstrated that non-lignite-fired units can meet the preferred 0.70 lb/MWh considering the inclusion of startup 

and shutdown periods into the compliance period. Accordingly, the alternative standard of 0.80 lb/MWh is more 

representative of what can be realistically achieved for non-lignite units, and no level lower than that should be 

considered for the NOX NSPS for new units.

Response: While the Oak Grove facilities use supercritical steam conditions, increasing the steam temperature 

and pressure to those used at the Weston 4 facility would reduce fuel use and emission rates by approximately 

2.5%. In addition, upgrading the heating value of the lignite to 10,000 Btu/lb would improve the efficiency of the 

EGU by almost 4%. Designing either of these things into a new lignite-fired EGU using the same control 

configuration as Oak Grove 1 would theoretically reduce the NOX emissions rate to less than the 0.70 lb/MWh 

amended NOX standard.

The Sandow 5B facility is a subcritical lignite-fired fluidized bed EGU and is presently operating below the 

combined NOX/CO standard. Furthermore, increasing the steam temperature and pressure to those used at the 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

18

Weston 4 facility would reduce fuel use and emission rates by approximately 5%. In addition, upgrading the 

heating value of the lignite to 10,000 Btu/lb would improve the efficiency of the EGU by almost 5%. 

Implementing both of these for a newly designed EGU using the same control configuration as Sandow 5B would 

theoretically reduce the NOX emissions rate to below the 0.70 lb/MWh amended NOX standard. Fluidized bed 

boilers are not limited in application since they are available in various sizes, the largest individual unit is 460 

MW, and are able to utilize supercritical steam conditions. 

As described elsewhere in the response to comments, the 0.70 lb NOX/MWh is achievable for all of the primary 

coal (and petroleum coke)-fired EGUs. 

2.6 Compliance Requirements

2.6.1 Opacity Monitoring 

Comment: Many commenters (4712, 4836, 4989) support EPA’s proposal to allow affected EGUs using a PM 

continuous monitoring system (CEMS), a fabric filter bag leak detection system (BLDS), or an electrostatic 

precipitator (ESP) predictive model to be exempted from the existing requirement to install a continuous opacity 

monitoring system (COMS). 

Response: The final rule amendments include a provision allowing affected EGUs using a PM CEMS, a fabric 

filter BLDS, or an electrostatic precipitator (ESP) predictive model to be exempted from installing a COMS. 

Comment: Several commenters (4673, 4836) support EPA’s proposal to reduce the frequency of visible 

emissions testing for affected EGUs that are subject to an opacity standard, but are not required to use a COMS. 

The commenters further note that when EGUs are subject to state air permit requirements to conduct Method 9 

visible opacity tests, visible emissions testing requirements under the NSPS are redundant and may conflict with 

the state requirements. The commenter recommends that EPA add a provision in the rule explicitly allowing 

permitting authorities the discretion to waive any NSPS visible emissions testing as long as the state testing is at 

least as frequent.

Response: All the boiler rules have been amended to allow the permitting authority the discretion to establish site 

specific monitoring plans for owners/operators of facilities burning fuels that typically result in low opacity. The 

frequency of Method 9 performance testing for owners/operators of facilities with some visible emissions, but 

with all 6-minute readings of less than 5%, has been reduced from every 6 months to every 12 months. The 

frequency of opacity monitoring for owners/operators of facilities with higher opacity is unchanged. The 

additional testing frequency for facilities with opacities of 5% and higher is required to adequately assure 

compliance with the opacity standard. 

2.6.2 PM Continuous Emission Monitoring

Comment: Several commenters (4989, 5077) oppose removal of the option to use Method 19 of Appendix A 

when the PM CEMS minimum data availability conditions are not met. One commenter (5077) states that 

removal of the option to use Method 19 of Appendix A eliminates a credible option to provide data when monitor 

availability falls below a required threshold. Without the Method 19 option, a source that does not meet the data 

availability requirements would have to obtain data using “other monitoring systems.” EPA provides no reason in 

the proposed rule for removing the Method 19 option. 

Response: The redline included the intended edits and the amendatory language was in error. The option to use 

Method 19 has not been removed in the final rule.

Comment: Several commenters (4989, 5077) stated concerns about the ability of PM CEMS to meet the 

proposed 90% availability requirement on a 30-day rolling average basis because of the limited number of 

installations of PM CEMS on EGUs. One commenter (5077) requests that EPA consider using a 75% data 

availability requirement when validating a required reporting duration (i.e., 30 day rolling average).

Response: We find the commenter's concern about a limited number of PM CEMS installations on utility units to 

be misplaced, as over 100 EGUs have installed and are operating PM CEMS. As we are unaware of situations that 
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19

have caused or may cause data availability from these units with PM CEMS to be below ninety percent, we find 

that that level is achievable in the field and that there is no need to lower it.

Comment: One commenter (4989) states that for the PM CEMS missing data procedures EPA is proposing to 

replace references to “valid” data with the phrase “non-out-of-control” data. Neither of these terms are defined in 

Subpart Da.

Response: The part 63 definition for “out-of-control” has been added to subpart Da. This amendment improves 

consistency for reporting and reduces burden to the regulated community.

2.6.3 Electronic Reporting of Performance Test Data

Comment: Several commenters (4712, 4836, 4989, 5077) opposes EPA’s proposal specifying mandatory

electronic reporting of PM CEMS performance data and Relative Accuracy Test Audit (RATA) data to EPA’s 

Central Reporting Data Exchange (CDX) using the Electronic Reporting tool (ERT). The commenters state that 

this proposed requirement is unlawful, unsupported, and incomprehensible for the following reasons: 1) EPA has 

not articulated the purpose of the submission and reconciled that with existing reporting requirements, 2) EPA has 

not used appropriate terms to identify the data required to be submitted, 3) EPA has not submitted an Information 

Collection Request (ICR) and obtained Office of Management and Budget(OMB) approval as required by the 

Paperwork Reduction Act (PRA) for the data to be reported, and (4) EPA has not provided a reporting format 

compliant with EPA's Cross-Media Electronic Reporting Regulation (CROMERR) requirements. 

Response: EPA strongly disagrees with the statement that the submittal of performance related data using the 

ERT is unlawful, unsupported, and incomprehensible. Section 114 of the Clean Air Act specifically allows EPA

to require the submittal of emissions (and other environmental data) to develop regulations. In fact, in support of 

this rulemaking, there was an information collection request (ICR) that affected many facilities. If EPA had had 

these performance test data prior to the rulemaking, then an extensive ICR would not have been needed. We 

believe that requiring that such data be routinely submitted using the ERT will eliminate, or at least reduce, the 

need for such an extensive ICR in conjunction with future rulemaking. In answer to item 1 above, the purpose of 

requiring the submission of performance tests is to support the development of regulations. In addition, 

performance test data will be used to improve emissions factors, develop control strategies, determine rule 

effectiveness, and support other air pollution control activities. Assuming the commenters meant performance test 

reports, rather than performance data, disagrees with the statement that the requirements to submit performance 

test reports to EPA are unsupported. EPA has already required the use of the ERT for several information 

collection requests and has promulgated several other rules that require its use. Further, EPA as a whole has been 

working toward electronic submittal of environmental data and information; see, for example, the Risk 

Management Plan information required in 40 CFR part 68 and the Toxics Release Inventory requirements in the 

Emergency Planning and Community Right-to-Know Act of 1986. There are other common examples of 

electronic reporting, such as filing income tax, as well. Electronic reporting allows for easier submission and 

storage of data and will allow easier review and access for all stakeholders. If the commenters meant the submittal 

of the PM CEMS data, EPA also disagrees with the commenters. EPA has concluded that these data are important 

for determining the operation of the facility. These data are also important for determining compliance with this 

regulation. Thus, EPA is establishing a system to collect these data.

EPA is not sure what the commenters intend in stating that the requirement are incomprehensible. We have 

concluded that the requirement is clear on its face and, for the reasons stated above, electronic reporting of data is 

a very good solution, both for EPA and for industry, for the collection and review of air quality data. If the 

incomprehensible comment pertains to the ERT, our response is that ERT has been used by many source testing 

companies and is steadily improving. EPA has worked very closely with the source samplers and industry to 

identify and correct most of the problems encountered with its use. In response to item 2, EPA is not sure what the 

commenters are asking. EPA developed the ERT with former source testing personnel and in conjunction with 

source testing companies. The model for the ERT was and is the performance test requirements in the parts 60 

and 61 general provisions. The input of source testing companies was integral to the development of this tool and 

we are continuing to work closely with source samplers. Thus, common source testing terms are used in the ERT 

and most of the users of this tool have had little trouble in understanding what is required. The response to item 3 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

20

is that EPA will be accounting for ERT use in the ICR for the final regulation. EPA believes that requiring the use 

of this tool will not significantly increase any costs in the reporting of performance test data and will probably 

eventually result in a reduction in costs. EPA is aware that many source testing companies and most major 

facilities already use their own systems to gather performance test data electronically. EPA believes that the ERT 

works well and is ready for use. EPA also disagrees with the statement in item 4. EPA is working closely with the 

Office of Environmental Information to establish the procedures necessary to ensure that ERT submittals through 

EPA’s Central Data Exchange are compliant with the Cross-Media Electronic Reporting Regulation. EPA will 

have this process completed prior to the time when the ERT submittals are required.

Comment: One commenter (4674), a state air regulatory agency, intends to continue to request affected owner or 

operators to submit hard copies of stack test reports to the State, in addition to EPA’s collection of stack testing 

data via the Electronic Reporting Tool (ERT), and therefore supports EPA’s preservation of related requirements 

in 40 CFR 60.8 and 60.11. The commenter believes that the stack test data reported must be considered along 

with additional, specific information for each source’s operations. This evaluation cannot be easily conducted 

with the limited data reported in the ERT. The State believes that the stack test data submitted in the ERT, taken 

at face value, may be misleading unless the context in which the testing was completed is understood. Until the 

number and degree of source configuration and operation variables can be adequately accounted for and reported 

in one reporting tool, allowing the associated test data to be wholly considered, the State relies heavily upon the 

submission of written stack test reports. Thus, the commenter supports EPA’s preservation of the submittal of 

written performance testing reports to state agencies, and requests that EPA consider a way for states to report to 

EPA via the ERT that the test is not approvable or was not representative.

Response: EPA agrees that the State and Local Air Pollution Control Agencies (S/Ls) should be able to continue 

to require stack test reports to be submitted in the format that best suits their needs. However, EPA encourages 

S/Ls to consider requiring the submission of stack test data electronically as well and the ERT is a readily 

available tool for S/Ls use. In response to the comment that the stack test data taken at face value may be 

misleading, EPA disagrees. EPA believes that the data and information required to be submitted in the ERT is the 

same data and information that is included in written performance test reports and will allow for an adequate 

review of the stack test and its conduct. The ERT was designed using existing performance test reports. All the 

data in test reports is also clearly required in the ERT. EPA does believe that the S/Ls have the expertise and 

knowledge of their sources, such as operation variables and source configuration, and would generally be better 

able to evaluate stack test reports. Thus, we have designed the ERT, in conjunction with WebFIRE (the repository 

for ERT data), to allow for S/Ls to conduct a third-party review of the performance test reports. Regarding the 

comment to have the S/Ls submit the data, EPA is designing the reporting to be submitted by the sources. Where 

the S/Ls have comments concerning a particular performance test, they need to discuss with the source and have 

the source resubmit the test report. We have concluded that having the source resubmit their performance test 

report electronically will eliminate the burden associated with tracking different versions of the test report in 

different formats.

Comment: One commenter (4770) requests that the reporting requirements in rules Da, Db and Dc be amended 

to commence on January 1, 2013 so that affected owners and operators have adequate time to familiarize 

themselves with the requirements and procedures for using the CDX and ERT. Until then, affected facilities 

should be allowed to continue to submit paper copies of test data to EPA. In addition, the reporting requirements 

should be changed to 90 days after completion of correlation and performance tests so that affected facilities have 

adequate time to gather required data and make adequate resources available to submit the data.

Response: EPA does not agree that the electronic reporting of performance test data through the Central Data 

Exchange using the Electronic Reporting Tool (ERT) needs to be extended for one year because the ERT is 

difficult to use. EPA believes that the source testing community, for the most part, has had plenty of experience in 

the past year using the ERT. EPA has also worked closely with the source testing community to understand and 

address their concerns with ease of use, so there is no need to extend the commencement date. We agree that it is 

appropriate to allow the required reports to be submitted 90 days after completion of correlation and performance 

tests. Among other things, this will provide time for owners/operators to familiarize themselves with ERT. Thus, 

we are extending the date for submitting the ERT report to 90 days.
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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2.6.4 Monitoring PM and Opacity Emissions from EGUs Using ESPs

Comment: One commenter (17755) states the rule is not clear regarding how PM emissions will be monitored for 

EGUs using ESPs if and when the ESP is not running, e.g., during SSM or offline activities, and if the ESP is not 

running, commenter asks how these excess emissions will be detected using the ESP Predictive Model. The 

commenter states concerns that determining compliance with opacity and PM standards will be more complicated 

without some kind of continuous emission monitor in place. The commenter requests information and guidance 

on what constitutes an excess emission if there is no continuous emission monitor, and asks the following: how 

does the EPA anticipate that compliance with the emission limit be determined, would an inspector simply 

monitor and check all of the parameters established for the ESP Predictive Model, and if the ESP is operating 

outside the defined parameters is that considered an excess emission. 

Response: During periods of startup and shutdown the ESP predictive model would not apply and the 

owner/operator would be required to follow the specified work practice standards to minimize emissions.

2.7 Other Proposed Amendments

2.7.1 Rule Definitions

2.7.1.1 Definition of “Affected Facility”

Comment: One commenter (4836) stated that EPA’s rationale for proposing to revise the definition of “affected 

facility” by adding integrated combustion turbines and fuel cells is vague and ambiguous, and the existing 

definition should not be revised. Another (4766) stated that EPA should provide additional clarification regarding 

the proposed expanded definition of “affected facility” under subpart Da to include “integrated” combustion 

turbines and fuel cells. Although discussed briefly in the preamble, the word “integrated” is still unclear and is not 

well-defined in the rule. Also, although EPA suggests that its intent is to encourage and promote the use of such 

units, it is unclear how EPA’s proposed regulation would accomplish that goal. Without further explanation, the 

new definition of “affected facility” remains vague and ambiguous and should be eliminated.

Response: The definition has been clarified to specify that “integrated” means the device either supplies useful 

thermal output to the boiler or electrical output to power auxiliary equipment of the EGU. If the definition were 

not expanded to include integrated equipment, the intent of subpart Da could be circumvented by having auxiliary 

equipment provide steam to the EGU to increase the output of the EGU and decrease the corresponding outputbased emissions rate without accounting for the emissions from the integrated equipment. 

2.7.1.2 Definition of “Gaseous Fuel”

Comment: One commenter (5195) stated that EPA should clarify within subpart Da that the definition of “fossil 

fuel” does not include landfill gas, biogases or other materials such as engineered fuels that are produced from 

processing components of municipal solid waste. Because landfill gas and biogas are included under the proposed 

definition of “gaseous fuel,” and the term “gaseous fuel” is included in the definition of “fossil fuel,” there may be 

an ambiguity with respect to how these definitions relate to each other in implementing subpart Da. The 

commenter requests that EPA clarify the circumstances under which subpart Da may apply to gaseous fuel firing, 

where such gaseous fuel is not a fossil fuel (for example, where a non-fossil gaseous fuel is combusted in 

combination and/or alternately with a fossil-fuel).

Response: The definition of fossil fuel under subpart Da only includes fuels “created for the purpose of creating 

useful heat.’ Since landfill gas and other fuels derived from municipal solid waste are not derived for the purpose 

of creating useful heat they are not considered fossil fuels under subpart Da. The definition of gaseous fuel 

includes these fuels strictly for circumstances when non-fossil fuel gaseous fuels are burned in combination with 

fossil fuels to determine the appropriate monitoring requirements.

2.7.1.3 Definition of “IGCC Electric Utility Steam Generating Unit”

Comment: One commenter (4836) stated that EPA’s proposed revised definition of “IGCC Electric Utility Steam 

Generating Unit” should be reworded to read “The Administrator may waive the 50 percent solid-derived fuel 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

22

requirement during periods of the gasification system construction, startup and commissioning, shutdown or 

repair.” Adding startup and commissioning would provide the EPA Administrator with additional authority to 

resolve any regulatory problems associated with the construction and initial operations of an IGCC EGU. Adding 

shutdown would allow an operator to combust natural gas for safety reasons during shutdown.

Response: The definition has been amended as suggested.

2.7.1.4 Definition of “Natural Gas”

Comment: One commenter (4836) notes that the proposed Subpart D definition of” natural gas”, and the existing 

definitions of “natural gas” in 40 CFR 60 subparts Da, Db, and Dc, are slightly different from the definition of 

“natural gas” in Part 75. Another commenter (5749) stated that the definitions of “natural gas” used for the NSPS 

are different from the proposed definition of “natural gas” for the EGU NESHAP. The commenters recommend 

that EPA use this NSPS amendment rulemaking to make the definitions consistent in all of the rules to avoid 

confusion and unintended results.

Response: In an effort to make the definitions as consistent as possible, the definition of “natural gas” under the 

NSPS has been amended as follows: i) “maintains a gaseous state under ISO conditions” has been added; ii) the 

heating value range has been amended to 950 to 1,100 Btu/scf; iii) a statement that natural gas does not include 

“any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value,”

has been added; and, iv) a provision that the “maximum sulfur content is 20 grains per 100 standard cubic feet”

has been added. The definition for industrial sources has historically included liquefied petroleum gas and will 

continue to do so. However, it will be removed for subpart Da affected EGUs to make it more consistent with that 

used in part 75.

2.7.1.5 Definition of “Petroleum Coke”

Comment: Several commenters (4765, 4836) object to including petroleum coke in the definition of “coal” for 

purposes of NSPS subpart Da. Reasons cited by the commenters are 1) EPA acknowledged in its NSPS Subpart Y 

rulemaking that petroleum coke “is a by-product residual from the thermal cracking of heavy residual oil during 

the petroleum refining process,”(74 FR 25,304, 25,316/1), and therefore is not coal at all; and as a result, the 

nature of the analysis required for setting NSPS would be different for petroleum coke as compared to coal; 2)

EPA has failed to provide emissions data as to whether EPA’s proposed NSPS for PM, NOX or SO2 are 

achievable when petroleum coke is burned in a EGU, either during periods of normal operation or during periods 

of startup and shutdown. 

Response: When subpart Da was originally promulgated, petroleum coke was not as commonly used in utility 

boilers. Subsequently, when EPA finalized the industrial boiler NSPS, subpart Db, petroleum coke was 

recognized as a valuable fuel that has characteristics similar to coal and was therefore included in the definition of 

coal. From analysis of emissions data from facilities burning petroleum coke EPA has concluded that EGUs 

burning petroleum coke are able to achieve the amended criteria pollutant standards for coal-fired units.

The Northside 1A and 1B EGUs and the Manitowoc 9 petroleum coke-fired EGUs are achieving the PM standard, 

the AES Deepwater petroleum coke-fired EGU is achieving the NOX standard, and the Northside 1A facility is 

achieving the combined NOX + CO standard. While none of the petroleum coke-fired EGUs are achieving the 

amended SO2 standard, the SO2 technology is directly transferrable and other facilities burning high sulfur fuels 

have demonstrated that 97% reduction in potential SO2 emissions is achievable. Furthermore, the recent permit 

for the proposed Las Brisas Energy Center indicates that the amended NOX, SO2, and PM standards are 

achievable for a new petroleum coke-fired EGU. The proposed Las Brisas Energy Center would burn petroleum 

coke in a fluidized bed using subcritical steam conditions. The permit conditions for NOX and SO2 are 0.070 

lb/MMBtu and 0.114 lb/MMBtu respectively. The gross EGU efficiency would only have to be 34% (achievable 

using subcritical steam conditions) and 38% (achievable with supercritical steam conditions) to comply with the 

amended NOX and SO2 standards, respectively. In addition, based on the sulfur content of the petroleum coke, the 

SO2 control is designed to control over 97% of the potential SO2 emissions. 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

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2.7.2 General Duty 

Comment: One commenter (4836) stated that EPA’s proposal to add to Subpart Da a provision imposing a 

“general duty to minimize emissions” is neither necessary nor appropriate. Subpart Da facilities already are 

subject to the general duty under 40 CFR 60.11(d).

Response: EPA agrees that it is not necessary to include a specific provision imposing a “general duty to 

minimize emissions” in Subpart Da for the reason the commenter articulates. The provision has, therefore, been 

removed.

2.7.3 Affirmative Defense Provisions

Comment: One commenter (5210) stated that EPA’s proposed inclusion of the “affirmative defense” for 

malfunctions is unlawful and contravenes the CAA. The commenter states that the CAA clearly sets forth how the 

courts are to assess civil penalties, whether the case is brought by a citizen or EPA. 42 U.S.C. § 7413(e). By 

allowing an affirmative defense in the case of malfunction, EPA goes directly against two expressed intentions of 

Congress: 1) the burden it places on citizens makes it less likely that they will enforce the CAA, see, e.g., 

Pennsylvania v. Del. Valley Citizens' Council for Clean Air, 478 U.S. 546, 560 (1986);and 2) several of the 

factors at issue in the affirmative defense undercut Congress's intent that citizen suit enforcement should avoid redelving into "technological or other considerations, "NRDC v. Train, 510 F.2d 692, 700 (D.C. Cir. 1974). Both 

result from the technical burden EPA imposes on citizens with the affirmative defense, and both render the 

defense impermissible. In addition to these problems, there is simply no need for an affirmative defense to 

penalties to be written into the regulations. EPA has discretion to decide what cases to prosecute, to consider 

settlements, and to request civil penalties in a case-by-case manner, as long as it acts consistent with the CAA to 

protect clean air as its top priority, see U.S.C. § 7401. If EPA has the authority to promulgate any type of 

“affirmative defense”, then the commenter made specific recommendations for the provisions of such “affirmative 

defense”. Several commenters (4714, 4770, 4830, 4997) stated that the proposed “affirmative defense” provisions 

to be added to subpart Da need clarifications, are vague or contradictory, and impose requirements that the 

defense will be entirely useless as a practical matter. Some of the nine requirements that EPA proposed be met in 

order for a facility to claim an affirmative defense for a malfunction are unreasonable, difficult to demonstrate, 

and subject to varying interpretation. EPA should revise the affirmative defense provisions in the rule so that the 

requirements are meaningful to implement. The commenters provided specific recommended changes to the 

proposed rule language to address these issues. Another commenter (17975) states that EPA has not determined

whether some emission control technologies are prone to malfunctions, or explained why EGUs that rely on such 

equipment should be entitled to an affirmative defense when it breaks down. Requiring government agencies to 

evaluate and rebut affirmative defenses on a case by case basis is impractical and has proved ineffective.

Response: EPA is finalizing emission standards that apply at all times, including during periods of malfunction. 

For malfunctions, the EPA is finalizing the proposed affirmative defense language for exceedances of the 

numerical emission limits that are caused by malfunctions. As EPA explained in the preamble to the proposed 

rule, EPA recognizes that even equipment that is properly designed and maintained can fail and that such failure 

can cause an exceedance of the relevant emission standard. The EPA included an affirmative defense in the final 

rule in an attempt to balance a tension, inherent in many types of air regulation, to ensure adequate compliance 

while simultaneously recognizing that despite the most diligent of efforts, emission limits may be exceeded under 

circumstances beyond the control of the source. 

With respect to the Affirmative Defense and the comment that the provisions are vague or contradictory, the 

EPA’s view is that the affirmative defense is consistent with CAA section the EPA believes that courts are well 

equipped and often do evaluate and apply the type of criteria set forth is the affirmative defense. Many of the 

conditions were modeled after the conditions of the affirmative defense in EPA’s SIP SSM policy, which several 

states have adopted into their SIPs. (See, e.g., State Implementation Plans: Policy Regarding Excessive Emissions 

During Malfunctions, Startup, and Shutdown (Sept. 20, 1999); Policy on Excess Emissions During Startup, 

Shutdown, Maintenance, and Malfunctions (Feb. 15, 1983)). We do not have any indication that parties to 

enforcement proceedings have had any significant difficulties applying the terms of these SIP affirmative 

defenses. In addition, EPA’s view is that use of consistent terms in establishing affirmative defense regulations 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

24

and policies across various CAA programs will promote consistent implementation of those rules and policies. 

The affirmative defense does not require a facility to prove its innocence rather than requiring an enforcement 

authority to prove a violation of the CAA or change the burden of proof with respect to establishing a violation. 

The affirmative defense applies to penalties and thus is only utilized where a violation has been established. The 

burden of proof remains with the plaintiff in an enforcement action. See, e.g., 40 C.F.R. 22.24. If a violation has 

been established and a source wishes to assert the affirmative defense with respect to penalties, the source does 

bear the burden of establishing that the elements of the affirmative defense have been met. This burden-shifting is 

appropriate because the source is in a better position to determine the facts required to establish the defense. See, 

e.g., Arizona Pub. Serv. Co. v. EPA, 562 F.3d 1116, 1120, 1129-30 (10th Cir. 2009) (rejecting industry challenge 

to EPA’s use of an affirmative defense to address excess emissions during malfunction events.).

Comment: One commenter (4714) states that the proposed rules should be revised to enable EPA to allow state 

rules for affirmative defense that are EPA-approved as part of a state implementation plan (SIP) to be used in lieu 

of the federal procedures. This flexibility would eliminate duplicative or potentially even conflicting requirements 

for both state agencies and regulated entities.

Response: As a general matter, state SIP provisions do not apply in the context of an EPA promulgated NSPS. 

States can, and in fact are encouraged to, take delegation of the authority to implement and enforce the 

requirements of NSPS; however, in such circumstances, it is still the provisions of the NSPS that apply, not EPAapproved SIP provisions. EPA, therefore, concludes that inclusion of the Affirmative Defense in the NSPS is 

appropriate.

Comment: One commenter (4714) states that an initial notification should be required if an affected 

owner/operator wishes to claim an affirmative defense and the proposed rules should specify notification by 

telephone or facsimile. An electronic reporting mechanism should be allowed for this initial notification. 

However, telephone notifications should not be allowed because such notifications are difficult to verify and 

enforce. At a minimum, electronic notification that complies with EPA’s Cross-Media Electronic Reporting 

Regulation (CROMERR) standards could provide for quick and durable reporting that may be relied upon for 

investigative and enforcement purposes.

Response: The EPA accepts documents in electronic format, as long as the format is compatible with the 

requirements of the standards. For the affirmative defense provisions, the owner or operator of a facility 

experiencing an exceedance of its emission limit(s) during a malfunction must notify the Administrator by 

telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial 

occurrence of the malfunction, or if it is not possible to determine within two business days after the malfunction 

caused or contributed to an exceedance, no later than two business days after the owner or operator knew or 

should have known that the malfunction caused or contributed to an exceedance, but, in no event later than two 

business days after the end of the averaging period. The written reports required to demonstrate that the 

affirmative defense provisions have been met and requests for an extension of the deadline for these reports may 

also be submitted electronically. EPA has conlcuded that notification by telephone is appropriate since that 

notification must by followed by submission of a written report demonstrating that the affirmative defense 

provisions, including the notification requirement, have been met.

2.7.4 Subpart Da Mercury Provisions

Comment: Several commenters (4836, 5715) state that it is appropriate to remove the applicable mercury 

emissions standards provisions vacated by a federal court ruling from the NSPS under 40 CFR 60 subpart Da).

Response: The provisions have been removed. In addition, the amendments to subpart B that occurred as part of 

the Clean Air Mercury Rule have also been removed.

2.7.5 Removal of References to 30-Day Rolling Averages 

Comment: One commenter (4836) stated that EPA’s proposed removal of references to 30-day rolling averages 

in Subpart Da provisions establishing emission limitations and the addition of new provisions stating that 

compliance with emission limits in various sections “are determined on a 30-day rolling average basis” does not 
Response to Comments on Proposed NSPS Amendments to Subparts D and Da

25

appear to be intended to change the averaging time of any provision, but could cause confusion and should be 

better explained.

Response: The revisions are only intended to make the rules easier to read and are not intended to change any of 

the existing provisions.

2.7.6 Deletion of Obsolete Provision References in Rule 

Comment: One commenter (4698) supports EPA proposal to delete “emergency condition” requirements for the 

SO2 standard exemption, references to percent reductions for NOX and PM, references to the term “solvent refined 

coal,” and the existing commercial demonstration permit references.

Response: The provisions have been removed

2.7.7 Proposed Rule Language Corrections and Clarifications

Comment: One commenter (4698) states that in §60.48Da(k)(1)(i) the term “Osg” in Equation 2 should be defined 

as “Average hourly gross energy output from electric utility steam generating unit” to be consistent with the rule’s 

definitions. 

Response: A “steam generating unit” is a subset of an “electric utility steam generating” and EPA has concluded 

that the suggested change is not necessary.
Response to Comments on Proposed NSPS Amendments to Subparts Db and Dc

26

3. Response to Comments on Proposed NSPS Amendments to Subparts 

Db and Dc 

3.1 Definition of “Distillate Oil”

Comment: Several commenters (4698, 4770, 4841) support EPA’s proposal to expand the definition of 

“Distillate oil” in both 40 CFR 60 subparts Db and Dc to include biodiesel and kerosene because it is appropriate 

to have the same requirements for units burning biodiesel or kerosene as those units firing distillate fuel oil. One 

commenter (5749) requested that EPA explain why the definition for “distillate oil” in 40 CFR 60 subpart Db of 

the NSPS includes a limitation on the weight percent nitrogen, while the proposed definition for “distillate oil” in 

the EGU NESHAP does not.

Response: The definition of distillate oil has been amended as proposed. When the industrial boiler NSPS was 

originally promulgated, certain provisions in the NSPS assumed low fuel NOX formation and that requires low 

fuel nitrogen content. This is not necessary for purposes of the EGU NESHAP.

3.2 Exemption of Steam Generating Units Subject to Other NSPS

Comment: One commenter (4841) supports EPA’s proposal to i) exempt owners and operators of affected 

facilities subject to 40 CFR 60 subpart Eb (standards of performance for large municipal waste combustors 

(MWCs) and 40 CFR 60 subpart CCCC (standards of performance for commercial and industrial solid waste 

incineration) from 40 CFR part 60, subpart Da; ii) exempt owners/operators of affected facilities subject to 40 

CFR part 60, subpart BB (standards of performance for Kraft pulp mills) from the PM standards under subpart 

Db; and, iii) exempt owners/operators of fuel gas combustion devices subject to 40 CFR 60 subpart Ja (standards 

of performance for petroleum refineries) from the SO2 standard under 40 CFR 60 subpart Db.

Response: The exemptions are included in the final rule.

3.3 Applicability to Temporary Boilers

Comment: One commenter (4766) stated that EPA appears to suggest that separate NSPS requirements should 

apply to temporary boilers that are on-site for 30 days or less. However, temporary boilers, especially those 

brought on-site on skids or trucks for construction projects, are not stationary equipment and therefore do not fall 

under NSPS. In any event, even if such temporary sources could be considered “stationary,” 30 days is not 

enough time to implement the NSPS.

Response: Since temporary boilers are not self propelled they are considered stationary facilities and subject to 

the applicable NSPS. In recognition of the special considerations of temporary boilers the final rule exempts 

temporary boilers that burn natural gas and/or low sulfur distillate oil from the NSPS. The definition added to 40 

CFR 60 subparts Db and Dc is as follows:

Temporary boiler means any generating unit that combusts natural gas and/or distillate oil with a potential 

SO2 emissions rate of 26 ng/J (0.060 lb/MMBtu) or less, and that is designed to, and is capable of, being 

carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, 

dollies, trailers, or platforms. A steam generating unit is not a temporary boiler if any one of the following 

conditions exists:

(1) The equipment is attached to a foundation.

(2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. 

Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar 

function will be included in calculating the consecutive time period.

(3) The equipment is located at a seasonal facility and operates during the full annual operating period of

the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 

3 months each year.
Response to Comments on Proposed NSPS Amendments to Subparts Db and Dc

27

(4) The equipment is moved from one location to another in an attempt to circumvent the residence time 

requirements of this definition.

The requirement to limit fuel to inherently cleaner burning fuels minimizing emissions while providing flexibility 

to the regulated community.

3.4 Site-Specific Monitoring Plan

Comment: One commenter (4674) requests that EPA provide further guidance on the “written site-specific 

monitoring plan approved by the permitting authority,” under 40 CFR 60.47c(h). Specifically, commenter 

requests that EPA allow permitting authorities to authorize less stringent opacity or other monitoring requirements

than identified in the rule. For example, a permitting agency could require affected owners and operators to 

conduct opacity testing only upon using a fuel for operational reasons rather than for compliance demonstrations. 

Further, a permitting agency could specify that each periodically required Method 9 does not have to adhere to the 

40 CFR part 60 notification and reporting requirements associated with performance tests found in §60.8 and 

§60.11, but rather the affected owner or operator would be required to submit any deviations with the excess 

emissions report required under §60.48c(c).

Response: There are no specific requirements in § 60.47c(h). The permitting authority for the owner/operator of 

the affected steam generating unit determines appropriate “procedures and criteria for establishing and monitoring 

specific parameters for the affected facility indicative of compliance with the opacity standard on a site specific 

basis. The source specific requirements could be as described in the comment as long as the permitting authority 

has determined they are appropriate for a specific affected facility.

3.5 Opacity Monitoring 

Comment: One commenter (4674), a state air pollution control agency, recommends that EPA consider removing 

the requirement to complete subsequent Method 9 opacity performance tests after the initial performance test is 

completed, if the affected owner or operator is able to show in the initial reading that the opacity complies with 

the standard. It is the experience of the commenter that subsequent opacity readings for sources which have not 

exceeded the standard are onerous and may actually discourage good air pollution control practices. Alternately, 

the State suggests that EPA consider expanding the extension associated with proposed changes to 40 CFR 

60.47c(a)(1)(i). EPA proposed a change to allow affected owners and operators to extend the time frame to 

complete a Method 9 performance test from a minimum of every 12 months for sources where the initial 

performance test showed that there were no visible emissions. EPA proposes to allow those sources to either 

repeat the performance test every month or within 45 days of using a fuel with an opacity standard. Without the 

latter option, sources which primarily combust natural gas are often required to undergo a special startup using 

diesel fuel solely to satisfy the current compliance requirement to complete a Method 9 performance test every 12 

months. As proposed, those sources will now only be required to complete a Method 9 performance test within 45 

days of using diesel fuel, which will be dependent on the sources’ operational needs and not a compliance 

requirement. The State is in agreement with EPA’s proposed revision to 40 CFR 60.47c(a)(1)(i). However, this 

proposed extension is only available to facilities that have no visible emissions observed during the initial 60 

minute Method 9 performance test. Pursuant to 40 CFR 60.47c(a)(1)(ii-iv), sources which have any 6-minute 

opacity average greater than 0% must conduct another Method 9 performance test for compliance purposes in the 

near term (every 6 months, 3 months, or more frequently). It is the commenter’s experience that all boilers 

running on diesel experience some degree of opacity during operation, which typically subsides quickly. At least 

one 6-minute opacity average is likely to exceed 0%. For many of the State’s sources, the primary fuel used is 

natural gas, and diesel fuel is used only as a backup. Because these sources are likely to have at least one 6-minute 

opacity average greater than 0% while using diesel fuel, they are required to repeat the Method 9 performance test 

even if they have ceased using diesel fuel in the interim. Repeating this performance test requires the affected 

owner or operator to shut down the boiler and restart using diesel fuel, only to shut down once again to restart 

using natural gas. It is the State’s experience that, left to the operational needs of the source, a boiler may only 

utilize diesel fuel once every few years as opposed to the compliance requirement to use diesel fuel every few 

months. It appears that the 45-day allowance, while intending to limit unnecessary opacity monitoring for sources 

with no visible emissions, was not extended to sources which may have some visible emissions during operation. 
Response to Comments on Proposed NSPS Amendments to Subparts Db and Dc

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Therefore, such sources are required to regularly shutdown their equipment and restart on diesel just to complete 

the necessary opacity readings. The State suggests that either EPA extend the 45-day allowance to 40 CFR 

60.47c(a)(1)(ii-iv), or that a permitting agency may authorize an alternative opacity monitoring schedule by 

means of the site-specific monitoring plan as discussed §60.47c(h).

Response: Under subpart Dc §60.47c(h), state permitting authorities have the ability to develop an alternate 

opacity monitoring plan to alleviate the above concerns. To minimize burden, the 45 day testing allowance has 

been added to all subparts.